(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations

Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas and oil exploration, development and production (“E&P”). The Company’s current operations are principally focused within the United States on the development of unconventional reservoirs located in Pennsylvania, West Virginia and Arkansas.

The Company’s operations in northeast Pennsylvania are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”), its operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs (herein referred to as “Southwest Appalachia”) and its operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. Collectively, the Company’s properties located in Pennsylvania and West Virginia are herein referred to as the “Appalachian Basin.” The Company also actively seeks to find and develop new natural gas and oil plays with significant exploration and exploitation potential, which it refers to as “New Ventures,” and has exploration and production activities ongoing in Colorado and Louisiana, along with other areas in which it is currently exploring for new development opportunities. The Company also has drilling rigs in Pennsylvania, West Virginia and Arkansas, as well as in other operating areas, and provides oilfield products and services, principally serving its exploration and production operations. Southwestern’s natural gas gathering and marketing (“Midstream Services”) activities primarily support the Company’s E&P activities in Arkansas, Pennsylvania, Louisiana and West Virginia.

Basis of Presentation

The consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued. Certain reclassifications have been made to the prior year financial statements to conform to the 2015 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements.

Principles of Consolidation

The consolidated financial statements include the accounts of Southwestern and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.

In 2015, the Company purchased an 86% ownership in a limited partnership which owns and operates a gathering system in Northeast Appalachia as part of the WPX Property Acquisition (discussed in Note 2). Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the year ended December 31, 2015 was insignificant.

Revenue Recognition

Natural gas and liquid sales. Natural gas and liquid sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The Company had no significant production imbalances at December 31, 2015 or 2014.

Marketing. The Company generally markets its natural gas and liquids, as well as some products produced by third parties, to brokers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Gas gathering. In certain areas, the Company gathers its natural gas as well as some natural gas produced by third parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.

Cash and Cash Equivalents

Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. Management considers cash and cash equivalents to have minimal credit and market risk.

Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $29 million and $17 million as of December 31, 2015 and 2014, respectively.

Inventory

Inventory is comprised of tubulars and other equipment and natural gas in underground storage. Tubulars and other equipment are carried at the lower of cost or market and are accounted for by a moving weighted average cost method that is applied within specific classes of inventory items. In the fourth quarter of 2015, the Company wrote-down the carrying value of its inventory by $23 million as a result of reduced drilling activity. Natural gas in underground storage is carried at the lower of cost or market and accounted for by a weighted average cost method. During the fourth quarter of 2015, the Company completed the sale of its underground storage facility in Franklin County, Arkansas.

The components of inventory as of December 31, 2015 and December 31, 2014 consisted of the following:


	For years ended December 31,
	2015		2014
	(in millions)
Inventory:
Tubulars and other equipment	$	3	$	33
Natural gas in underground storage		–		4

Property, Depreciation, Depletion and Amortization

Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas, oil and NGL reserves. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country by country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method must use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling value of their reserves.

Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.59 per MMBtu, West Texas Intermediate oil of $46.79 per barrel, and NGLs of $6.82 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $1,586 million (net of tax) at December 31, 2015 and resulted in a non-cash ceiling test impairment. No cash flow hedges were in place as of December 31, 2015. In the second and third quarters of 2015, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015, respectively, and resulted in non-cash ceiling test impairments. Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $60 million and $40 million as of June 30, 2015 and September 30, 2015, respectively. At December 31, 2014, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu, West Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 per barrel. At December 31, 2013, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.67 per MMBtu, for West Texas Intermediate oil of $93.42 and NGLs of $43.45 per barrel. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.

Gathering Systems. The Company’s investment in gathering systems is primarily related to its Fayetteville Shale assets in Arkansas. These assets are being depreciated on a straight-line basis over 25 years.

Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and actively being evaluated.

Asset Retirement Obligations. The Company owns natural gas and oil properties, which require expenditures to plug and abandon the wells and reclaim the associated pads when reserves in the wells are depleted. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Impairment of long-lived assets. The carrying value of long-lived assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.

Intangible assets. The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their weighted average useful life.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations. Additional information regarding uncertain tax positions can be found in Note 10 – Income Taxes.

