Note 1 – Summary of Significant Accounting Policies

Description of Operations

SM Energy Company is an independent energy company engaged in the acquisition, exploration, development, and production of crude oil and condensate, natural gas, and NGLs in onshore North America.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and have been prepared in accordance with GAAP and the instructions to Form 10-K and Regulation S-X. Subsidiaries that the Company does not control are accounted for using the equity or cost methods as appropriate. Equity method investments are included in other noncurrent assets in the accompanying consolidated balance sheets (“accompanying balance sheets”). Intercompany accounts and transactions have been eliminated. In connection with the preparation of the consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of December 31, 2015, through the filing date of this report.

Certain prior period amounts have been reclassified to conform to the current period presentation on the accompanying financial statements. Please refer to the caption Recently Issued Accounting Standards below for additional discussion of the change in presentation of debt issuance costs on the accompanying balance sheets.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of proved oil and gas reserves, assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of proved oil and gas reserve quantities provide the basis for the calculation of depletion, depreciation, and amortization expense, impairment of proved properties, and asset retirement obligations, each of which represents a significant component of the accompanying consolidated financial statements.

Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Accounts Receivable

The Company’s accounts receivable consist mainly of receivables from oil, gas, and NGL purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s oil and gas receivables are collected within two months and the Company has had minimal bad debts.

Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized. The Company’s allowance for doubtful accounts as of December 31, 2015, totaled $1.1 million, primarily for receivables from joint interest owners. The Company had no allowance for doubtful accounts as of December 31, 2014.

Concentration of Credit Risk and Major Customers

The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to regular review. The Company does not believe the loss of any single purchaser would materially impact its operating results, as crude oil, natural gas, and NGLs are products with well-established markets and numerous purchasers in the Company’s operating regions. During 2015 and 2014, the Company had one major customer, which represented approximately 21 percent and 19 percent, respectively, of total production revenue, which is discussed in the next paragraph. During 2015 and 2014, the Company also sold to four entities that are under common ownership. In aggregate, these four entities represented approximately 10 percent and 14 percent of total production revenue in 2015 and 2014, respectively; however, none of these entities individually represented more than 10 percent of total production revenue. Additionally, in 2015 the Company sold to three entities that are under common ownership, which in aggregate represented 11 percent of its total production revenue; however, none of these entities individually represented more than 10 percent of the Company’s total production revenue. During 2013, the Company had three major customers, which represented approximately 26 percent, 16 percent, and 12 percent, respectively, of total production revenue.

During the third quarter of 2013, the Company entered into various marketing agreements with a joint venture partner, whereby the Company is subject to certain gathering, transportation, and processing throughput commitments for up to 10 years pursuant to each contract. While the Company’s joint venture partner is the first purchaser under these contracts, representing 21 percent and 19 percent of total production revenue in 2015 and 2014, respectively, the Company also shares with them the risk of non-performance by their counterparty purchasers. Several of the Company’s joint venture partner’s counterparty purchasers under these contracts are also direct purchasers of products produced by the Company from other operated areas.

The Company’s policy is to use the commodity affiliates of the lenders under its credit facility as its derivative counterparties, and each counterparty must have investment grade senior unsecured debt ratings. Each of the Company’s 10 counterparties meet both of these requirements as of the filing date of this report.

The Company has accounts in the following locations with a national bank: Denver, Colorado; Houston, Texas; Midland, Texas; and Billings, Montana. The Company’s policy is to invest in highly-rated instruments and to limit the amount of credit exposure at each individual institution.

Oil and Gas Producing Activities

The Company accounts for its oil and gas exploration and development costs using the successful efforts method. G&G costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures within the accompanying statements of cash flows. The costs of development wells are capitalized whether those wells are successful or unsuccessful.

DD&A of capitalized costs related to proved oil and gas properties is calculated on a pool-by-pool basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. As of December 31, 2015, and 2014, the estimated salvage value of the Company’s equipment was $29.7 million and $50.8 million, respectively.

Assets Held for Sale

Any properties held for sale as of the balance sheet date have been classified as assets held for sale and are separately presented on the accompanying balance sheets at the lower of carrying value or fair value less the cost to sell. For additional discussion on assets held for sale, please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions.

Other Property and Equipment

Other property and equipment such as facilities, office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is calculated using either the straight-line method over the estimated useful lives of the assets, which range from three to 30 years, or the unit of output method where appropriate. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Internal Use Software Development Costs

The Company capitalizes certain software costs incurred during the application development stage. The application development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2015, and 2014, the Company has capitalized approximately $44.0 million and $35.0 million, respectively, related to the development and implementation of accounting and operational software.

