0001104659-17-059037.txt : 20170927 0001104659-17-059037.hdr.sgml : 20170927 20170927084829 ACCESSION NUMBER: 0001104659-17-059037 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 10 CONFORMED PERIOD OF REPORT: 20170927 ITEM INFORMATION: Other Events ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20170927 DATE AS OF CHANGE: 20170927 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EQT Corp CENTRAL INDEX KEY: 0000033213 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 250464690 STATE OF INCORPORATION: PA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03551 FILM NUMBER: 171103225 BUSINESS ADDRESS: STREET 1: 625 LIBERTY AVENUE STREET 2: SUITE 1700 CITY: PITTSBURGH STATE: PA ZIP: 15222 BUSINESS PHONE: 4125535700 MAIL ADDRESS: STREET 1: 625 LIBERTY AVENUE STREET 2: SUITE 1700 CITY: PITTSBURGH STATE: PA ZIP: 15222 FORMER COMPANY: FORMER CONFORMED NAME: EQT Corp /PA/ DATE OF NAME CHANGE: 20090206 FORMER COMPANY: FORMER CONFORMED NAME: EQUITABLE RESOURCES INC /PA/ DATE OF NAME CHANGE: 19920703 FORMER COMPANY: FORMER CONFORMED NAME: EQUITABLE GAS CO DATE OF NAME CHANGE: 19841120 8-K 1 a17-22068_28k.htm 8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported): September 27, 2017

EQT CORPORATION

(Exact name of registrant as specified in its charter)

Pennsylvania		1-3551		25-0464690
(State or Other Jurisdiction of Incorporation)		(Commission File Number)		(IRS Employer Identification Number)

625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania 15222

(Address of principal executive offices, including zip code)

(412) 553-5700

(Registrant’s telephone number, including area code)

NONE

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

x Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Item 8.01. Other Events.

EQT Corporation (EQT) is filing this Current Report on Form 8-K to provide certain historical financial information with respect to Rice Energy Inc. (Rice), Vantage Energy LLC and Vantage Energy II, LLC. As previously disclosed in its Current Report on Form 8-K filed on June 19, 2017, EQT entered into an Agreement and Plan of Merger dated as of June 19, 2017 with Rice, providing for the acquisition of Rice by EQT (the Merger).

Included in this Current Report on Form 8-K as Exhibit 99.1 are the audited consolidated financial statements of Rice for the periods described in Item 9.01(a) below, the notes related thereto, the related Report of Independent Registered Public Accounting Firm, each as previously filed by Rice with the Securities and Exchange Commission (SEC). Exhibit 99.1 also includes the information set forth in Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of Rice’s Annual Report on Form 10-K filed with the SEC on March 1, 2017 (the Rice 2016 FY MD&A).

Included in this Current Report on Form 8-K as Exhibit 99.2 are the unaudited condensed consolidated financial statements of Rice for the periods described in Item 9.01(a) below and the notes related thereto, as previously filed by Rice with the SEC. Exhibit 99.2 also includes the information set forth in Item 2 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of Rice’s Quarterly Report on Form 10-Q filed with the SEC on August 3, 2017 (the Rice 2017 Interim MD&A).

Included in this Current Report on Form 8-K as Exhibit 99.3 are the audited consolidated financial statements of Vantage Energy, LLC for the periods described in Item 9.01(a) below, the notes related thereto and the Report of Independent Registered Public Accounting Firm, and included in this filing as Exhibit 99.4 are the unaudited condensed consolidated financial statements of Vantage Energy, LLC for the periods described in Item 9.01(a) below and the notes related thereto, as previously filed with the SEC by Rice.

Included in this filing as Exhibit 99.5 are the audited consolidated financial statements of Vantage Energy II, LLC for the periods described in Item 9.01(a) below, the notes related thereto and the Report of Independent Registered Public Accounting Firm, and included in this filing as Exhibit 99.6 are the unaudited condensed combined financial statements of Vantage Energy II Group for the periods described in Item 9.01(a) below and the notes related thereto, as previously filed with the SEC by Rice.

Item 9.01. Financial Statements and Exhibits.

(a) Financial Statements

· Audited consolidated financial statements of Rice Energy Inc. and its subsidiaries as of December 31, 2016 and 2015 and for each of the years in the three-year period ended December 31, 2016, and the related notes to the consolidated financial statements, included in Exhibit 99.1 hereto.