Derivative Financial Instruments

The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses commodity fixed price swaps and fixed price option contracts to hedge sales of natural gas. Gains and losses resulting from the settlement of hedge contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivatives if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item. In contrast, gains and losses from the ineffective portion of fixed price swaps designated for hedge accounting treatment are recognized currently and have an inconsequential impact in the consolidated statement of operations. Gains and losses from the unsettled portion of fixed price swaps not designated for hedge accounting treatment, interest rate swaps, fixed price call options and basis swaps that were not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 5 – Derivatives and Risk Management and Note 7 – Fair Value Measurements for a discussion of the Company’s hedging activities.

Earnings Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock and performance units and the assumed conversion of mandatory convertible preferred stock. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.

In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). The common stock offering was priced at $23.00 per share. Net proceeds, after underwriting discount and expenses, from the common stock offering were approximately $669 million. Net proceeds, after underwriting discount and expenses, from the depositary share offering were approximately $1.7 billion. Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public offering of $2.2 billion in long-term senior notes.

The mandatory convertible preferred stock entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (and, correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date.

The mandatory convertible preferred stock has the non-forfeitable right to participate on an as converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. Accordingly, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

The following table presents the computation of earnings per share for the years ended December 31, 2015, 2014 and 2013.


	For the years ended
	December 31,
	2015		2014		2013
	(in millions, except share/per share amounts)
Net income (loss)	$	(4,556)	$	924	$	704
Mandatory convertible preferred stock dividend		106		–		–
Net income (loss) attributable to common stock	$	(4,662)	$	924	$	704

Number of common shares:
Weighted average outstanding		380,521,039		351,446,747		350,465,430
Issued upon assumed exercise of outstanding stock options (1)		–		241,603		377,626
Effect of issuance of non-vested restricted common stock (2)		–		448,415		258,396
Effect of issuance of non-vested performance units (3)		–		273,918		–
Effect of issuance of mandatory convertible preferred stock (4)		–		–		–
Weighted average and potential dilutive outstanding		380,521,039		352,410,683		351,101,452

Earnings (loss) per common share:
Basic	$	(12.25)	$	2.63	$	2.01
Diluted	$	(12.25)	$	2.62	$	2.00

(1)

Due to the net loss for the year ended December 31, 2015, the unvested stock options were not recognized in diluted earnings per share calculations as they would be antidilutive. Options for 3,835,234 shares, 1,446,004 shares and 1,634,695 shares were excluded from the calculation of diluted shares for the years ended December 31, 2015, 2014 and 2013, respectively, because they would have had an antidilutive effect.

(2)

Due to the net loss for the year ended December 31, 2015, the unvested share-based payments were not recognized in diluted earnings per share calculations as they would be antidilutive. The calculation excluded 1,990,383 shares, 29,879 shares and 114,433 shares of restricted stock for the years ended December 31, 2015, 2014, and 2013, respectively, because they would have had an antidilutive effect.

(3)

Due to the net loss for the year ended December 31, 2015, 140,414 shares of performance units were excluded in the calculation of diluted earnings per share as they would be antidilutive. There were no performance units issued in 2013.

(4)

Due to the net loss for the year ended December 31, 2015, the weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock were not recognized in diluted earnings per share calculations as they would be antidilutive. The calculation excluded 70,890,312 weighted average common shares issuable upon the assumed conversion of the mandatory convertible preferred stock because they would have had an antidilutive effect. There were no mandatory convertible preferred shares in 2014 or 2013.

Supplemental Disclosures of Cash Flow Information

The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2015, 2014, and 2013.


	For the years ended December 31,
	2015		2014		2013
	(in millions)
Cash paid during the year for interest, net of amounts capitalized	$	6	$	50	$	36
Cash paid (received) during the year for income taxes		(6)		28		19
Increase (decrease) in noncash property additions		(10)		174		(13)

Stock-Based Compensation

The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.

Treasury Stock

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liabilities of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust and are presented as treasury stock and carried at cost. As of December 31, 2015, 47,149 shares were accounted for as treasury stock, compared to 11,055 shares at December 31, 2014.

Foreign Currency Translation

The Company has designated the Canadian dollar as the functional currency for our operations in Canada. The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders' equity.