Derivative Financial Instruments

The Company seeks to manage or reduce commodity price risk on its production by entering into derivative contracts. The Company seeks to minimize its basis risk and indexes its oil derivative contracts to NYMEX prices, its NGL derivative contracts to OPIS prices, and its gas derivative contracts to various regional index prices associated with pipelines into which the Company’s gas production is sold. For additional discussion on derivatives, please see Note 10 – Derivative Financial Instruments.

Net Profits Plan

The Company records the estimated fair value of expected future payments to be made under the Net Profits Plan as a noncurrent liability in the accompanying balance sheets. The underlying assumptions used in the calculation of the estimated liability include estimates of production, proved reserves, recurring and workover lease operating expense, transportation, production and ad valorem tax rates, present value discount factors, pricing assumptions, and overall market conditions. The estimates used in calculating the long-term liability are adjusted from period-to-period based on the most current information attributable to the underlying assumptions. Changes in the estimated liability of future payments associated with the Net Profits Plan are recorded as increases or decreases to expense in the current period as a separate line item in the accompanying statements of operations, as these changes are considered changes in estimates.

The distribution amounts due to participants and payable in each period under the Net Profits Plan as cash compensation related to periodic operations are recognized as compensation expense and are included within general and administrative expense and exploration expense in the accompanying statements of operations. The corresponding current liability is included in accounts payable and accrued expenses in the accompanying balance sheets. This treatment provides for a consistent matching of cash expense with net cash flows from the oil and gas properties in each respective pool of the Net Profits Plan. For additional discussion, please refer to the heading Net Profits Plan in Note 7 – Compensation Plans and Note 11 – Fair Value Measurements.

Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is drilled or acquired. The increase in carrying value is included in proved oil and gas properties in the accompanying balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties. For additional discussion, please refer to Note 9 – Asset Retirement Obligations.

Revenue Recognition

The Company derives revenue primarily from the sale of produced oil, gas, and NGLs. Revenue is recognized when the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses knowledge of its properties and historical performance, contractual agreements, NYMEX, OPIS, and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates. The Company uses the sales method of accounting for gas revenue whereby sales revenue is recognized on all gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property.

Impairment of Proved and Unproved Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value, which is based on expected future discounted cash flows, when there is an indication that the carrying costs may not be recoverable. Expected future cash flows are calculated on all proved reserves and risk adjusted probable and possible reserves using a discount rate and price forecasts that management believes are representative of current market conditions. The prices for oil and gas are forecasted based on NYMEX strip pricing, adjusted for basis differentials, for the first five years, after which a flat terminal price is used for each commodity stream. The prices for NGLs are forecasted using OPIS pricing, adjusted for basis differentials, for as long as the market is actively trading, after which a flat terminal price is used. Future operating costs are also adjusted as deemed appropriate for these estimates. An impairment is recorded on unproved property when the Company determines that either the property will not be developed or the carrying value is not realizable.

The Company recorded $468.7 million, $84.5 million, and $172.6 million, of proved property impairment expense for the years ended December 31, 2015, 2014, and 2013, respectively. The impairments of proved properties in 2015 were due to continued commodity price declines, largely impacting the Company’s Powder River Basin program and certain legacy and non-core assets in the Rocky Mountain region, as well as the Company’s decision to reduce capital invested in the development of its east Texas exploration program in its South Texas & Gulf Coast region. The impairments of proved properties in 2014 were primarily a result of the significant decline in commodity prices in late 2014 and recognition of the outcomes of exploration and delineation wells in certain prospects in the Company’s South Texas & Gulf Coast and Permian regions. The impairments in 2013 primarily resulted from the write-down of certain Mississippian limestone assets in the Company’s Permian region due to negative engineering revisions, write-downs related to Olmos interval, dry gas assets in the South Texas & Gulf Coast region as a result of a plugging and abandonment program, and write-downs of certain underperforming assets due to the Company’s decision to no longer pursue the development of those assets.

For the years ended December 31, 2015, 2014, and 2013, the Company recorded expense related to the abandonment and impairment of unproved properties of $78.6 million, $75.6 million, and $46.1 million, respectively. The Company’s abandonment and impairment of unproved properties expense in 2015 and 2014 was primarily a result of lease expirations and acreage the Company no longer intended to develop in light of changes in drilling plans in response to the continued decline in commodity prices. The Company’s abandonment and impairment of unproved properties expense in 2013 was mostly related to acreage the Company no longer intended to develop in its Permian region.

Impairment of Other Property and Equipment

A long-lived asset is evaluated for potential impairment whenever events or changes in circumstances indicate that its carrying value may be greater than its undiscounted future net cash flows. Impairment, if any, is measured as the excess of an asset’s carrying value over its estimated fair value. The Company uses an income valuation technique if there is not a market-observable price for the asset.

