rrc-10q_20170331.htm

Former Name, Former Address and Former Fiscal Year, if changed since last report: Not applicable

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files).

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Unless the context otherwise indicates, all references in this report to “Range Resources,” “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its directly and indirectly owned subsidiaries.

	March 31,			December 31,
	2017			2016
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	545		$	314
Accounts receivable, less allowance for doubtful accounts of $5,558 and $5,559		246,392			241,718
Derivative assets		30,454			13,278
Inventory and other		20,146			26,573
Total current assets		297,537			281,883
Derivative assets		15,791			205
Goodwill		1,654,292			1,654,292
Natural gas and oil properties, successful efforts method		12,551,347			12,386,153
Accumulated depletion and depreciation		(3,191,483	)		(3,129,816	)
		9,359,864			9,256,337
Other property and equipment		114,402			112,796
Accumulated depreciation and amortization		(97,653	)		(95,923	)
		16,749			16,873
Other assets		77,512			72,655
Total assets	$	11,421,745		$	11,282,245

Liabilities
Current liabilities:
Accounts payable	$	299,839		$	229,190
Asset retirement obligations		7,271			7,271
Accrued liabilities		231,568			265,843
Accrued interest		36,689			35,340
Derivative liabilities		55,713			165,009
Total current liabilities		631,080			702,653
Bank debt		841,188			876,428
Senior notes		2,849,088			2,848,591
Senior subordinated notes		48,519			48,498
Deferred tax liabilities		1,055,737			943,343
Derivative liabilities		1,515			24,491
Deferred compensation liabilities		110,455			119,231
Asset retirement obligations and other liabilities		301,687			310,642
Total liabilities		5,839,269			5,873,877
Commitments and contingencies

Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 247,563,324 issued at March 31, 2017 and 247,174,903 issued at December 31, 2016		2,476			2,471
Common stock held in treasury, 26,547 shares at March 31, 2017 and 30,547 shares at December 31, 2016		(1,054	)		(1,209	)
Additional paid-in capital		5,533,211			5,524,423
Retained earnings (deficit)		47,843			(117,317	)
Total stockholders’ equity		5,582,476			5,408,368
Total liabilities and stockholders’ equity	$	11,421,745		$	11,282,245

	Three Months Ended March 31,
	2017			2016

Revenues and other income:
Natural gas, NGLs and oil sales	$	559,450		$	209,487
Derivative fair value income		165,557			86,908
Brokered natural gas, marketing and other		51,648			35,018
Total revenues and other income		776,655			331,413
Costs and expenses:
Direct operating		28,023			24,054
Transportation, gathering, processing and compression		177,648			125,263
Production and ad valorem taxes		9,163			5,887
Brokered natural gas and marketing		53,550			36,558
Exploration		8,504			4,913
Abandonment and impairment of unproved properties		4,420			10,628
General and administrative		47,496			40,657
Termination costs		4,192			162
Deferred compensation plan		(13,169	)		16,056
Interest		47,101			37,739
Depletion, depreciation and amortization		149,821			120,561
Impairment of proved properties and other assets		—			43,040
(Gain) loss on the sale of assets		(22,600	)		1,643
Total costs and expenses		494,149			467,161
Income (loss) before income taxes		282,506			(135,748	)
Income tax expense (benefit):
Current		—			—
Deferred		112,395			(41,976	)
		112,395			(41,976	)
Net income (loss)	$	170,111		$	(93,772	)
Net income (loss) per common share:
Basic	$	0.69		$	(0.56	)
Diluted	$	0.69		$	(0.56	)
Dividends paid per common share	$	0.02		$	0.02
Weighted average common shares outstanding:
Basic		244,652			166,803
Diluted		244,803			166,803

	Three Months Ended March 31,
	2017			2016

Operating activities:
Net income (loss)	$	170,111		$	(93,772	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
Deferred income tax expense (benefit)		112,395			(41,976	)
Depletion, depreciation and amortization and impairment		149,821			163,601
Abandonment and impairment of unproved properties		4,420			10,628
Derivative fair value income		(165,557	)		(86,908	)
Cash settlements on derivative financial instruments		(4,181	)		109,466
Allowance for bad debt		—			200
Amortization of deferred financing costs, loss on extinguishment of debt and other		1,310			1,707
Deferred and stock-based compensation		962			29,128
(Gain) loss on the sale of assets		(22,600	)		1,643
Changes in working capital:
Accounts receivable		(4,690	)		18,752
Inventory and other		2,868			5,333
Accounts payable		24,384			11,922
Accrued liabilities and other		(43,381	)		(38,939	)
Net cash provided from operating activities		225,862			90,785
Investing activities:
Additions to natural gas and oil properties		(186,727	)		(107,015	)
Additions to field service assets		(1,565	)		(631	)
Acreage purchases		(28,725	)		(19,497	)
Proceeds from disposal of assets		26,053			113,079
Purchases of marketable securities held by the deferred compensation plan		(12,388	)		(8,662	)
Proceeds from the sales of marketable securities held by the deferred compensation plan		10,231			7,833
Net cash used in investing activities		(193,121	)		(14,893	)
Financing activities:
Borrowings on credit facilities		448,000			358,000
Repayments on credit facilities		(484,000	)		(422,000	)
Repayment of senior notes		(500	)		—
Debt issuance costs and other		—			(124	)
Dividends paid		(4,951	)		(3,395	)
Taxes paid for shares withheld		(5,879	)		(3,361	)
Change in cash overdrafts		11,803			(6,368	)
Proceeds from the sales of common stock held by the deferred compensation plan		3,017			1,414
Net cash used in financing activities		(32,510	)		(75,834	)
Increase in cash and cash equivalents		231			58
Cash and cash equivalents at beginning of period		314			471
Cash and cash equivalents at end of period	$	545		$	529

Range Resources Corporation is a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and the North Louisiana regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC”.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2016 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on February 22, 2017. The results of operations for three months ended March 31, 2017 are not necessarily indicative of the results to be expected for the full year. These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements.

On September 16, 2016, we issued approximately 77.0 million shares of common stock in exchange for all outstanding shares of common stock of Memorial Resources Development Corp. (“Memorial”) using an exchange ratio of 0.375 of a share of Range common stock for each share of Memorial common stock. For additional information, see Note 4.

Inventory. As of March 31, 2017, we had $10.2 million of material and supplies inventory compared to $9.4 million at December 31, 2016. Material and supplies inventory consists of primarily tubular goods and equipment used in our operations and is stated at lower of specific cost of each inventory item or market. At March 31, 2017, we also had commodity inventory of $2.4 million compared to $8.3 million at December 31, 2016. Commodity inventory as of March 31, 2017 consists of natural gas and NGLs held in storage or as line fill in pipelines.

In May 2014, an accounting standards update was issued that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in first quarter 2018 and will be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. We continue to evaluate the available adoption methods. We are utilizing a bottom-up approach to analyze the impact of the new standard on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts and the impact of adopting this standards update on our total net revenues, operating income (loss) and our consolidated balance sheet. We are currently performing detailed analysis of our portfolio of contracts at the individual contract level as we continue to evaluate the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures, in addition to developing any process or control changes necessary.

In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use asset and lease liability for all leases with terms of more than 12 months. Classification of leases as either a finance or operating lease will determine the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements. This standard is effective for us in first quarter 2019 and should be applied using a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements and early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows but based on our preliminary review of the update, we expect that we will have operating leases with durations greater than twelve months on the balance sheet. As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date.

In August 2016, an accounting standards update was issued that clarifies how entities classify certain cash receipts and cash payments on the statement of cash flows. The guidance is effective for us in first quarter 2018 and will be applied retrospectively with

early adoption permitted. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated cash flow statement presentation.

In August 2014, an accounting standards update was issued that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards. This standard was effective for us in 2016. The adoption did not have a significant impact on our consolidated results of operations, financial position, cash flows or financial disclosures; however, we did implement and formalize policies and procedures to ensure compliance with the requirement to perform ongoing interim and annual going concern assessments.

In March 2016, an accounting standards update was issued that simplifies several aspects of the accounting for share-based payment award transactions. Among other things, this new guidance requires all income tax effects of share-based awards to be recognized in the statement of operations when the awards vest or are settled, allows an employer to repurchase more of an employee’s shares for tax withholding purposes than it can today without triggering liability accounting and allows a policy election to account for forfeitures as they occur. This new standard is effective for annual periods beginning after December 15, 2016. Early adoption is permitted. We elected to early adopt this accounting standards update in fourth quarter 2016 and reflected any adjustments as of January 1, 2016, the beginning of the annual period that includes the interim period of adoption. The following summarizes the impact of the adoption of this update on our consolidated financial statements:

Income taxes - Upon adoption of this standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) are recognized as income tax expense or benefit in our consolidated statements of operations. The tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur. Adoption of this new standard resulted in the recognition of an excess tax deficiency in our provision for income taxes rather than paid-in capital of $2.1 million for the year ended December 31, 2016 and affected our previously reported first quarter 2016 results as follows (in thousands, except per share data):

In addition, we recorded a cumulative-effect adjustment to retained earnings (deficit) and reduced our deferred tax liability for $101.1 million for previously unrecognized tax benefits due to our NOL position as of December 31, 2016.

Forfeitures - Prior to adoption, share-based compensation expense was recognized on a straight line basis, net of estimated forfeitures, such that expense was recognized only for share-based awards that are expected to vest. We have elected to continue to estimate forfeitures.