· Unaudited condensed consolidated financial statements of Rice Energy Inc. and its subsidiaries comprised of the condensed consolidated balance sheets as of December 31, 2016 and June 30, 2017, the related condensed consolidated statements of operations for the three and six months ended June 30, 2017 and 2016, the related condensed consolidated statements of cash flows and equity for the six months ended June 30, 2017 and 2016 and the related notes to the unaudited condensed consolidated financial statements, included in Exhibit 99.2 hereto.

· Audited consolidated financial statements of Vantage Energy, LLC and its subsidiaries as of December 31, 2015 and 2014 and for each of the years in the three-year period ended December 31, 2015, and the related notes to the consolidated financial statements, attached as Exhibit 99.3 hereto.

· Unaudited condensed consolidated financial statements of Vantage Energy, LLC and its subsidiaries comprised of the condensed consolidated balance sheets as of December 31, 2015 and September 30, 2016, the related condensed consolidated statements of operations and cash flows for the nine months ended September 30, 2016 and 2015 and the related notes to the unaudited condensed consolidated financial statements, attached as Exhibit 99.4 hereto.

· Audited consolidated financial statements of Vantage Energy II, LLC and its subsidiaries as of December 31, 2015 and 2014 and for each of the years in the three-year period ended December 31, 2015, and the related notes to the consolidated financial statements, attached as Exhibit 99.5 hereto.

· Unaudited condensed combined financial statements of Vantage Energy II Group and its subsidiaries comprised of the condensed combined balance sheets as of December 31, 2015 and September 30, 2016, the related condensed combined statements of operations and cash flows for the nine months ended September 30, 2016 and 2015 and the related notes to the unaudited condensed combined financial statements, attached as Exhibit 99.6 hereto.

Cautionary Statement Regarding Forward-Looking Information

This communication may contain certain forward-looking statements, including certain plans, expectations, goals, projections, and statements about the benefits of the proposed transaction, EQT’s and Rice’s plans, objectives, expectations and intentions, the expected timing of completion of the transaction, and other statements that are not historical facts. Such statements are subject to numerous assumptions, risks, and uncertainties. Statements that do not describe historical or current facts, including statements about beliefs and expectations, are forward-looking statements. Forward-looking statements may be identified by words such as expect, anticipate, believe, intend, estimate, plan, target, goal, or similar expressions, or future or conditional verbs such as will, may, might, should, would, could, or similar variations. The forward-looking statements are intended to be subject to the safe harbor provided by Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934, and the Private Securities Litigation Reform Act of 1995.

While there is no assurance that any list of risks and uncertainties or risk factors is complete, below are certain factors which could cause actual results to differ materially from those contained or implied in the forward-looking statements including: risks related to our acquisition and integration of acquired businesses and assets; the cost of defending our intellectual property; technological changes and other trends affecting the oil and gas industry; the possibility that the proposed transaction does not close when expected or at all because required regulatory, shareholder or other approvals are not received or other conditions to the closing are not satisfied on a timely basis or at all; the risk that the financing required to fund the transaction is not obtained; potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the transaction; uncertainties as to the timing of the transaction; competitive responses to the transaction; the possibility that the anticipated benefits of the transaction are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies; the possibility that the transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events; diversion of management’s attention from ongoing business operations and opportunities; EQT’s ability to complete the acquisition and integration of Rice successfully; the possibility of litigation relating to the transaction; and other factors that may affect future results of EQT and Rice. Additional factors that could cause results to differ materially from those described above can be found in EQT’s Annual Report on Form 10-K for the year ended December 31, 2016 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, each of which is on file with the SEC and available in the “Investors” section of EQT’s website, https://www.eqt.com/, under the heading “SEC Filings” and in other documents EQT files with the SEC, and in Rice’s Annual Report on Form 10-K for the year ended December 31, 2016 and in its subsequent Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, each of which is on file with the SEC and available in the “Investor Relations” section of Rice’s website, https://www.riceenergy.com/, under the subsection “Financial Information” and then under the heading “SEC Filings” and in other documents Rice files with the SEC.

All forward-looking statements speak only as of the date they are made and are based on information available at that time. Neither EQT nor Rice assumes any obligation to update forward-looking statements to reflect circumstances or events that occur after the date the forward-looking statements were made or to reflect the occurrence of unanticipated events except as required by federal securities laws. As forward-looking statements involve significant risks and uncertainties, caution should be exercised against placing undue reliance on such statements.