For the year ended December 31, 2015, the Company recorded a $49.4 million impairment charge on its gas gathering system assets in east Texas, in conjunction with the impairment of the associated proved and unproved properties, resulting from the Company’s decision to reduce capital spent in the program in light of sustained, low commodity prices. The Company did not have any impairments of other property and equipment for the years ended December 31, 2014, or 2013.

Sales of Proved and Unproved Properties

The partial sale of proved property within an existing field is accounted for as normal retirement and no net gain or loss on divestiture activity is recognized as long as the treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties.

The partial sale of unproved property is accounted for as a recovery of cost when substantial uncertainty exists as to the ultimate recovery of the cost applicable to the interest retained. A net gain on divestiture activity is recognized to the extent that the sales price exceeds the carrying amount of the unproved property. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of unproved property. For additional discussion, please refer to Note 3 – Divestitures, Assets Held for Sale, and Acquisitions.

Stock-Based Compensation

At December 31, 2015, the Company had stock-based employee compensation plans that included RSUs, PSUs, and restricted stock awards issued to employees and non-employee directors, as more fully described in Note 7 - Compensation Plans. The Company records expense associated with the fair value of stock-based compensation in accordance with authoritative accounting guidance, which is based on the estimated fair value of these awards determined at the time of grant, and included within general and administrative expense and exploration expense in the accompanying statements of operations.

Income Taxes

The Company accounts for deferred income taxes whereby deferred tax assets and liabilities are recognized based on the tax effects of temporary differences between the carrying amounts on the financial statements and the tax basis of assets and liabilities, as measured using current enacted tax rates. These differences will result in taxable income or deductions in future years when the reported amounts of the assets or liabilities are recorded or settled, respectively. The Company records deferred tax assets and associated valuation allowances, when appropriate, to reflect amounts more likely than not to be realized based upon Company analysis.

Earnings per Share

Basic net income (loss) per common share is calculated by dividing net income or loss available to common stockholders by the basic weighted-average common shares outstanding for the respective period. The earnings per share calculations reflect the impact of any repurchases of shares of common stock made by the Company.

Diluted net income (loss) per common share is calculated by dividing adjusted net income or loss by the diluted weighted-average common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for this calculation consist of unvested RSUs, contingent PSUs, and in-the-money outstanding stock options. When there is a loss from continuing operations, as was the case for the year ended December 31, 2015, all potentially dilutive shares are anti-dilutive and are consequently excluded from the calculation of diluted earnings per share.

PSUs represent the right to receive, upon settlement of the PSUs after the completion of the three-year performance period, a number of shares of the Company’s common stock that may range from zero to two times the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. For additional discussion on PSUs, please refer to Note 7 – Compensation Plans under the heading Performance Share Units Under the Equity Plan.

The treasury stock method is used to measure the dilutive impact of unvested RSUs, contingent PSUs, and in-the-money stock options. All remaining stock options were exercised during the year ended December 31, 2014.

The following table details the weighted-average dilutive and anti-dilutive securities related to RSUs, PSUs, and stock options for the years presented:



	For the Years Ended December 31,
	2015	2014	2013
	(in thousands)
Dilutive	—	814	1,383
Anti-dilutive	256	—	—

The following table sets forth the calculations of basic and diluted earnings per share:



	For the Years Ended December 31,
	2015			2014		2013
	(in thousands, except per share amounts)
Net income (loss)	$	(447,710	)	$	666,051	$	170,935
Basic weighted-average common shares outstanding	67,723			67,230		66,615
Add: dilutive effect of stock options, unvested RSUs, and contingent PSUs ⁽¹⁾	—			814		1,383
Diluted weighted-average common shares outstanding	67,723			68,044		67,998
Basic net income (loss) per common share	$	(6.61	)	$	9.91	$	2.57
Diluted net income (loss) per common share	$	(6.61	)	$	9.79	$	2.51

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(1)	For the year ended December 31, 2015, the shares were anti-dilutive and excluded from the calculation of diluted earnings per share.

Comprehensive Income (Loss)

Comprehensive income (loss) is used to refer to net income (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under GAAP are reported as separate components of stockholders’ equity instead of net income (loss). Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of comprehensive income (loss).

The changes in the balances of components comprising other comprehensive income (loss) are presented in the following table:



	Derivative Adjustments ⁽¹⁾			Pension Liability Adjustments
	(in thousands)
For the year ended December 31, 2013
Net actuarial gain				$	2,766
Reclassification to earnings	$	1,777		1,239
Tax expense	(662		)	(1,522		)
Income, net of tax	$	1,115		$	2,483
For the year ended December 31, 2014
Net actuarial loss				$	(10,062	)
Reclassification to earnings	$	—		706
Tax benefit	—			3,460
Loss, net of tax	$	—		$	(5,896	)
For the year ended December 31, 2015
Net actuarial loss				$	(4,990	)
Reclassification to earnings	$	—		1,853
Tax benefit	—			1,047
Loss, net of tax	$	—		$	(2,090	)

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⁽¹⁾	As of December 31, 2013, all commodity derivative contracts that had been previously designated as cash flow hedges had settled and had been reclassified into earnings from AOCL.