Statements of cash flows - The presentation requirements for cash flows related to employee taxes paid for withheld shares were adjusted retrospectively. These cash flows have historically been presented as an operating activity. Upon adoption of this new standard, these cash outflows were classified as a financing activity. Prior periods have been adjusted as follows (in thousands):

In January 2017, an accounting standards update was issued that eliminates the requirements to calculate the implied fair value of goodwill to measure goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This standard is effective for annual periods beginning after December 15, 2019 and should be applied on a prospective basis. Early adoption is permitted for any goodwill impairment tests performed in first quarter 2017 or later. We elected to adopt this accounting standards update in first quarter 2017. The adoption did not have a significant impact on our consolidated results of operations, financial position, cash flows or financial disclosures; however, this standard did change our policy for our annual goodwill impairment assessment by eliminating the requirement to calculate the implied fair value of goodwill.

On September 16, 2016, we completed our merger with Memorial Resource Development Corp. (the “MRD Merger” or “Memorial”) which was accomplished through the merger of Medina Merger Sub, Inc., a Delaware corporation and a direct, wholly-owned subsidiary of Range, with and into Memorial, with Memorial surviving as a wholly-owned subsidiary of Range. The results of Memorial’s operations since the effective time of the MRD Merger are included in our consolidated statement of operations. The MRD Merger was effected through the issuance of approximately 77.0 million shares of Range common stock in exchange for all outstanding shares of Memorial using an exchange ratio of 0.375 of a share of Range common stock for each share of Memorial common stock. At the effective time of the MRD Merger, Memorial’s liabilities, which are reflected in Range’s consolidated financial statements, included approximately $1.2 billion fair value of outstanding debt. In the last six months of 2016, we incurred MRD Merger-related expenses of approximately $37.2 million which includes consulting, investment banking, advisory, legal and other merger-related fees.

Allocation of Purchase Price. The MRD Merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of the MRD Merger to the assets acquired and the liabilities assumed based on the fair value at the effective time of the MRD Merger, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of certain pre-merger contingencies, final tax returns that provide the underlying tax basis of Memorial’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the MRD Merger date, in line with the acquisition method of accounting, during which time the value of the assets and liabilities, including goodwill, may be revised as appropriate.

The following table sets forth our preliminary purchase price allocation (in thousands, except shares and stock price):

Purchase price:
Shares of Range common stock issued to Memorial stockholders		77,042,749
Range common stock price per share at September 15, 2016 (close)	$	39.37
Total purchase price	$	3,033,173

Plus fair value of liabilities assumed by Range:
Accounts payable	$	55,624
Other current liabilities		114,426
Long-term debt		1,204,449
Deferred taxes		547,348
Other long-term liabilities		77,223
Total purchase price plus liabilities assumed	$	5,032,243

Fair value of Memorial assets:
Cash and equivalents	$	7,180
Other current assets		97,875
Derivative instruments		152,994
Natural gas and oil properties:
Proved property		1,117,011
Unproved property		1,999,187
Other property and equipment		3,579
Goodwill ^(a)		1,654,292
Other		125
Total asset value	$	5,032,243

The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the MRD Merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs.

The fair value measurements of natural gas and oil properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of natural gas and oil properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of natural gas and oil properties include estimates of: (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices and (v) a market-based weighted average costs of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and may be subject to change. Management utilized the assistance of a third party valuation expert to estimate the value of natural gas and oil properties acquired. In some cases, certain amounts allocated to unproved properties are based on a market approach using third party published data which provides lease pricing information based on certain geographic areas and represent Level 2 inputs.

Goodwill is attributed to net deferred tax liabilities arising from the differences between the purchase price allocated to Memorial’s assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the total consideration for the MRD Merger included a control premium, which resulted in a higher value compared to the fair value of net assets acquired. There are also other qualitative assumptions of long-term factors that the MRD Merger creates including additional potential for exploration and development opportunities, additional scale and efficiencies in other basins in which we operate and substantial operating and administrative synergies.

The results of operations attributable to Memorial are included in our consolidated statement of operations beginning on September 16, 2016. We recognized $129.1 million of natural gas, oil and NGLs revenues and $83.4 million of field net operating income from these assets from January 1, 2017 to March 31, 2017.

Pro forma Financial Information. The following pro forma condensed combined financial information was derived from the historical financial statements of Range and Memorial and gives effect to the MRD Merger as if it had occurred on January 1, 2015. The below information reflects pro forma adjustments for the issuance of Range common stock in exchange for Memorial’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of Memorial’s fair-valued proved oil and gas properties and (ii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may

result from the MRD Merger or any estimated costs that have been or will be incurred by us to integrate the Memorial assets. The pro forma condensed combined financial information is not necessarily indicative of the results that might have actually occurred had the MRD Merger taken place on January 1, 2015. In addition, the pro forma financial information below is not intended to be a projection of future results (in thousands, except per share amounts).

We recognized a pretax net gain on the sale of assets of $22.6 million in first quarter 2017 compared to a pretax net loss of $1.6 million in the same period of the prior year.

Western Oklahoma. In first three months 2017, we sold certain properties in Western Oklahoma for proceeds of $26.0 million and we recorded a gain of $22.5 million related to this sale, after closing adjustments and transaction fees.

Other. In first three months 2017, we sold miscellaneous proved and unproved properties, inventory, other assets and surface acreage for proceeds of $53,000 resulting in a pretax gain of $69,000.

Pennsylvania. In first quarter 2016, we sold our non-operated interest in certain wells and gathering facilities in northeast Pennsylvania for proceeds of $111.5 million. After closing adjustments, we recorded a loss of $2.1 million related to this sale.

Other. In first three months 2016, we sold miscellaneous proved and unproved properties, inventory, other assets and surface acreage for proceeds of $1.6 million resulting in a pretax gain of $443,000. Included in the $1.6 million of proceeds is $1.2 million received from the sale of proved properties in Mississippi and South Texas.

During 2016, we recorded goodwill associated with the MRD Merger, which represents the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. During fourth quarter 2016, we performed our annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of the reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step impairment test. Based on the results of this assessment, we determined it was not likely that goodwill was impaired. We are not aware of any events or circumstances that occurred during first quarter 2017 that would have more likely than not reduced the fair value of our reporting unit below its carrying value.

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For first quarter 2017 and 2016, our overall effective tax rate was different than the federal statutory rate of 35% due primarily to state income taxesand other tax items which are detailed below (dollars in thousands).

	Three Months Ended March 31,
		2017			2016
Total income (loss) before income taxes	$	282,506		$	(135,748	)
U.S. federal statutory rate		35	%		35	%
Total tax expense (benefit) at statutory rate		98,877			(47,512	)

State and local income taxes, net of federal benefit		8,982			(4,432	)
Non-deductible executive compensation		140			236
Tax less than book equity compensation		2,524			5,266
Change in valuation allowances:
Federal net operating loss carryforwards & other		856			—
State net operating loss carryforwards & other		2,086			4,490
Rabbi trust		(1,122	)		(51	)
Permanent differences and other		52			27
Total expense (benefit) for income taxes	$	112,395		$	(41,976	)
Effective tax rate		39.8	%		30.9	%

Basic income or loss per share attributable to common shareholders is computed as (1) income or loss attributable to common shareholders (2) less income allocable to participating securities (3) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common shareholders is computed as (1) basic income or loss attributable to common shareholders (2) plus diluted adjustments to income allocable to participating securities (3) divided by weighted average diluted shares outstanding. The following tables set forth a reconciliation of income or loss attributable to common shareholders to basic income or loss attributable to common shareholders to diluted income or loss attributable to common shareholders (in thousands except per share amounts):

		Three Months Ended March 31,
		2017			2016
Net income (loss), as reported	$	170,111		$	(93,772	)
Participating earnings ^(a)		(1,882	)		(56	)
Basic net income (loss) attributed to common shareholders		168,229			(93,828	)
Reallocation of participating earnings ^(a)		1			—
Diluted net income (loss) attributed to common shareholders	$	168,230		$	(93,828	)
Net income (loss) per common share:
Basic	$	0.69		$	(0.56	)
Diluted	$	0.69		$	(0.56	)

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):

⁽¹⁾ 2017 includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016.

Weighted average common shares outstanding–basic for first quarter 2017 excludes 2.7 million shares of restricted stock held in our deferred compensation plan compared to 2.8 million shares in first quarter 2016 (although all awards are issued and outstanding upon grant). For first quarter 2017, stock appreciation rights (“SARs”) of 941,000 were outstanding but not included in the computation of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations. Due to our net loss from operations in first quarter 2016, we excluded all outstanding SARs, restricted stock and performance shares from the computation of diluted net loss per share because the effect would have been anti-dilutive.

We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are included in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. We did not have any exploratory well costs that have been capitalized for a period greater than one year as of March 31, 2017. The following table reflects the change in capitalized exploratory well costs for the three months ended March 31, 2017 and the year ended December 31, 2016 (in thousands):

We had the following debt outstanding as of the dates shown below (bank debt interest rate at March 31, 2017 is shown parenthetically). No interest was capitalized during the three months ended March 31, 2017 or the year ended December 31, 2016 (in thousands).


		March 31, 2017			December 31, 2016
Bank debt (2.5%)	$	846,000		$	882,000
Senior notes:
4.875% senior notes due 2025		750,000			750,000
5.00% senior notes due 2023		741,514			741,514
5.00% senior notes due 2022		580,032			580,032
5.75% senior notes due 2021		475,952			475,952
5.875% senior notes due 2022		329,244			329,244
Other senior notes due 2022		590			1,090
Total senior notes		2,877,332			2,877,832
Senior subordinated notes:
5.00% senior subordinated notes due 2023		7,712			7,712
5.00% senior subordinated notes due 2022		19,054			19,054
5.75% senior subordinated notes due 2021		22,214			22,214
Total senior subordinated notes		48,980			48,980
Total debt		3,772,312			3,808,812
Unamortized premium		6,960			7,258
Unamortized debt issuance costs		(40,477	)		(42,553	)
Total debt net of debt issuance costs	$	3,738,795		$	3,773,517

In October 2014, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets and has a maturity date of October 16, 2019. The bank credit facility provides for a maximum facility amount of $4.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually by May and for event-driven unscheduled redeterminations. As part of our annual redetermination completed on March 21, 2017, our borrowing base was reaffirmed at $3.0 billion and our bank commitment was also reaffirmed at $2.0 billion. As of March 31, 2017, our bank group was composed of twenty-nine financial institutions with no one bank holding more than 5.8% of the total facility. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. As of March 31, 2017, the outstanding balance under our bank credit facility was $846.0 million, before deducting debt issuance costs. Additionally, we had $279.7 million of undrawn letters of credit leaving $874.3 million of committed borrowing capacity available under the facility. During a non-investment grade period, borrowings under the bank credit facility can either be at the alternate base rate (“ABR,” as defined in the bank credit facility agreement) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit facility agreement) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. The weighted average interest rate was 2.4% in first quarter 2017 compared to 2.1% in first quarter 2016. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At March 31, 2017, the commitment fee was 0.3% and the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our base rate loans.