Important Additional Information

In connection with the proposed transaction, EQT has filed with the SEC a registration statement on Form S-4 that contains a preliminary joint proxy statement of EQT and Rice and also constitutes a preliminary prospectus of EQT. The registration statement has not yet become effective. After the registration statement is declared effective by the SEC, a definitive joint proxy statement/prospectus will be mailed to the shareholders of EQT and the stockholders of Rice. This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval. SHAREHOLDERS OF EQT AND STOCKHOLDERS OF RICE ARE URGED TO READ THE

REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ANY OTHER RELEVANT DOCUMENTS FILED OR THAT WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY CONTAIN OR WILL CONTAIN IMPORTANT INFORMATION. Investors may obtain a free copy of the registration statement and the joint proxy statement/prospectus, as well as other filings containing information about EQT and Rice, without charge, at the SEC’s website (http://www.sec.gov). Copies of the documents filed with the SEC by EQT can be obtained, without charge, by directing a request to Investor Relations, EQT Corporation, EQT Plaza, 625 Liberty Avenue, Pittsburgh, Pennsylvania 15222-3111, Tel. No. (412) 553-5700. Copies of the documents filed with the SEC by Rice can be obtained, without charge, by directing a request to Investor Relations, Rice Energy Inc., 2200 Rice Drive, Canonsburg, Pennsylvania 15317, Tel. No. (724) 271-7200.

Participants in the Solicitation

EQT, Rice, and certain of their respective directors, executive officers and employees may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding EQT’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on February 17, 2017, and certain of its Current Reports on Form 8-K. Information regarding Rice’s directors and executive officers is available in its definitive proxy statement, which was filed with the SEC on April 17, 2017, and certain of its Current Reports on Form 8-K. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, is contained in the preliminary joint proxy statement/prospectus of EQT and Rice filed with the SEC and will be contained in the definitive joint proxy statement/prospectus of EQT and Rice and other relevant materials filed with the SEC. Free copies of this document may be obtained as described in the preceding paragraph.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.		Description
23.1		Consent of Ernst & Young LLP.

23.2		Consent of KPMG LLP.

23.3		Consent of KPMG LLP.

99.1		Audited consolidated financial statements of Rice Energy Inc. and its subsidiaries, together with the Rice 2016 FY MD&A.

99.2		Unaudited condensed consolidated financial statements of Rice Energy Inc. and its subsidiaries, together with the Rice 2017 Interim MD&A.

99.3		Audited consolidated financial statements of Vantage Energy, LLC.

99.4		Unaudited condensed consolidated financial statements of Vantage Energy, LLC.

99.5		Audited consolidated financial statements of Vantage Energy II, LLC.

99.6		Unaudited condensed combined financial statements of Vantage Energy II Group.

EXHIBIT INDEX

Exhibit No.		Description
23.1		Consent of Ernst & Young LLP.

23.2		Consent of KPMG LLP.

23.3		Consent of KPMG LLP.

99.1		Audited consolidated financial statements of Rice Energy Inc. and its subsidiaries, together with the Rice 2016 FY MD&A.

99.2		Unaudited condensed consolidated financial statements of Rice Energy Inc. and its subsidiaries, together with the Rice 2017 Interim MD&A.

99.3		Audited consolidated financial statements of Vantage Energy, LLC.

99.4		Unaudited condensed consolidated financial statements of Vantage Energy, LLC.

99.5		Audited consolidated financial statements of Vantage Energy II, LLC.

99.6		Unaudited condensed combined financial statements of Vantage Energy II Group.

SIGNATURES

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 hereunto duly authorized.

	EQT CORPORATION

Dated: September 27, 2017	By:	/s/ Robert J. McNally
	Name:	Robert J. McNally
	Title:	Senior Vice President and Chief Financial Officer

EX-23.1 2 a17-22068_2ex23d1.htm EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

· Registration Statement (Form S-4 No. 333-219508) and related prospectus of EQT Corporation pertaining to the shares of EQT Corporation common stock to be issued in the merger with Rice Energy Inc.,

· Registration Statement (Form S-3 No. 333-158198) pertaining to the 2009 Dividend Reinvestment and Stock Purchase Plan,

· Registration Statement (Form S-3 No. 333-214092) pertaining to the registration of Debt Securities, Preferred Stock and Common Stock,