Fair Value of Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company had $202.0 million of outstanding loans under its credit facility as of December 31, 2015. The Company had $166.0 million of outstanding loans under its credit facility as of December 31, 2014. The Company’s Senior Notes are recorded at cost, net of unamortized deferred financing costs, and the respective fair values are disclosed in Note 11 - Fair Value Measurements. The Company has derivative financial instruments that are recorded at fair value. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.

Industry Segment and Geographic Information

The Company operates in the exploration and production segment of the oil and gas industry within the United States. The Company reports as a single industry segment. The Company sold its Mid-Continent assets in 2015, and therefore, no longer has marketed gas volumes as of December 31, 2015. Prior to the sale of these assets, the Company’s gas marketing function provided mostly internal services and acted as the first purchaser of natural gas and natural gas liquids produced by the Company in certain cases. The Company considered its marketing function as ancillary to its oil and gas producing activities. The amount of income these operations generated from marketing gas produced by third parties was not material to the Company’s results of operations, and segmentation of such activity would not have provided a better understanding of the Company’s performance. However, gross revenue and expense related to marketing activities for gas produced by third parties is presented in the marketed gas system revenue and marketed gas system expense line items in the accompanying statements of operations.

Off-Balance Sheet Arrangements

The Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPE”), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

The Company evaluates its transactions to determine if any variable interest entities exist. If it is determined that SM Energy is the primary beneficiary of a variable interest entity, that entity is consolidated into SM Energy. The Company has not been involved in any unconsolidated SPE transactions in 2015 or 2014.

Recently Issued Accounting Standards

In May 2014, the FASB issued new authoritative accounting guidance related to the recognition of revenue

from contracts with customers. This guidance is to be applied using a full retrospective method or a modified

retrospective method, as outlined in the guidance. In August 2015, the FASB deferred the effective date of the new revenue recognition standard by one year. The revenue recognition standard is now effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. Early adoption is permitted but only for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In August 2014, the FASB issued new authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures but does not believe it will impact the Company’s financial statements or disclosures.

Effective January 1, 2015, the Company adopted, on a prospective basis, Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2015-01, “Income Statement – Extraordinary and Unusual Items.” This ASU simplifies income statement presentation by eliminating the concept of extraordinary items. There was no impact to the Company’s financial statements or disclosures from the adoption of this standard.

In February 2015, the FASB issued new authoritative accounting guidance meant to clarify the consolidation reporting guidance in GAAP. This guidance is to be applied using a full retrospective method or a modified retrospective method, as outlined in the guidance, and is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

Effective November 1, 2015, the Company early adopted, on a retrospective basis, FASB ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs” (“ASU 2015-03”). ASU 2015-03 requires deferred financing costs to be presented on the accompanying balance sheets as a direct deduction from the carrying value of the related debt liability. In accordance, the Company has reclassified $33.6 million of deferred financing costs related to its Senior Notes at December 31, 2014, from the other noncurrent assets line item to the Senior Notes, net of unamortized deferred financing costs line item. The December 31, 2014, accompanying balance sheet line items that were adjusted as a result of the adoption of ASU 2015-03 are presented in the following table:



	As of
	December 31, 2014
	As Reported		As Adjusted
	(in thousands)
Other noncurrent assets	$	78,214	$	44,659
Total other noncurrent assets	$	267,754	$	234,199
Total Assets	$	6,516,700	$	6,483,145
Senior Notes	$	2,200,000	N/A
Senior Notes, net of unamortized deferred financing costs	N/A		$	2,166,445
Total noncurrent liabilities	$	3,445,385	$	3,411,830
Total Liabilities and Stockholders’ Equity	$	6,516,700	$	6,483,145

ASU 2015-03 does not specifically address the accounting for deferred financing costs related to line-of-credit arrangements. In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” (“ASU 2015-15”) allowing for deferred financing costs associated with line-of-credit arrangements to continue to be presented as assets. ASU 2015-15 is consistent with how the Company currently accounts for deferred financing costs related to the Company’s revolving credit facility.

Effective December 1, 2015, the Company early adopted, on a prospective basis, FASB ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” (“ASU 2015-17”). ASU 2015-17 requires that deferred tax liabilities and assets, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments in ASU 2015-17. As ASU 2015-17 was adopted on a prospective basis, the Company did not retrospectively adjust prior periods.

There are no other accounting standards applicable to the Company that would have a material effect on the Company’s financial statements and disclosures that have been issued but not yet adopted by the Company as of December 31, 2015, and through the filing date of this report.