At any time during which we have an investment grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and we have elected, at our discretion, to effect the investment grade rating period, certain collateral security requirements, including the borrowing base requirement and restrictive covenants, will cease to apply and an additional financial covenant (as defined in the bank credit facility) will be imposed. During the investment grade period, borrowings under the credit facility can either be at the ABR plus a spread ranging from 0.125% to 0.75% or at the LIBOR Rate plus a spread ranging from 1.125% to 1.75% depending on our debt rating. The commitment fee paid on the undrawn balance would range from 0.15% to 0.30%. We currently do not have an investment grade debt rating.

In May 2015, we issued $750.0 million aggregate principal amount of 4.875% senior notes due 2025 (the “Outstanding Notes”) for net proceeds of $737.4 million after underwriting discounts and commissions of $12.6 million. The notes were issued at par and were offered to qualified institutional buyers and non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). On April 8, 2016, all of the Outstanding Notes were exchanged for an equal principal amount of registered 4.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4 filed with the SEC on February 29, 2016 under the Securities Act (the “Exchange Notes”). The Exchange Notes are identical to the Outstanding Notes except the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any.

If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior subordinated notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and are subordinated to existing and future senior debt that we or our subsidiary guarantors are permitted to incur.

Range is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries, which are directly or indirectly owned by Range, of our senior notes, senior subordinated notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the bank credit facility agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the bank credit facility agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at March 31, 2017.

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well lives. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the three months ended March 31, 2017 is as follows (in thousands):

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying consolidated statements of operations.

We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. We currently have no preferred stock issued or outstanding. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2016:

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We typically do not utilize complex derivatives, as we utilize commodity swaps or options to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. The fair value of our derivative contracts, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally the New York Mercantile Exchange (“NYMEX”) for natural gas and crude oil or Mont Belvieu for NGLs, approximated a net asset of $8.8 million at March 31, 2017. These contracts expire monthly through December 2019. The following table sets forth our commodity-based derivative volumes by year as of March 31, 2017, excluding our basis and freight swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2017	Swaps ⁽¹⁾	844,245 Mmbtu/day	$ 3.19
2018	Swaps	417,260 Mmbtu/day	$ 3.25
2017	Collars ⁽¹⁾	123,818 Mmbtu/day	$ 3.46–$ 4.12
2018	Collars	7,397 Mmbtu/day	$ 3.40–$ 3.75
2017	Purchased Puts ⁽¹⁾	178,909 Mmbtu/day	$ 3.49 ⁽²⁾
2017	Sold Calls	9,041 Mmbtu/day	$ 3.75 ⁽³⁾

Crude Oil
2017	Swaps ⁽¹⁾	8,782 bbls/day	$ 56.00
2018	Swaps	3,500 bbls/day	$ 53.81
2019	Swaps	250 bbls/day	$ 51.00

NGLs (C2-Ethane)
2017	Swaps	3,000 bbls/day	$ 0.27/gallon
2018	Swaps	124 bbls/day	$ 0.29/gallon

NGLs (C3-Propane)
2017	Swaps	13,895 bbls/day	$ 0.57/gallon
2018	Swaps	7,199 bbls/day	$0.65/gallon

NGLs (NC4-Normal Butane)
2017	Swaps	7,750 bbls/day	$ 0.74/gallon
2018	Swaps	4,250 bbls/day	$ 0.81/gallon

NGLs (C5-Natural Gasoline)
2017	Swaps	5,250 bbls/day	$ 1.06/gallon
2018	Swaps	1,500 bbls/day	$ 1.19/gallon

⁽¹⁾ Includes derivative instruments assumed in connection with the MRD Merger.

Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-hedge derivatives are recognized in earnings as derivative fair value income or loss.

In addition to the swaps above, at March 31, 2017, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing indices primarily in Appalachia. These contracts settle monthly through October 2018 and include a total volume of 68,830,000 Mmbtu. The fair value of these contracts was a loss of $20.4 million on March 31, 2017.

At March 31, 2017, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices. The contracts settle monthly through December 2018 and include a total volume of 1,641,000 barrels in 2017 and 750,000 barrels in 2018. The fair value of these contracts was a gain of $491,000 on March 31, 2017.

In connection with our international propane spread swaps, at March 31, 2017, we had freight swap contracts which lock in the freight rate for a specific trade route on the Baltic Exchange. These contracts settle monthly in fourth quarter 2017 through December 2018 and cover 5,000 metric tons per month with a fair value gain of $116,000 on March 31, 2017.

The combined fair value of derivatives included in the accompanying consolidated balance sheets as of March 31, 2017 and December 31, 2016 is summarized below. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. The tables below provide additional information relating to our master netting arrangements with our derivative counterparties (in thousands):

		March 31, 2017
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	28,756	$	(19,019	)	$	9,737
	–basis swaps		905		(3,330	)		(2,425	)
	–collars		9,650		(1,435	)		8,215
	–puts		19,563		(4,609	)		14,954
	–calls		—		(531	)		(531	)
Crude oil	–swaps		14,026		(1,532	)		12,494
NGLs	–C2 ethane swaps		507		(251	)		256
	–C3 propane swaps		4,531		(4,892	)		(361	)
	–C3 propane spread swaps		11,812		(11,812	)		—
	–NC4 butane swaps		6,970		(3,258	)		3,712
	–C5 natural gasoline swaps		2,405		(2,211	)		194
Freight	–swaps		116		(116	)		—
		$	99,241	$	(52,996	)	$	46,245

		March 31, 2017
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative liabilities:
Natural gas	–swaps	$	(55,204	)	$	19,019	$	(36,185	)
	–basis swaps		(21,287	)		3,330		(17,957	)
	–collars		—			1,435		1,435
	–puts		—			4,609		4,609
	–calls		(531	)		531		—
Crude oil	–swaps		(1,308	)		1,532		224
NGLs	–C2 ethane swaps		(137	)		251		114
	–C3 propane swaps		(12,164	)		4,892		(7,272	)
	–C3 propane spread swaps		(11,321	)		11,812		491
	–NC4 butane swaps		(3,395	)		3,258		(137	)
	–C5 natural gasoline swaps		(4,877	)		2,211		(2,666	)
Freight	–swaps		—			116		116
		$	(110,224	)	$	52,996	$	(57,228	)

		December 31, 2016
		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
Derivative assets:
Natural gas	–swaps	$	13,213	$	(11,425	)	$	1,788
	–basis swaps		12,535		(9,437	)		3,098
	–collars		6,298		(6,298	)		—
	–puts		18,159		(15,429	)		2,730
Crude oil	–swaps		9,356		(3,489	)		5,867
NGLs	–C2 ethane swaps		53		(53	)		—
	–C3 propane spread swaps		17,396		(17,396	)		—
	–NC4 butane swaps		4		(4	)		—
Freight	–swaps		65		(65	)		—
		$	77,079	$	(63,596	)	$	13,483

		December 31, 2016
		Gross Amounts of Recognized (Liabilities)			Gross Amounts Offset in the Balance Sheet		Net Amounts of (Liabilities) Presented in the Balance Sheet
Derivative liabilities:
Natural gas	–swaps	$	(158,359	)	$	11,425	$	(146,934	)
	–basis swaps		(687	)		9,437		8,750
	–collars		(2,625	)		6,298		3,673
	–puts		—			15,429		15,429
	–calls		(1,041	)		—		(1,041	)
Crude oil	–swaps		(13,206	)		3,489		(9,717	)
NGLs	–C2 ethane swaps		(1,008	)		53		(955	)
	–C3 propane swaps		(32,437	)		—		(32,437	)
	–C3 propane spread swaps		(18,138	)		17,396		(742	)
	–NC4 butane swaps		(13,419	)		4		(13,415	)
	–C5 natural gasoline swaps		(12,176	)		—		(12,176	)
Freight	–swaps		—			65		65
		$	(253,096	)	$	63,596	$	(189,500	)

The effects of our derivatives on our consolidated statements of operations are summarized below (in thousands):

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

The need to test long-lived assets and goodwill can be based on several indicators, including a significant reduction in prices of natural gas, oil and condensate, NGLs, sustained declines in our common stock, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which a property is located.

We use a market approach for our recurring fair value measurements and endeavor to use the best information available. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):

	Fair Value Measurements at March 31, 2017 using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of March 31, 2017
Trading securities held in the deferred compensation plans	$	67,075	$	—		$	—	$	67,075
Derivatives –swaps		—		(19,890	)		—		(19,890	)
–collars		—		9,650			—		9,650
–puts		—		19,563			—		19,563
–calls		—		(531	)		—		(531	)
–basis swaps		—		(19,891	)		—		(19,891	)
–freight swaps		—		116			—		116

		Fair Value Measurements at December 31, 2016 Using:
		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2016
Trading securities held in the deferred compensation plans		$	61,717	$	—		$	—	$	61,717
Derivatives	–swaps		—		(207,979	)		—		(207,979	)
	–collars		—		3,673			—		3,673
	–puts		—		18,159			—		18,159
	–calls		—		(1,041	)		—		(1,041	)
	–basis swaps		—		11,106			—		11,106
	–freight swaps		—		65			—		65

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using end of period market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes.

Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains or losses are included in deferred compensation plan expense in the accompanying consolidated statements of operations. For first quarter 2017, interest and dividends were $118,000 and the mark-to-market adjustment was a gain of $1.5 million compared to interest and dividends of $136,000 and a mark-to-market gain of $259,000 in first quarter 2016.

Our proved natural gas and oil properties are reviewed for impairment periodically as events or changes in circumstances indicate the carrying amount may not be recoverable. In first quarter 2016, due to declines in commodity prices, there were indicators that the carrying value of certain of our oil and gas properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their remaining fair value was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 measurements. We also considered the potential sale of certain of these properties. We recorded non-cash charges during first quarter 2016 of $43.0 million related to our natural gas and oil properties in Western Oklahoma. Our estimates of future cash flows attributable to our natural gas and oil properties could decline further with commodity prices which may result in additional impairment charges. There were no impairment charges in first quarter 2017. The following table presents the value of these assets measured at fair value on a non-recurring basis at the time impairment was recorded (in thousands):

The following table presents the carrying amounts and the fair values of our financial instruments as of March 31, 2017 and December 31, 2016 (in thousands):

	March 31, 2017						December 31, 2016
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, options and basis swaps	$	46,245		$	46,245		$	13,483		$	13,483
Marketable securities ^(a)		67,075			67,075			61,717			61,717
(Liabilities):
Commodity swaps, options and basis swaps		(57,228	)		(57,228	)		(189,500	)		(189,500	)
Bank credit facility ^(b)		(846,000	)		(846,000	)		(882,000	)		(882,000	)
5.75% senior notes due 2021 ^(b)		(475,952	)		(490,231	)		(475,952	)		(496,180	)
5.00% senior notes due 2022 ^(b)		(580,032	)		(573,507	)		(580,032	)		(577,132	)
5.875% senior notes due 2022 ^(b)		(329,244	)		(338,298	)		(329,244	)		(343,648	)
Other senior notes due 2022 ^(b)		(590	)		(575	)		(1,090	)		(1,104	)
5.00% senior notes due 2023 ^(b)		(741,514	)		(730,391	)		(741,514	)		(735,026	)
4.875% senior notes due 2025 ^(b)		(750,000	)		(714,375	)		(750,000	)		(724,688	)
5.75% senior subordinated notes due 2021 ^(b)		(22,214	)		(22,131	)		(22,214	)		(22,325	)
5.00% senior subordinated notes due 2022 ^(b)		(19,054	)		(18,649	)		(19,054	)		(18,387	)
5.00% senior subordinated notes due 2023 ^(b)		(7,712	)		(7,538	)		(7,712	)		(7,645	)
Deferred compensation plan ^(c)		(128,805	)		(128,805	)		(139,580	)		(139,580	)

Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivable and payable. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical and expected incurrence of bad debt expense. Non-financial liabilities initially measured at fair value include asset retirement obligations. For additional information, see Note 10.

As of March 31, 2017, our primary concentrations of credit risk are the risks of not collecting accounts receivable and the risk of a counterparty’s failure to perform under derivative obligations. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate securities are obtained as deemed necessary to limit our risk of loss. Our allowance for uncollectable receivables was $5.6 million at both March 31, 2017 and December 31, 2016. As of March 31, 2017, our derivative contracts consist of swaps and options. Our derivative exposure to credit risk is diversified primarily among major investment grade

financial institutions, where we have master netting agreements which provide for offsetting payables against receivables from separate derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. At March 31, 2017, our derivative counterparties include twenty-two financial institutions, of which all but five are secured lenders in our bank credit facility. At March 31, 2017, our net derivative liability includes a net payable to these five counterparties that are not participants in our bank credit facility of $5.9 million.

We have one active equity-based stock plan, our Amended and Restated 2005 Equity-Based Incentive Compensation Plan, which we refer to as the 2005 Plan. Under this plan, various awards may be issued to non-employee directors and employees pursuant to decisions of the Compensation Committee, which is composed of only non-employee, independent directors. In 2005, we granted SARs which represent the right to receive a payment equal to the excess of the fair market value of shares of our common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted under the 2005 Plan will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted. In 2011, the Compensation Committee of the Board of Directors began granting restricted stock units under this plan. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement.

In 2014, the Compensation Committee also began granting market-based performance share unit (“TSR”) awards under our 2005 Plan. The number of shares to be issued is determined by our total shareholder return compared to the total shareholder return of a predetermined group of peer companies over the performance period. The grant date fair value of the PSU-TSR awards is determined using a Monte Carlo simulation and is recognized as stock-based compensation expense over the three-year performance period. The actual payout of shares granted depends on our total shareholder return compared to our peer companies and will be between zero and 150%, unless our return is negative in which case the payout is capped at 100%. In first quarter 2017, the Compensation Committee also began granting performance-based unit awards based on production growth per share (“RGPS”) and reserve growth per share (“PGPS”). The number of shares to be issued depends on our level of success in achieving specifically identified performance targets. The grant date fair value is determined by the market value of our stock on the grant date and is recognized as stock-based compensation expense over the three-year performance period. The actual payout of shares granted will be between zero and 150%.

The Compensation Committee also grants restricted stock to certain employees and non-employee directors of the Board of Directors as part of their compensation. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the shares generally are placed in our deferred compensation plan and, upon vesting, employees are allowed to take withdrawals either in cash or in stock based on their distribution elections. Compensation expense is recognized over the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and vesting is based upon an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. Prior to vesting, all restricted stock awards have the right to vote such shares and receive dividends thereon. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market adjustment is reported as deferred compensation plan expense in the accompanying consolidated statements of operations.

Stock-based compensation represents amortization of restricted stock, PSUs and SARs expense. Unlike the other forms of stock-based compensation, the mark-to-market adjustment of the liability related to the vested restricted stock held in our deferred compensation plan is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. The following table details the allocation of stock-based compensation to functional expense categories (in thousands):

The following is a summary of our non-vested TSR awards outstanding at March 31, 2017:

^(a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 150% of the performance units granted depending on the total shareholder return ranking compared to the peer companies at the end of the three-year performance period.

The following assumptions were used to estimate the fair value of TSR’s granted during first quarter 2017 and 2016:

We recorded TSR compensation expense of $3.1 million in first quarter 2017 compared to $2.5 million in the same period of 2016.

The following is a summary of our non-vested PGPS/RGPS awards outstanding at March 31, 2017:

^(a) Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 150% depending on achievement of specifically identified performance targets.

In first quarter 2017, we granted 870,000 restricted stock Equity Awards to employees at an average grant price of $32.98 compared to 927,000 restricted stock Equity Awards granted to employees at an average grant price of $28.04 in first quarter 2016. These awards generally vest over a three-year period. We recorded compensation expense for these Equity Awards of $6.0 million in first quarter 2017 compared to $5.8 million in the same period of 2016. Equity Awards are not issued to employees until they are vested. Employees do not have the option to receive cash.

In first quarter 2017, we granted 66,000 shares of restricted stock Liability Awards as compensation to employees at an average price of $32.67 with vesting over a three-year period. In first quarter 2016, we granted 136,000 shares of Liability Awards as compensation to employees at an average price of $28.40 with vesting generally over a three-year period. We recorded compensation expense for Liability Awards of $2.7 million in first quarter 2017 compared to $3.7 million in the same period of 2016. Substantially all of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value at the end of each reporting period. This mark-to-market adjustment is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The following is a summary of the status of our non-vested restricted stock outstanding at March 31, 2017:

	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2016		765,971		$	33.62		425,018		$	43.48
Granted		870,326			32.98		66,078			32.67
Vested		(162,647	)		36.88		(67,973	)		50.56
Forfeited		(52,069	)		33.74		—			—
Outstanding at March 31, 2017		1,421,581		$	32.85		423,123		$	40.65

There were 908,000 SARs outstanding at March 31, 2017. Information with respect to SARs activity is summarized below:

Our deferred compensation plan gives non-employee directors and officers the ability to defer all or a portion of their salaries, bonuses or director fees and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution to officers which vests over three years. The assets of the plan are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our general creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected as deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value as other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market gain of $13.2 million in first quarter 2017 compared to mark-to-market loss of $16.1 million in first quarter 2016. The Rabbi Trust held 2.7 million shares (2.2 million of which were vested) of Range stock at March 31, 2017 compared to 2.7 million shares (2.3 million of which were vested) at December 31, 2016.

We are the subject of, or party to, a number of pending or threatened legal actions, administrative proceedings and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to these actions, proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. We will continue to evaluate our litigation and regulatory proceedings quarterly and will establish and adjust any estimated liability as appropriate to reflect our assessment of the then current status of litigation and regulatory proceedings. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different.

In first quarter 2017, our transportation and gathering commitments increased by approximately $437.4 million over the next twenty-two years (through 2038) primarily due to extension of terms and pricing changes for current contracts.

In first quarter 2017, we have recorded additional accruals for severance, other personnel costs and accelerated vesting of stock-based compensation as part of a continuing effort to reduce our general and administrative expenses due, in part, to the lower commodity price environment. The following summarizes our termination costs for the three months ended March 31, 2017 and 2016 (in thousands):

The following details our accrued liability as of March 31, 2017 (in thousands):

(18) Capitalized Costs and Accumulated Depreciation, Depletion and Amortization ^(a)

	Three Months Ended March 31, 2017		Year Ended December 31, 2016
	(in thousands)
Acquisitions:
Acreage purchases	$	25,425	$	33,142
Oil and gas properties		—		3,098,772
Asset retirement obligations		—		21,908
Development		227,177		497,795
Exploration:
Drilling		500		37,680
Expense		7,997		30,027
Stock-based compensation expense		507		2,298
Gas gathering facilities:
Development		1,455		3,595
Subtotal		263,061		3,725,217
Asset retirement obligations		1,715		(24,064	)
Total costs incurred	$	264,776	$	3,701,153

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our current forecasts for our existing operations and do not include the potential impact of any future events. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2016, as filed with the SEC on February 22, 2017.