· Registration Statement (Form S-8 No. 333-185845) pertaining to the Employee Savings Plan,

· Registration Statement (Form S-8 No. 333-82193) pertaining to the 1999 Non-Employee Directors’ Stock Incentive Plan,

· Registration Statement (Form S-8 No. 333-32410) pertaining to the Deferred Compensation Plan and the Directors’ Deferred Compensation Plan,

· Registration Statement (Form S-8 No. 333-122382) pertaining to the 2005 Employee Deferred Compensation Plan and the 2005 Directors’ Deferred Compensation Plan,

· Registration Statement (Form S-8 No. 333-152044) pertaining to the 2008 Employee Stock Purchase Plan,

· Registration Statement (Form S-8 No. 333-158682) pertaining to the 2009 Long-Term Incentive Plan, and

· Registration Statement (Form S-8 No. 333-195625) pertaining to the 2014 Long-Term Incentive Plan

of our reports dated March 1, 2017, with respect to the consolidated financial statements of Rice Energy Inc. and the effectiveness of internal control over financial reporting of Rice Energy Inc., included in this Current Report (Form 8-K) of EQT Corporation, filed with the Securities and Exchange Commission.

/s/Ernst & Young LLP
Pittsburgh, Pennsylvania
September 27, 2017

EX-23.2 3 a17-22068_2ex23d2.htm EX-23.2

Exhibit 23.2

Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statement (File No. 333-219508) on Form S-4, in the registration statements (File Nos. 333-158198 and 333-214092) on Form S-3, and the registration statements (File Nos. 333-185845, 333-82193, 333-32410, 333-122382, 333-152044, 333-158682 and 333-195625) on Form S-8 of EQT Corporation of our report dated July 26, 2016, with respect to the consolidated financial statements of Vantage Energy, LLC, which comprise the consolidated balance sheets as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015, which report appears in the accompanying Form 8-K of EQT Corporation.

/s/ KPMG LLP

Denver, Colorado
September 27, 2017

EX-23.3 4 a17-22068_2ex23d3.htm EX-23.3

Exhibit 23.3

Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statement (File No. 333-219508) on Form S-4, in the registration statements (File Nos. 333-158198 and 333-214092) on Form S-3, and the registration statements (File Nos. 333-185845, 333-82193, 333-32410, 333-122382, 333-152044, 333-158682 and 333-195625) on Form S-8 of EQT Corporation of our report dated July 26, 2016, with respect to the consolidated financial statements of Vantage Energy II, LLC, which comprise the consolidated balance sheets as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015, which report appears in the accompanying Form 8-K of EQT Corporation.

/s/ KPMG LLP

Denver, Colorado
September 27, 2017

EX-99.1 5 a17-22068_2ex99d1.htm EX-99.1

Exhibit 99.1

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described in “Item 1A. Risk Factors” included elsewhere in this Annual Report. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview of Our Business

Rice Energy is an independent natural gas and oil company focused on the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. As a result of changes to our operations and organizational structure in 2016, we now manage our business in three operating segments - the Exploration and Production segment, the Rice Midstream Holdings segment and the Rice Midstream Partners segment. These segments are managed separately due to their distinct operational differences. The Exploration and Production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGLs. The Rice Midstream Holdings segment is engaged in the gathering and compression of natural gas, oil and NGL production for us and third parties in Belmont and Monroe Counties, Ohio. The Rice Midstream Partners segment is engaged in the gathering and compression of natural gas, oil and NGL production in Washington and Greene Counties, Pennsylvania, and in the provision of water services to support the well completion services of us and third parties in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio.

As a result of certain reorganizations and transactions that occurred during 2014, 2015 and 2016, our historical financial condition and results of operations for the periods presented in this Annual Report may not be comparable, either from period to period or going forward. For example, information for the period from January 1, 2014 until January 29, 2014, as contained within the year ended December 31, 2014 pertains to the historical financial statements and results of operations of Rice Drilling B LLC, our accounting predecessor. Such periods reflect only our 50% equity investment in our Marcellus joint venture. From and after our acquisition of the remaining 50% interest from Alpha Holdings on January 29, 2014, the results of operations of our Marcellus joint venture are consolidated into our results of operations.