New Accounting Standards Implemented in this Report

In November 2015, the FASB issued Accounting Standards Update No. 2015-17, Balance Sheet Classification of Deferred Taxes (Topic 740) (“Update 2015-17”), which seeks to reduce the complexity in financial reporting. The amendments in Update 2015-17 require that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as non-current on the balance sheet. Although the amendments in Update 2015-17 are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, the Company has elected to early adopt the amendments of Update 2015-17 on a prospective basis for the current period. The implementation did not have a material impact on the Company’s consolidated statement of operations, balance sheet or statement of cash flows. The net deferred tax liability at December 31, 2014 was comprised of net long-term deferred income tax liabilities of $1,951 million, in addition to a net current deferred income tax liability of $109 million.

New Accounting Standards Not Yet Implemented in this Report

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. Topic 606 Revenue from Contracts with Customers will supersede the revenue recognition requirement as in Topic 605 Revenue Recognition. Update 2014-09 requires an entity to recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to those goods or services. Entities may apply the amendments in Update 2014-09 either (a) retrospectively to each reporting period presented, and the entity may elect a practical expedient per the update, or (b) retrospectively with the cumulative effect of initially applying Update 2014-09 recognized at the date of initial application – if an entity elects this transition method it also should provide the additional disclosures in reporting periods. In August 2015, the FASB issued Accounting Standards Update Accounting Standards Update (ASU) No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, which finalizes Proposed ASU No. 2015-240 of the same name, and responds to stakeholders’ requests to defer the effective date of the guidance in ASU No. 2014-09. For public entities, Update 2014-09 and Update 2015-14 are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-09 and 2015-14 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In November 2014, the FASB issued Accounting Standards Update No. 2014-16, Derivatives and Hedging – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (Subtopic 815-15) (“Update 2014-16”), addresses diversity in practice related to the determination of whether derivative features embedded in hybrid instruments issued in the form of a share should be bifurcated and accounted for separately. For public entities, Update 2014-16 is effective for annual reporting periods beginning after December 15, 2015 including interim periods within that reporting period. The Company is currently evaluating the provisions of Update 2014-16 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-03”), which seeks to simplify presentation of debt issuance costs. Update 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. Entities should apply the amendments in Update 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. For public entities, Update 2015-03 and Update 2015-15 are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company has evaluated the provisions of Update 2015-03 and Update 2015-15 and expects the impact to be immaterial on its consolidated results of operations, financial position and cash flows.

In May 2015, the FASB issued Accounting Standards Update No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent) (“Update 2015-07”), which amends ASC 820, Fair Value Measurement. The standard removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure requirements. The amendments in Update 2015-07 are effective for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-07 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In July 2015, the FASB issued Accounting Standards Update No. 2015-11, Inventory (Topic 330) (“Update 2015-11”), which seeks to simplify the measurement of inventory. Update 2015-11 requires that an entity should measure inventory at the lower of cost and net realizable value, where net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public entities, the amendments in Update 2015-11 are effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-11 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

In July 2015, the FASB issued Accounting Standards Update (ASU) No. 2015-12 (“Update 2015-12”), which consists of three related parts: (1) Plan Accounting: Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Fully Benefit-Responsive Investment Contracts (“Part I”); (2) Plan Accounting: Defined Benefit Pension Plans (Topic 960); Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Plan Investment Disclosures (“Part II”); and (3) Plan Accounting: Defined Benefit Pension Plans (Topic 960); Defined Contribution Pension Plans (Topic 962); Health and Welfare Benefit Plans (Topic 965): Measurement Date Practical Expedient (“Part III”). Part I requires (1) fully benefit-responsive investment contracts to be measured at contract value; and (2) an adjustment to reconcile contract value to fair value, when these measures differ, on the face of the plan financial statements. Part II eliminates the current requirement for both participant-directed investments and non-participant-directed investments to disclose individual investments representing 5% or more of net assets available for benefits, as well as the net appreciation or depreciation for investments by general type on a disaggregated basis. Part III permits plans to measure investments and investment-related accounts as of a month-end date that is closest to the plan’s fiscal year-end, when the fiscal period does not coincide with a month-end. The amendments in Update 2015-12 are effective for fiscal years beginning after December 15, 2015, with early adoption permitted. The Company is currently evaluating the provisions of Update 2015-12 and assessing the impact, if any, it may have on its consolidated results of operations, financial position, or cash flows.

In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Business Combinations (Topic 805) (“Update 2015-16”), which seeks to reduce the complexity of amounts recognized in a business combination. The amendments in Update 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in Update 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in Update 2015-16 require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in Update 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Company is currently evaluating the provisions of Update 2015-16 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.