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company engaged in the exploration, development and acquisition of natural gas and crude oil properties primarily in the Appalachian and North Louisiana regions of the United States. We operate in one segment and 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 a geographical or an area-by-area basis.

Our overarching business objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our business objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures of non-core assets. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs, crude oil and condensate and on our ability to economically find, develop, acquire and produce natural gas, NGLs and crude oil reserves. Natural gas, NGLs and crude oil prices continue to be depressed. Prices for natural gas, NGLs and oil fluctuate widely and affect:

We prepare our financial statements in conformity with generally accepted accounting principles, which require us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities.

Prices for our products significantly impact our revenue, net income and cash flow. Natural gas, NGLs and oil are commodities and prices for these commodities are inherently volatile. The following table lists average New York Mercantile Exchange (“NYMEX”) prices for natural gas and oil and the Mont Belvieu NGL composite price for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
		2017		2016		Change	%

Average NYMEX prices ^(a)
Natural gas (per mcf)	$	3.29	$	2.09	$	1.20	57	%
Oil (per bbl)		51.81		33.56		18.25	54	%
Mont Belvieu NGLs composite (per gallon) ^(b)		0.54		0.32		0.22	69	%

During first quarter 2017, we achieved the following financial and operating results:

Our financial results are significantly impacted by commodity prices. We experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 41% increase in realized prices (average prices including all derivative settlements and third party transportation costs paid by us) and 38% higher production volumes when compared to first quarter 2016. During first quarter 2017, we recognized a net income of $170.1 million, or $0.69 per diluted common share compared to net loss of $93.8 million, or $0.56 per diluted common share, during first quarter 2016. One of our primary focuses over the past few years has been to increase efficiencies and reduce costs throughout the organization through a number of internal initiatives. As a result, we have continued to achieve reductions in our direct operating expenses per mcfe when compared to prior year. We continue to evaluate opportunities to reduce our general and administrative expenses and in early 2017 have implemented additional work force reductions.

On September 16, 2016, we completed the MRD Merger. The MRD Merger adds a premier onshore U.S. natural gas resource play to our existing core operating areas. The North Louisiana location provides geographic and marketing diversity to our high quality Appalachia basin assets. We anticipate continuing to improve drilling and well performance in this play by applying best practices from our Marcellus division and capitalizing on synergies. On September 16, 2016, we issued approximately 77.0 million shares of common stock in exchange for all outstanding shares of Memorial using an exchange ratio of 0.375 of a share of Range common stock for each share of Memorial common stock. See also Note 4 to our unaudited consolidated financial statements.

Our revenues vary primarily as a result of changes in realized commodity prices and production volumes. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types include transportation charges. One type of agreement is a netback agreement, under which we sell natural gas or oil at the wellhead and collect a price, net of transportation costs incurred by the purchaser. In this case, we record revenue at the price we receive from the purchaser. At times, for NGLs, we receive a net price from the purchaser (which is net of processing costs) which is also recorded as revenue at the net price we receive from the purchaser. Under the other type of agreement, we sell natural gas, NGLs or oil at a specific delivery point, pay transportation and other costs to a third party and receive proceeds from the purchaser with no transportation cost deduction. In that case, we record transportation costs and other costs that we pay to third parties as transportation, gathering and compression expense.

In first quarter 2017, natural gas, NGLs and oil sales increased 167% compared to first quarter 2016 with a 93% increase in average realized prices (before cash settlements on our derivatives) and a 40% increase in average daily production. The following table illustrates the primary components of natural gas, NGLs, oil and condensate sales for the three months ended March 31, 2017 and 2016 (in thousands):

	Three Months Ended March 31,
		2017		2016		Change	%
Natural gas, NGLs and oil sales
Gas	$	371,352	$	142,435	$	228,917	161	%
NGLs		138,063		50,162		87,901	175	%
Oil		50,035		16,890		33,145	196	%
Total natural gas, NGLs and oil sales	$	559,450	$	209,487	$	349,963	167	%

Our production continues to grow through drilling success, additional NGLs extraction and newly acquired production but is partially offset by the natural production decline of our wells and non-core asset sales. When compared to the same period of 2016, our first quarter 2017 production volumes increased 12% in our Appalachian region. Production volumes from our newly acquired North Louisiana properties were 396.8 Mmcfe per day. Production volumes from the Marcellus Shale in first quarter 2017 were 1.5 Bcfe per day. When compared to the same period of 2016, our Marcellus production volumes increased 12% for first quarter 2017. Our production for the three months ended March 31, 2017 and 2016 is set forth in the following table:

	Three Months Ended March 31,
	2017		2016		Change		%
Production ^(a)
Natural gas (mcf)		116,256,337		84,867,370		31,388,967	37	%
NGLs (bbls)		8,536,728		5,974,734		2,561,994	43	%
Crude oil (bbls)		1,065,286		844,341		220,945	26	%
Total (mcfe) ^(b)		173,868,421		125,781,820		48,086,601	38	%
Average daily production ^(a)
Natural gas (mcf)		1,291,737		932,608		359,129	39	%
NGLs (bbls)		94,853		65,656		29,197	44	%
Crude oil (bbls)		11,837		9,278		2,559	28	%
Total (mcfe) ^(b)		1,931,871		1,382,218		549,653	40	%

Our average realized price received (including all derivative settlements and third-party transportation costs) during first quarter 2017 was $2.17 per mcfe compared to $1.54 per mcfe in first quarter 2016. Although we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. Average realized prices (excluding derivative settlements) do not include derivative settlements or third party transportation costs which are reported in transportation, gathering, processing and compression expense on the accompanying consolidated statements of operations. Average realized prices (excluding derivative settlements) do include transportation costs where we receive net revenue proceeds from purchasers.

Realized prices include the impact of basis differentials. The price we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. Average natural gas differentials were $0.10 per mcf below NYMEX in first quarter 2017 compared to $0.41 per mcf below NYMEX in first quarter 2016. We also realized gains on our basis hedging in first quarter 2017 of $0.11 per mcf compared to a realized gain of $0.10 per mcf in first quarter 2016. Average realized price calculations for the three months ended March 31, 2017 and 2016 are shown below:

	Three Months Ended March 31,
	2017		2016		Change		%
Average Prices
Average realized prices (excluding derivative settlements):
Natural gas (per mcf)	$	3.19	$	1.68	$	1.51	90	%
NGLs (per bbl)		16.17		8.40		7.77	93	%
Crude oil and condensate (per bbl)		46.97		20.00		26.97	135	%
Total (per mcfe) ^(a)		3.22		1.67		1.55	93		%
Average realized prices (including all derivative settlements):
Natural gas (per mcf)	$	3.26	$	2.69	$	0.57	21	%
NGLs (per bbl)		14.49		10.22		4.27	42	%
Crude oil and condensate (per bbl)		49.50		35.49		14.01	39	%
Total (per mcfe) ^(a)		3.19		2.54		0.65	26	%
Average realized prices (including all derivative settlements and third party transportation costs paid by Range):
Natural gas (per mcf)	$	2.21	$	1.59	$	0.62	39	%
NGLs (per bbl)		8.00		4.75		3.25	68	%
Crude oil and condensate (per bbl)		49.50		35.49		14.01	39	%
Total (per mcfe) ^(a)		2.17		1.54		0.63	41	%

Transportation, gathering, processing and compression expense was $177.6 million in first quarter 2017 compared to $125.3 million in first quarter 2016. These third party costs are higher in 2017 as compared to 2016 due to our production growth in the Marcellus Shale where we have third party gathering, processing, compression and transportation agreements. Also included in first quarter 2017 are additional third party costs for our newly acquired North Louisiana production. We have included these costs in the calculation of average realized prices (including all derivative settlements and third party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the three months March 31, 2017 and 2016 (in thousands) and on a per mcf and per barrel basis:

	Three Months Ended March 31,
	2017		2016		Change			%
Natural gas	$	122,194	$	92,592	$	29,602		32	%
NGLs		55,454		32,671		22,783		70	%
Total	$	177,648	$	125,263	$	52,385		42	%

Natural gas (per mcf)	$	1.05	$	1.09	$	(0.04	)	(4	%)
NGLs (per bbl)	$	6.50	$	5.47	$	1.03		19	%

Derivative fair value income was $165.6 million in first quarter 2017 compared to $86.9 million in first quarter 2016. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment can result in more volatility of our revenues as the change in the fair value of our commodity derivative positions is included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the three months ended March 31, 2017 and 2016 (in thousands):

		Three Months Ended March 31,
		2017			2016
Derivative fair value income per consolidated statements of operations	$	165,557		$	86,908

Non-cash fair value gain (loss): ⁽¹⁾
Natural gas derivatives	$	99,063		$	(2,947	)
Oil derivatives		16,567			(9,506	)
NGLs derivatives		54,056			(10,094	)
Freight derivatives		52			(11	)
Total non-cash fair value gain (loss) ⁽¹⁾	$	169,738		$	(22,558	)

Net cash (payment) receipt on derivative settlements:
Natural gas derivatives	$	7,455		$	85,515
Oil derivatives		2,697			13,073
NGLs derivatives		(14,333	)		10,878
Total net cash (payment) receipt	$	(4,181	)	$	109,466

Brokered natural gas, marketing and other revenue in first quarter 2017 was $51.6 million compared to $35.0 million in first quarter 2016 with significantly higher average sales prices for our brokered natural gas volumes. First quarter 2016 includes $3.0 million from the sale of brokered propane volumes compared to none in first quarter 2017.