In connection with the RMP IPO in December 2014, we contributed to RMP all of our gas gathering and compression assets in Washington and Greene Counties, Pennsylvania in exchange for, among other things, common and subordinated units representing a 50% limited partner interest and all of the incentive distribution rights in RMP. Indirectly, through Midstream Holdings, we own and control the general partner of RMP, and, as such, the results of operations of RMP are consolidated into our results of operations. However, while our results of operations consolidate the results of operations of RMP for periods subsequent to December 22, 2014, they give effect to the noncontrolling interest in RMP held by its public unitholders.

Also in connection with the RMP IPO, we entered into various gas gathering and compression agreements and water distribution services agreements, both intercompany and, in the case of certain gas gathering and compression services in Pennsylvania, with RMP. Prior to December 22, 2014, with certain limited exceptions, the Rice Midstream Holdings segment and the Rice Midstream Partners segment did not charge fees for providing such services to our Exploration and Production segment. From December 22, 2014 through October 31, 2015, the Rice Midstream Holdings segment charged the Exploration and Production segment water services fees according to the water services agreements entered into in connection with the RMP IPO. Beginning on November 1, 2015, as a result of the closing of the acquisition of PA Water and OH Water by RMP, the Rice Midstream Partners segment charges the Exploration and Production segment water services fees according to certain water services agreements entered in connection with the acquisition. These gathering and water services fees are eliminated through consolidation.

Following completion of the Vantage Acquisition, we operate Vantage through Rice Energy Operating. As part of the consideration for the Vantage Acquisition, the Vantage Sellers were issued common units in Rice Energy Operating. In connection with the issuance of such membership interests to the Vantage Sellers, us and the Vantage Sellers entered into the Third A&R LLC Agreement. Under the Third A&R LLC Agreement, we control all of the day-to-day business affairs and decision making of Rice Energy Operating without approval of any other member, unless otherwise stated in the Third A&R LLC Agreement. As such, we, through our officers and directors, are responsible for all operational and administrative decisions of Rice Energy Operating and the day-to-day management of Rice Energy Operating’s business. Pursuant to the terms of the Third A&R LLC Agreement, we cannot, under any circumstances, be removed or replaced as the sole manager of Rice Energy Operating, except by our own election so long as it remains a member of Rice Energy Operating.

Sources of Revenues

The substantial majority of our revenues are derived from the sale of natural gas and do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in realized prices. Our gathering, compression and water services revenues are primarily derived from our gathering and compression contracts in addition to fees charged to outside working interest owners.

The following table provides detail of our operating revenues from the consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014.

	Years Ended December 31,
(in thousands)	2016		2015		2014
Natural gas sales	$	646,531	$	441,082	$	354,860
Oil and NGL sales	6,910		5,433		4,341
Gathering, compression and water services	101,057		49,179		5,504
Other revenue	24,408		6,447		26,237
Total operating revenues	$	778,906	$	502,141	$	390,942

NYMEX Henry Hub prompt month contract prices are widely-used benchmarks in the pricing of natural gas. The following table provides the high and low prices for NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated.

	Years Ended December 31,
	2016			2015			2014
NYMEX Henry Hub High ($/MMBtu)	$	3.77		$	3.30		$	7.94
NYMEX Henry Hub Low ($/MMBtu)	$	1.64		$	1.76		$	2.75

NYMEX Henry Hub Price ($/MMBtu)	$	2.46		$	2.64		$	4.32
Less: Average Basis Impact ($/MMBtu) (1)	(0.42		)	(0.54		)	(0.84		)
Plus: Btu Uplift (MMBtu/Mcf)	0.10			0.11			0.17
Pre-Hedge Realized Price ($/Mcf)	$	2.14		$	2.21		$	3.65

(1) Differential is calculated by comparing the average NYMEX Henry Hub price to our volume weighted average realized price per MMBtu before hedges, including 50% of the volumes sold by our Marcellus joint venture for the period from January 1, 2014 through January 28, 2014, contained within the year ended December 31, 2014. The remainder of the year ended December 31, 2014 reflects 100% of the volumes sold by our Marcellus joint venture.

We sell a substantial majority of our production to two natural gas marketers, Sequent and BP. For the year ended December 31, 2016, sales to Sequent and BP represented 25% and 24% of our total sales, respectively. If our natural gas marketers decided to stop purchasing natural gas from us, our revenues could decline and our operating results and financial condition could be harmed. Although a substantial portion of production is purchased by these customers, we do not believe the loss of these customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.