We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the three months ended March 31, 2017 and 2016:

Direct operating expense was $28.0 million in first quarter 2017 compared to $24.1 million in first quarter 2016. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses. Our production volumes increased 38% but, on an absolute basis, our spending for direct operating expenses for first quarter 2017 only increased 17% from the prior year quarter. Our direct operating costs have declined as a result of our cost reduction efforts and the sale of non-core assets. We have experienced cost decreases in many categories of direct operating expenses including lower well service costs, lower water handling and disposal costs and lower utilities. We incurred $1.7 million of workover costs in first quarter 2017 compared to $1.4 million in first quarter 2016.

On a per mcfe basis, direct operating expense in first quarter 2017 decreased 16% from the same period of 2016 with the decrease consisting of lower well service costs, lower water handling and disposal costs and lower personnel costs. The following table summarizes direct operating expenses per mcfe for the three months ended March 31, 2017 and 2016:

Production and ad valorem taxes are paid based on market prices, not hedged prices. This expense category also includes the Pennsylvania impact fee. Production and ad valorem taxes (excluding the impact fee) were $2.0 million in first quarter 2017 compared to $526,000 in first quarter 2016. On a per mcfe basis, production and ad valorem taxes (excluding the impact fee) were $0.01 in first quarter 2017 compared to a negligible amount in first quarter 2016 due to an increase in volumes not subject to production or ad valorem taxes. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” which functions as a tax on unconventional natural gas and oil production from the Marcellus Shale in Pennsylvania. Included in first quarter 2017 is a $7.2 million impact fee ($0.04 per mcfe) compared to $5.4 million ($0.04 per mcfe) in first quarter 2016.

General and administrative (“G&A”) expense was $47.5 million in first quarter 2017 compared to $40.7 million for first quarter 2016. First quarter 2017 increase of $6.8 million when compared to the same period of 2016 is primarily due to higher salaries and benefits, higher Louisiana franchise taxes and higher office expenses, including technology. At March 31, 2017, the number of G&A employees increased 14% when compared to March 31, 2016 with 11% related to our newly acquired North Louisiana properties. The following table summarizes G&A expenses per mcfe for the three months ended March 31, 2017 and 2016:

Interest expense was $47.1 million for first quarter 2017 compared to $37.7 million for first quarter 2016. The following table presents information about interest expense per mcfe for the three months ended March 31, 2017 and 2016:

	Three Months Ended March 31,
	2017			2016			Change			%
Bank credit facility	$	0.04		$	0.03		$	0.01		(33	%)
Senior notes		0.22			0.07			0.15		214	%
Subordinated notes		—			0.19			(0.19	)	(100	%)
Amortization of deferred financing costs and other		0.01			0.01			—		—	%
Total interest expense	$	0.27		$	0.30		$	(0.03	)	(10	%)
Average debt outstanding (in thousands)	$	3,852,362		$	2,737,692		$	1,114,670		41	%
Average interest rate ^(a)		4.7	%		5.3	%		(0.6	)	(11	%)

^(a) Includes commitment fees but excludes debt issue costs and amortization of discounts.

On an absolute basis, the increase in interest expense for first quarter 2017 from the same period of 2016 was primarily due to higher average outstanding debt balances partially offset by lower average interest rates. Average debt outstanding on the bank credit facility for first quarter 2017 was $926.3 million compared to $137.6 million in first quarter 2016 and the weighted average interest rate on the bank credit facility was 2.4% in first quarter 2017 compared to 2.1% in first quarter 2016.

Depletion, depreciation and amortization (“DD&A”) expense was $149.8 million in first quarter 2017 compared to $120.6 million in first quarter 2016. This increase is due to a 38% increase in production volumes somewhat offset by a 9% decrease in depletion rates. Depletion expense, the largest component of DD&A expense, was $0.83 per mcfe in first quarter 2017 compared to $0.91 per mcfe in first quarter 2016. We have historically 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. Our depletion rate per mcfe continues to decline due to the mix of our production from our properties with lower depletion rates and asset sales. The following table summarizes DD&A expense per mcfe for the three months ended March 31, 2017 and 2016:

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gas and marketing expense, exploration expense, abandonment and impairment of unproved properties, termination costs and deferred compensation plan expenses. Stock-based compensation includes the amortization of restricted stock grants, PSUs and SARs grants. The following table details the allocation of stock-based compensation to functional expense categories for the three months ended March 31, 2017 and 2016 (in thousands):

Brokered natural gas and marketing expense was $53.6 million in first quarter 2017 compared to $36.6 million in first quarter 2016. The increase reflects significantly higher broker purchase prices.

Exploration expense was $8.5 million in first quarter 2017 compared to $4.9 million in first quarter 2016 due to higher seismic, delay rental costs and personnel costs, due in part to our North Louisiana operations. The following table details our exploration related expenses for the three months March 31, 2017 and 2016 (in thousands):

Abandonment and impairment of unproved properties was $4.4 million in first quarter 2017 compared to $10.6 million in first quarter 2016. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments may be recorded.

Termination costs were $4.2 million for first quarter 2017 compared to $162,000 in the same period of 2016. In first quarter 2017, we implemented additional work force reductions which increased these costs $2.4 million for estimated severance costs and $1.7 million of accelerated vesting of equity grants.

Deferred compensation plan expense was a gain of $13.2 million in first quarter 2017 compared to a loss of $16.1 million in first quarter 2016. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. Our stock price decreased from $34.36 at December 31, 2016 to $29.10 at March 31, 2017. In the same quarter of the prior year, our stock price increased from $24.61 at December 31, 2015 to $32.38 at March 31, 2016.

Impairment of proved properties was $43.0 million in first quarter 2016. There was no impairment of proved properties in first quarter 2017. We assess our proved natural gas and oil properties whenever events or circumstances indicate the carrying value of these assets may not be recoverable. The cash flows we use to assess proved property impairment includes numerous assumptions including (1) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves (2) results of future drilling activities (3) future commodity prices and (4) increases or decreases in production and capital costs. All inputs are evaluated at each measurement date. In first quarter 2016, impairment expense was recorded related to certain of our oil and gas properties in Oklahoma. Due to falling commodity prices, our analysis of these properties, which included the possibility of a sale of certain of these properties, determined that undiscounted future cash flows were less than their carrying values.

(Gain) loss on the sale of assets was a gain of $22.0 million in first quarter 2017 compared to a loss of $1.6 million in first quarter 2016. In first quarter 2017, we sold properties in Western Oklahoma for $26.0 million of proceeds and, after closing adjustments, we recognized a gain of $22.5 million related to this sale. In first quarter 2016, we sold our non-operated interest in certain wells and gathering facilities in Northeast Pennsylvania for proceeds of $111.5 million and, after closing adjustments, we recognized a loss of $2.1 million related to this sale.

Income tax expense (benefit) was an expense of $112.4 million in first quarter 2017 compared to a benefit of $42.0 million in first quarter 2016. For the first quarter, the effective tax rate was 39.8% in 2017 compared to 30.9% in 2016. The 2017 and 2016 effective tax rates were different than the statutory tax rate due to state income taxes and other discrete tax items which are detailed below. We expect our effective tax rate to be approximately 38% for the remainder of 2017, before any tax items (dollars in thousands).

	Three Months Ended March 31,
		2017			2016
Total income (loss) before income taxes	$	282,506		$	(135,748	)
U.S. federal statutory rate		35	%		35	%
Total tax expense (benefit) at statutory rate		98,877			(47,512	)

State and local income taxes, net of federal benefit		8,982			(4,432	)
Non-deductible executive compensation		140			236
Tax less than book equity compensation		2,524			5,266
Change in valuation allowances:
Federal net operating loss carryforwards & other		856			—
State net operating loss carryforwards & other		2,086			4,490
Rabbi trust		(1,122	)		(51	)
Permanent differences and other		52			27
Total expense (benefit) for income taxes	$	112,395		$	(41,976	)
Effective tax rate		39.8	%		30.9	%

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations are also impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under our bank credit facility. Because of this, and because our principal source of operating cash flows (proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has varied and will continue to vary from year-to-year depending on, among other things, our expectation of future commodity prices. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. As of March 31, 2017, we have entered into hedging agreements covering 382.5 Bcfe for the remainder of 2017, 191.3 Bcfe for 2018 and 547,500 Mcfe in 2019, not including our basis swaps.

The following table presents sources and uses of cash and cash equivalents for the three months ended March 31, 2017 and 2016 (in thousands):


	Three Months Ended March 31,
		2017			2016
Sources of cash and cash equivalents
Operating activities	$	225,862		$	90,785
Disposal of assets		26,053			113,079
Borrowing on credit facility		448,000			358,000
Other		25,051			9,247
Total sources of cash and cash equivalents	$	724,966		$	571,111

Uses of cash and cash equivalents
Additions to natural gas and oil properties	$	(186,727	)	$	(107,015	)
Repayment on credit facility		(484,000	)		(422,000	)
Repayment of senior notes		(500	)		—
Acreage purchases		(28,725	)		(19,497	)
Other property		(1,565	)		(631	)
Dividends paid		(4,951	)		(3,395	)
Other		(18,267	)		(18,515	)
Total uses of cash and cash equivalents	$	(724,735	)	$	(571,053	)

Net cash provided from operating activities in first quarter 2017 was $225.9 million compared to $90.8 million in first quarter 2016. Cash provided from continuing operations is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The increase in cash provided from operating activities from 2016 to 2017 reflects a 38% increase in production, lower operating costs and higher realized prices (an increase of 41%). As of March 31, 2017, we have hedged more than 65% of our projected total production for the remainder of 2017, with more than 80% of our projected natural gas production hedged. Net cash provided from continuing operations is affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for first quarter 2017 were negative $20.8 million compared to negative $2.9 million for first quarter 2016.

Disposal of assets in first quarter 2017 includes $26.0 million of proceeds received from the sale of certain Western Oklahoma properties which closed in February 2017. First quarter 2016 includes $111.5 million of proceeds received from the sale of certain of our properties in Northeast Pennsylvania which closed in March 2016.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with uncommitted and committed availability, access to the debt and equity capital markets and asset sales. We must find new reserves and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs which require substantial capital expenditures. We continue to take steps to ensure we have adequate capital resources and liquidity to fund our capital expenditure program. In first quarter 2017, we reduced our operating costs per unit of production and we entered into additional commodity derivative contracts for 2017, 2018 and 2019 to protect future cash flows. In March 2017, our borrowing base and credit facility commitment were reaffirmed through May 1, 2018.

During first quarter 2017, our net cash provided from operating activities of $225.9 million and the proceeds we received from asset sales were used to fund approximately $217.0 million of capital expenditures (including acreage acquisitions). At March 31, 2017, we had $545,000 in cash and total assets of $11.4 billion.

Long-term debt at March 31, 2017 totaled $3.7 billion, including $846.0 million outstanding on our bank credit facility, $2.9 billion of senior notes and $49.0 million of senior subordinated notes. Our available committed borrowing capacity at March 31, 2017 was $874.3 million. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We currently believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives contracts currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. To the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, debt or equity securities may be issued to fund these requirements. Long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas business. A further material decline in natural gas, NGLs and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and operate profitably. We establish a capital budget at the beginning of each calendar year and review it during the course of the year, taking into account various factors including the commodity price environment. Our 2017 capital budget is $1.15 billion. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of natural gas, NGLs and oil, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

As of March 31, 2017, we maintained a revolving credit facility with a borrowing base of $3.0 billion and aggregate lender commitments of $2.0 billion, which we refer to as our bank credit facility. The bank credit facility, during a non-investment grade period, is secured by substantially all of our assets and has a maturity date of October 16, 2019. Availability under the bank credit facility is subject to a borrowing base set by the lenders annually with an option to set more often in certain circumstances. Availability under the bank credit facility, during an investment grade period, is limited to aggregate lender commitments. As of March 31, 2017, the outstanding balance under our credit facility was $846.0 million. Additionally, we had $279.7 million of undrawn letters of credit leaving $874.3 million of committed borrowing capacity available under the facility at the end of first quarter 2017.

Our bank credit facility imposes limitations on the payment of dividends and other restricted payments (as defined under our bank credit facility). These agreements also contain customary covenants relating to debt incurrence, liens, investments and financial ratios. We were in compliance with all covenants at March 31, 2017. See Note 9 to our unaudited consolidated financial statements for additional information regarding our bank debt.

In February 2016, the Board of Directors approved a reduction of our quarterly dividend from $0.04 per share to $0.02 per share. On March 1, 2017, our Board of Directors declared a dividend of two cents per share ($5.0 million) on our outstanding common stock, which was paid on March 31, 2017 to stockholders of record at the close of business on March 15, 2017. The amount of future dividends is subject to discretionary declaration by the Board of Directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors.

Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, processing and gathering commitments. As of March 31, 2017, we do not have any capital leases. As of March 31, 2017, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of March 31, 2017, we had a total of $279.7 million of undrawn letters of credit under our bank credit facility.

Since December 31, 2016, there have been no material changes to our contractual obligations other than a $36.0 million decrease in our outstanding bank credit facility balance and an extension of terms related to existing processing and gathering contracts. Our contractual obligations for firm transportation and gathering contracts increased by approximately $437.4 million over the next twenty-two years related to this extension.

We use commodity-based derivative contracts to manage our exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We typically do not utilize complex derivatives. We utilize commodity swap and option contracts to (1) reduce the effect of price volatility on the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. While there is a 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 a 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 on-going development drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets. The fair value of these contracts which is represented by the estimated amount that would be realized or payable on termination is based on a comparison of the contract price and a reference price, generally NYMEX for natural gas and oil or Mont Belvieu for NGLs, approximated a pretax gain of $8.8 million at March 31, 2017. The contracts expire monthly through December 2019. At March 31, 2017, the following commodity-based derivative contracts were outstanding, excluding our basis swaps which are discussed separately below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price

Natural Gas
2017	Swaps ⁽¹⁾	844,245 Mmbtu/day	$ 3.19
2018	Swaps	417,260 Mmbtu/day	$ 3.25
2017	Collars ⁽¹⁾	123,818 Mmbtu/day	$ 3.46–$ 4.12
2018	Collars	7,397 Mmbtu/day	$ 3.40–$ 3.75
2017	Purchased Puts ⁽¹⁾	178,909 Mmbtu/day	$ 3.49 ⁽²⁾
2017	Sold Calls	9,041 Mmbtu/day	$ 3.75 ⁽³⁾

Crude Oil
2017	Swaps ⁽¹⁾	8,782 bbls/day	$ 56.00
2018	Swaps	3,500 bbls/day	$ 53.81
2019	Swaps	250 bbls/day	$ 51.00

NGLs (C2-Ethane)
2017	Swaps	3,000 bbls/day	$ 0.27/gallon
2018	Swaps	124 bbls/day	$ 0.29/gallon

NGLs (C3-Propane)
2017	Swaps	13,895 bbls/day	$ 0.57/gallon
2018	Swaps	7,199 bbls/day	$ 0.65/gallon

NGLs (NC4-Normal Butane)
2017	Swaps	7,750 bbls/day	$ 0.74/gallon
2018	Swaps	4,250 bbls/day	$ 0.81/gallon
NGLs (C5-Natural Gasoline)
2017	Swaps	5,250 bbls/day	$ 1.06/gallon
2018	Swaps	1,500 bbls/day	$ 1.19/gallon

⁽¹⁾ Includes derivative instruments assumed in connection with the MRD Merger.

In addition to the swaps discussed above, we have entered into natural gas basis swap agreements. The price we received for our natural 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 the basis adjustments. The fair value of the basis swaps was a loss of $20.4 million at March 31, 2017. The volumes are for 68,830,000 Mmbtu and they expire monthly through October 2018.

At March 31, 2017, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indices. These contracts settle monthly through December 2018 and include total volume of 1,641,000 barrels in 2017 and 750,000 barrels in 2018. The fair value of these contracts was a gain of $491,000 on March 31, 2017.

At March 31, 2017, we had approximately $3.7 billion of debt outstanding. Of this amount, $2.9 billion bore interest at fixed rates averaging 5.2%. Bank debt totaling $846.0 million bears interest at floating rates, which was 2.5% at March 31, 2017. The 30-day LIBOR Rate on March 31, 2017 was approximately 1.0%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on March 31, 2017 would cost us approximately $8.5 million in additional annual interest expense.

We do not currently utilize any significant off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments, some of which are described above under cash contractual obligations.

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. We expect costs for the remainder of 2017 to continue to be a function of supply.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated.

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivative instruments apply to a varying portion of our production and provide only partial price protection. These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American natural gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Changes in natural gas prices affect us more than changes in oil prices because approximately 65% of our December 31, 2016 proved reserves are natural gas. We are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2016 to March 31, 2017.

We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We typically do not utilize complex derivatives such as three-ways, knockouts or extendable swaps. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program can also include collars, which establish a minimum floor price and a predetermined ceiling price. At March 31, 2017, our derivative program includes swaps and options. These contracts expire monthly through December 2019. The fair value of these contracts, represented by the estimated amount that would be realized upon immediate liquidation as of March 31, 2017, approximated a net unrealized pretax gain of $8.8 million. At March 31, 2017, the following commodity derivative contracts were outstanding, excluding our basis swaps which are discussed below:

Period	Contract Type	Volume Hedged	Weighted Average Hedge Price	Fair Market Value
				(in thousands)
Natural Gas
2017	Swaps ⁽¹⁾	844,245 Mmbtu/day	$ 3.19	$	(25,856	)
2018	Swaps	417,260 Mmbtu/day	$ 3.25	$	(592	)
2017	Collars ⁽¹⁾	123,818 Mmbtu/day	$ 3.46–$ 4.12	$	9,565
2018	Collars	7,397 Mmbtu/day	$ 3.40–$ 3.75	$	85
2017	Purchased Puts ⁽¹⁾	178,909 Mmbtu/day	$ 3.49 ⁽²⁾	$	19,563
2017	Sold Calls	9,041Mmbtu/day	$ 3.75 ⁽³⁾	$	(531	)

Crude Oil
2017	Swaps ⁽¹⁾	8,782 bbls/day	$ 56.00	$	10,314
2018	Swaps	3,500 bbls/day	$ 53.81	$	2,434
2019	Swaps	250 bbls/day	$ 51.00	$	(30	)

NGLs (C2-Ethane)
2017	Swaps	3,000 bbls/day	$ 0.27/gallon	$	380
2018	Swaps	124 bbls/day	$ 0.29/gallon	$	(10	)

NGLs (C3-Propane)
2017	Swaps	13,895 bbls/day	$ 0.57/gallon	$	(9,152	)
2018	Swaps	7,199 bbls/day	$ 0.65/gallon	$	1,519

NGLs (NC4-Normal Butane)
2017	Swaps	7,750 bbls/day	$ 0.74/gallon	$	(1,730	)
2018	Swaps	4,250 bbls/day	$ 0.81/gallon	$	5,305

NGLs (C5-Natural Gasoline)
2017	Swaps	5,250 bbls/day	$ 1.06/gallon	$	(4,581	)
2018	Swaps	1,500 bbls/day	$ 1.19/gallon	$	2,109

⁽¹⁾ Includes derivative instruments assumed in connection with the MRD Merger.

In the future, we expect our NGLs production to continue to increase. We believe NGLs prices are somewhat seasonal, particularly for propane. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional and international markets. If we are not able to sell or store NGLs, we may be required to curtail production or shift our drilling activities to dry gas areas.