For the year ended December 31, 2016, our Exploration and Production segment accounted for 87% of our operating revenues. While we anticipate that the Rice Midstream Holdings segment and the Rice Midstream Partners segment will continue to represent a meaningful portion of our operating revenues in future periods, we expect that a substantial majority of our operating revenues will remain attributable to our Exploration and Production segment.

Principal Components of Our Cost Structure

· Lease operating expense. These are the day to day operating costs incurred to maintain production of our natural gas producing wells. Such costs include field personnel costs, produced water disposal, maintenance and repairs. Cost levels for these expenses can vary based on supply and demand for oilfield services.

· Gathering, compression and transportation. These are costs incurred to bring natural gas to the market. Such costs include fees paid to third parties who operate low- and high-pressure gathering systems that transport our natural gas. We often enter into firm transportation contracts that secure takeaway capacity that includes minimum volume commitments, the cost for which is included in these expenses.

· Midstream operation and maintenance. These are costs incurred to operate and maintain our low- and high-pressure natural gas gathering and compression systems and our water services assets used to support well completion activities and to collect and recycle or dispose of flowback and produced water.

· Incentive unit expense. These costs represent non-cash compensation expense for incentive units awarded to certain of our employees by NGP Holdings and Rice Holdings. In connection with our IPO and related corporate reorganization, the holders of incentive units in REO contributed a portion of their incentive units to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. This resulted in the incentive units being deemed to have been modified, and the performance conditions were considered to be probable of occurring. Therefore, their fair values were measured and compensation expense from the date of initial grant through December 31, 2016 has been recognized in the year ended December 31, 2016. The payment obligation as it relates to the incentive units resides with NGP Holdings and Rice Holdings and has not been, and will not be borne by us. In April 2016, NGP Holdings settled its remaining incentive unit obligation in connection with our April 2016 Equity Offering. No future expense will be recognized related to the NGP Holdings incentive units.

· General and administrative expense. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our exploration and production operations, midstream operations, franchise taxes, audit and other professional fees and legal compliance expenses. General and administrative expense also includes stock-based compensation expense related to awards granted under our long-term incentive plan. Please see “Note 16- Stock-Based Compensation” in the notes of the consolidated financial statements under Item 8 of this Annual Report.

· Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs to each unit of production using the units of production method.

· Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our revolving credit facilities and our Notes. As a result, we incur interest expense that is affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and our financing decisions. We will likely continue to incur significant interest expense as we continue to grow. To date, we have not entered into any interest rate hedging arrangements to mitigate the effects of interest rate changes.

· Gain on derivative instruments. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are recorded at fair value at each balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

· Income tax expense. We are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings. The reorganization of our business into a corporation in connection with the closing of our IPO required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of our IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of our IPO. Based on our deductions primarily related to intangible drilling costs (“IDCs”), we could potentially generate significant net operating loss assets and deferred tax liabilities. We may report and pay state income or franchise taxes in periods where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.

How We Evaluate Our Operations

In evaluating our financial results, we focus on production, revenues, per unit cash production costs and general and administrative (“G&A”) expenses. We also evaluate our rates of return on invested capital in our wells, and we measure the expected return of our wells based on EUR and the related costs of acquisition, development and production.

We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our core acreage position in the Marcellus and Utica Shales. Additionally, by focusing on concentrated acreage positions, we can build and own centralized midstream infrastructure, including low- and high-pressure gathering lines, compression facilities and water pipeline systems, which enable us to reduce reliance on third-party operators, minimize costs and increase our returns.

Consolidated Results of Operations

Below are some highlights of our consolidated financial and operating results for the years ended December 31, 2016, 2015 and 2014:

· Our natural gas, oil and NGL sales were $653.4 million, $446.5 million and $359.2 million in the years ended December 31, 2016, 2015 and 2014, respectively.

· Our production volumes were 304.4 Bcfe, 201.3 Bcfe and 97.7 Bcfe in the years ended December 31, 2016, 2015 and 2014, respectively.

· Our gathering, compression and water services revenues were $101.1 million, $49.2 million and $5.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.

· Our per unit cash production costs were $0.63 per Mcfe, $0.68 per Mcfe and $0.67 per Mcfe in the years ended December 31, 2016, 2015 and 2014, respectively.