Currently, the Appalachian region has limited local demand and infrastructure to accommodate ethane. We have previously announced three ethane agreements wherein we have contracted to either sell or transport ethane from our Marcellus Shale area, two of which began operations in late 2013. Our Mariner East transportation agreement and our terminal/storage arrangements at Sunoco’s Marcus Hook Industrial Complex facility near Philadelphia began ethane operations late in first quarter 2016. We cannot assure you that these facilities will remain available. If we are not able to sell ethane under at least one of these agreements, we may be required to curtail production or, as we have in the past, purchase or divert natural gas to blend with our rich residue gas.

We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. Therefore, in addition to the swaps discussed above, we have entered into natural gas basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX price because of basis adjustments, relative quality and other factors. Basis swap agreements effectively fix the basis adjustments. The fair value of the natural gas basis swaps was a loss of $20.4 million at March 31, 2017 and they settle monthly through October 2018.

At March 31, 2017, we also had propane basis spread contracts which lock in the differential between Mont Belvieu and international propane indices. The contracts settle monthly through December 2018 and include a total volume of 1,641,000 barrels in 2016 and 750,000 barrels in 2018. The fair value of these contracts was a gain of $491,000 on March 31, 2017.

The following table shows the fair value of our swaps and basis swaps and the hypothetical changes in fair value that would result from a 10% and a 25% change in commodity prices at March 31, 2017. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):

				Hypothetical Change in Fair Value						Hypothetical Change in Fair Value
				Increase of						Decrease of
	Fair Value			10%			25%			10%			25%
Swaps	$	(19,890	)	$	(172,869	)	$	(431,951	)	$	174,717		$	437,658
Collars		9,650			(8,049	)		(19,986	)		8,835			23,790
Puts		19,563			(6,885	)		(12,959	)		9,464			28,215
Calls		(531	)		(466	)		(1,491	)		284			469
Basis swaps		(19,891	)		1,657			4,097			(1,745	)		(4,248	)
Freight swap		116			216			540			(217	)		(545	)

Our commodity-based derivative contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified primarily among major investment grade financial institutions and we have master netting agreements with our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At March 31, 2017, our derivative counterparties include twenty-two financial institutions, of which all but five are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While our counterparties are primarily major investment grade financial institutions, the fair value of our derivative contracts has been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial. Our propane sales from the Marcus Hook facility near Philadelphia are short-term and are to a single purchaser. Ethane sales from Marcus Hook are to a single international customer bearing a credit rating similar to Range.

We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior and senior subordinated debt and variable rate bank debt. At March 31, 2017, we had $3.7 billion of debt outstanding. Of this amount, $2.9 billion bears interest at fixed rates averaging 5.2%. Bank debt totaling $846.0 million bears interest at floating rates, which was 2.5% on March 31, 2017. On March 31, 2017, the 30-day LIBOR Rate was approximately 1.0%. A 1% increase in short-term interest rates on the floating-rate debt outstanding on March 31, 2017, would cost us approximately $8.5 million in additional annual interest expense.

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2017 at the reasonable assurance level.

There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

See Note 16 to our unaudited consolidated financial statements entitled “Commitments and Contingencies” included in Part I Item 1 above for a summary of our legal proceedings, such information being incorporated herein by reference.

Our subsidiary, Range Resources – Appalachia, LLC, was notified by the Pennsylvania Department of Environmental Protection (“DEP”), in second quarter 2015, that it intends to assess a civil penalty under the Clean Streams Law and the 2012 Oil and Gas Act in connection with one well in Lycoming County. The DEP has directed us to prevent methane and other substances from escaping from this gas well into groundwater and a stream. We have considerable evidence that this well is not leaking and pre-drill testing of surrounding water wells showed the presence of methane in the water before commencement of our operations. While we intend to vigorously assert this position with the DEP; resolution of this matter may nonetheless result in monetary sanctions of more than $100,000.

We are subject to various risks and uncertainties in the course of our business. In addition to the factors discussed elsewhere in this report, you should carefully consider the risks and uncertainties described under Item 1A. Risk Factors filed in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

Exhibits included in this report are set forth in the Index to Exhibits which immediately precedes such exhibits, and are incorporated herein by reference.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Exhibit Number		Exhibit Description

	3.1	Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004, as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) and the Certificate of Second Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 24, 2008)

	3.2	Amended and Restated By-laws of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 19, 2016)


	31.1*	Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2*	Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1**	Certification by the President and Chief Executive Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	32.2**	Certification by the Chief Financial Officer of Range Resources Corporation Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	101. INS*	XBRL Instance Document

	101. SCH*	XBRL Taxonomy Extension Schema

	101. CAL*	XBRL Taxonomy Extension Calculation Linkbase Document

	101. DEF*	XBRL Taxonomy Extension Definition Linkbase Document

	101. LAB*	XBRL Taxonomy Extension Label Linkbase Document

	101. PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200 Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Large Accelerated Filer	☑	Accelerated Filer	☐

Non-Accelerated Filer	☐ (Do not check if smaller reporting company)	Smaller Reporting Company	☐
		Emerging Growth Company	☐


		Page
PART I – FINANCIAL INFORMATION
ITEM 1.	Financial Statements	3
	Consolidated Balance Sheets (Unaudited)	3
	Consolidated Statements of Operations (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Selected Notes to Consolidated Financial Statements (Unaudited)	6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	40
ITEM 4.	Controls and Procedures	42
PART II – OTHER INFORMATION
ITEM 1.	Legal Proceedings	43
ITEM 1A.	Risk Factors	43
ITEM 6.	Exhibits	43

	SIGNATURES	44

		Three Months Ended March 31, 2016
		As Reported			As Adjusted
	(unaudited)
Statements of Operations
Income tax benefit	$	(44,038	)	$	(41,976	)
Net loss		(91,710	)		(93,772	)
Basic earnings per share		(0.55	)		(0.56	)
Diluted earnings per share		(0.55	)		(0.56	)

		As Reported		As Adjusted
		Net cash provided from operating activities		Net cash provided from operating activities
Three months ended March 31, 2016	$	87,424	$	90,785
Six months ended June 30, 2016		169,604		173,201
Nine months ended September 30, 2016		202,037		205,837

		As Reported			As Adjusted
		Net cash used in financing activities			Net cash used in financing activities
Three months ended March 31, 2016	$	(72,473	)	$	(75,834	)
Six months ended June 30, 2016		(95,411	)		(99,008	)
Nine months ended September 30, 2016		(35,229	)		(39,029	)


	Three Months Ended
		March 31, 2016
Revenues	$	448,933
Net loss	$	(74,616	)

Loss per share:
Basic	$	(0.31	)
Diluted	$	(0.31	)

		March 31, 2017			December 31, 2016
Balance at beginning of period	$	7,412		$	4,161
Additions to capitalized exploratory well costs pending the determination of proved reserves		872			9,128
Reclassifications to wells, facilities and equipment based on determination of proved reserves		—			(5,877	)
Balance at end of period		8,284			7,412
Less exploratory well costs that have been capitalized for a period of one year or less		(8,284	)		(7,412	)
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	—		$	—
Number of projects that have exploration well costs that have been capitalized greater than one year		—			—

	Three Months Ended March 31, 2017
Beginning of period	$	257,943
Acquisition of wells		—
Liabilities incurred		1,645
Liabilities settled		(2,360	)
Disposition of wells		(2,402	)
Accretion expense		3,744
Change in estimate		69
End of period		258,639
Less current portion		(7,271	)
Long-term asset retirement obligations	$	251,368

	Three Months Ended March 31, 2017		Year Ended December 31, 2016
Beginning balance		247,144,356		169,316,460
MRD Merger		—		77,042,749
Restricted stock grants		66,078		490,609
Restricted stock units vested		302,383		266,541
PSU-TSR units settled		19,960		—
Shares retired		—		(739	)
Treasury shares issued		4,000		28,736
Ending balance		247,536,777		247,144,356


		Three Months Ended March 31,
		Derivative Fair Value Income (Loss)
		2017			2016
Commodity swaps	$	166,752		$	79,644
Collars		9,475			—
Puts		6,707			—
Calls		510			—
Basis swaps		(17,972	)		7,275
Freight swaps		85			(11	)
Total	$	165,557		$	86,908

	Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2016		395,908		$	44.39
Units granted ^(a)		83,247			28.31
Units vested		(61,943	)		51.20
Units forfeited		(3,679	)		44.21
Outstanding at March 31, 2017		413,533		$	40.14

		Three Months Ended March 31,
		2017			2016
Risk-free interest rate		1.52	%		0.85	%
Expected annual volatility		44.6	%		51.7	%
Weighted average grant date fair value per unit	$	28.31		$	30.47


	Number of Units			Weighted Average Grant Date Fair Value of Range Stock
Outstanding at December 31, 2016	—			—
Units granted ^(a)	28,851		$	27.23
Units vested	(1,079	)		27.23
Outstanding at March 31, 2017	27,772		$	27.23

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2016		1,003,600		$	69.08
Exercised		—			—
Expired/forfeited		(95,877	)		62.91
Outstanding at March 31, 2017		907,723		$	69.70

		March 31, 2017
Beginning balance at December 31, 2016	$	2,460
Accrued severance costs		2,422
Accrued building rent		28
Payments		(437	)
Ending balance at March 31, 2017	$	4,473

	March 31, 2017			December 31, 2016
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	9,610,244		$	9,462,350
Unproved properties		2,941,103			2,923,803
Total		12,551,347			12,386,153
Accumulated depreciation, depletion and amortization		(3,191,483	)		(3,129,816	)
Net capitalized costs	$	9,359,864		$	9,256,337

RANGE RESOURCES CORPORATION

By:		/s/ ROGER S. MANNY
		Roger S. Manny
		Executive Vice President and Chief Financial Officer

RANGE RESOURCES CORPORATION

By:		/s/ DORI A. GINN
		Dori A. Ginn
		Senior Vice President – Controller and Principal Accounting Officer