The following tables set forth selected operating and financial data for the year ended December 31, 2016 compared to the year ended December 31, 2015 and the year ended December 31, 2015 compared to the year ended December 31, 2014:

	Year Ended December 31,							Year Ended December 31,
	2016		2015		Change			2015		2014		Change
Natural gas sales (in thousands)	$	646,531	$	441,082	$	205,449		$	441,082	$	354,860	$	86,222
Oil and NGL sales (in thousands)	6,910		5,433		1,477			5,433		$	4,341	1,092
Natural gas, oil and NGL sales (in thousands)	$	653,441	$	446,515	$	206,926		$	446,515	$	359,201	$	87,314

Natural gas production (MMcf)	302,322		199,831		102,491			199,831		97,172		102,659
Oil and NGL production (MBbls)	354		249		105			249		94		155
Total production (MMcfe)	304,443		201,328		103,115			201,328		97,737		103,591

Average natural gas prices before effects of hedges per Mcf	$	2.14	$	2.21	$	(0.07	)	$	2.21	$	3.65	$	(1.44	)
Average realized natural gas prices after effects of hedges per Mcf (1)	2.83		3.18		(0.35		)	3.18		3.46		(0.28		)
Average oil and NGL prices per Bbl	19.55		21.79		(2.24		)	21.79		46.07		(24.28		)

Average costs per Mcfe
Lease operating	$	0.17	$	0.22	$	(0.05	)	$	0.22	$	0.26	$	(0.04	)
Gathering, compression and transportation	0.41		0.42		(0.01		)	0.42		0.36		0.06
Production taxes and impact fees	0.05		0.04		0.01			0.04		0.05		(0.01		)
General and administrative	0.39		0.51		(0.12		)	0.51		0.63		(0.12		)
Depreciation, depletion and amortization	1.21		1.60		(0.39		)	1.60		1.60		—

Total gathering, compression and water service revenues (in thousands):	$	101,057	$	49,179	$	51,878		$	49,179	$	5,504	$	43,675
Gathering volumes (MDth/d):	1,691		894		797			894		402		492
Compression volumes (MDth/d):	1,007		115		892			115		—		115
Water services volumes (MMgal):	1,253		777		476			777		—		777

(1) The effect of hedges includes realized gains and losses on commodity derivative transactions.

(in thousands, except per	Year Ended December 31,							Year Ended December 31,
share data)	2016		2015		Change			2015		2014		Change
Operating revenues:
Natural gas, oil and NGL sales	$	653,441	$	446,515	$	206,926		$	446,515	$	359,201	$	87,314
Gathering, compression and water services	101,057		49,179		51,878			49,179		5,504		43,675
Other revenue	24,408		6,447		17,961			6,447		26,237		(19,790		)
Total operating revenues	778,906		502,141		276,765			502,141		390,942		111,199

Operating expenses:
Lease operating	50,574		44,356		6,218			44,356		24,971		19,385
Gathering, compression and transportation	123,852		84,707		39,145			84,707		35,618		49,089
Production taxes and impact fees	13,866		7,609		6,257			7,609		4,647		2,962
Exploration	15,159		3,137		12,022			3,137		4,018		(881		)
Midstream operation and maintenance	23,215		16,988		6,227			16,988		4,607		12,381
Incentive unit expense	51,761		36,097		15,664			36,097		105,961		(69,864		)
Impairment of gas properties	20,853		18,250		2,603			18,250		—		18,250
Impairment of goodwill	—		294,908		(294,908		)	294,908		—		294,908
Impairment of fixed assets	23,057		—		23,057			—		—		—
General and administrative	118,093		103,038		15,055			103,038		61,570		41,468
Depreciation, depletion and amortization	368,455		322,784		45,671			322,784		156,270		166,514
Acquisition expense	6,109		1,235		4,874			1,235		2,339		(1,104		)
Amortization of intangible assets	1,634		1,632		2			1,632		1,156		476
Other expense	27,308		5,567		21,741			5,567		207		5,360
Total operating expenses	843,936		940,308		(96,372		)	940,308		401,364		538,944

(in thousands, except per	Year Ended December 31,									Year Ended December 31,
share data)	2016			2015			Change			2015			2014			Change
Operating loss	(65,030		)	(438,167		)	373,137			(438,167		)	(10,422		)	(427,745		)
Interest expense	(99,627		)	(87,446		)	(12,181		)	(87,446		)	(50,191		)	(37,255		)
Gain on purchase of Marcellus joint venture	—			—			—			—			203,579			(203,579		)
Other income	1,406			1,108			298			1,108			893			215
(Loss) gain on derivative instruments	(220,236		)	273,748			(493,984		)	273,748			186,477			87,271
Amortization of deferred financing costs	(7,545		)	(5,124		)	(2,421		)	(5,124		)	(2,495		)	(2,629		)
Loss on extinguishment of debt	—			—			—			—			(7,654		)	7,654
Write-off of deferred financing costs	—			—			—			—			(6,896		)	6,896
Equity in loss of joint ventures	—			—			—			—			(2,656		)	2,656
Income (loss) before income taxes	(391,032		)	(255,881		)	(135,151		)	(255,881		)	310,635			(566,516		)
Income tax benefit (expense)	142,212			(12,118		)	154,330			(12,118		)	(91,600		)	79,482
Net (loss) income	(248,820		)	(267,999		)	19,179			(267,999		)	219,035			(487,034		)
Less: Net income attributable to noncontrolling interests	(20,931		)	(23,337		)	2,406			(23,337		)	(581		)	(22,756		)
Net (loss) income attributable to Rice Energy Inc.	(269,751		)	(291,336		)	21,585			(291,336		)	218,454			(509,790		)
Less: Preferred dividends and accretion of redeemable noncontrolling interests	(28,450		)	—			(28,450		)	—			—			—
Net (loss) income attributable to Rice Energy Inc. common stockholders	$	(298,201	)	$	(291,336	)	$	(6,865	)	$	(291,336	)	$	218,454		$	(509,790	)

(in thousands, except per	Year Ended December 31,								Year Ended December 31,
share data)	2016			2015			Change		2015			2014		Change
Weighted average number of shares of common stock - basic	162,226			136,344			25,882		136,344			128,151		8,193
Weighted average number of shares of common stock - diluted	162,226			136,344			25,882		136,344			128,225		8,119
(Loss) income earnings per share-basic	$	(1.84	)	$	(2.14	)	$	0.30	$	(2.14	)	$	1.70	$	(3.84	)
(Loss) income earnings per share-diluted	$	(1.84	)	$	(2.14	)	$	0.30	$	(2.14	)	$	1.70	$	(3.84	)

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Total operating revenues. The $276.8 million increase in total operating revenues was mainly a result of a 51% increase in natural gas, oil and NGL production from 201.3 Bcfe in 2015 to 304.4 Bcfe in 2016. During 2016, we turned 70 gross (63 net) wells into sales, of which 14 gross (14 net) wells were acquired in the Vantage Acquisition. The increase in operating revenues was slightly offset by a decrease in realized prices. Our realized price in 2016 was $2.14 per Mcf compared to $2.21 per Mcf in 2015, in each case before the effect of hedges. Operating revenues were also positively impacted by a $51.9 million, or 105%, increase in gathering, compression and water service revenues year-over-year. This increase primarily relates to an increase in third-party volumes and revenues on our gathering contracts. In addition, post-acquisition revenue associated with the Vantage Acquisition was $51.6 million for the period from October 19, 2016 through December 31, 2016.

Lease operating expenses. The $6.2 million increase in lease operating expenses was attributable to an increase in our production base in 2016 as compared to the prior year. However, on a per unit basis, lease operating expenses decreased from $0.22 for the year ended December 31, 2015 to $0.17 for the year ended December 31, 2016. The decrease on a per unit basis was attributable to improved efficiencies, primarily relating to production water recycling and reduced flowback periods.

Gathering, compression and transportation. Gathering, compression and transportation expense for 2016 of $123.9 million was mainly comprised of $105.1 million of transportation contracts with third parties and $19.3 million of gathering charges from third parties. The $39.1 million, or 46%, increase in expense was primarily attributable to a

51% increase in production volumes, as well as increased firm transportation expense for the year ended December 31, 2016.

Exploration. The increase in exploration expense year over year of $12.0 million was primarily due to leasehold write-offs, mainly associated with expired leaseholds.

Midstream operation and maintenance. The $6.2 million increase in midstream operation and maintenance expense in 2016 compared to the prior year was primarily due to on and off pad water transfer costs and water procurement, in addition to increased expenses following the Vantage Midstream Asset Acquisition primarily associated with water transfer and pipeline maintenance costs. On a per unit basis, midstream operation and maintenance expense was $0.08 for the years ended December 31, 2016 and 2015.

Incentive unit expense. Incentive unit expense increased $15.7 million in 2016 compared to 2015. In 2016, the $51.8 million expense consisted of $24.5 million of non-cash compensation expense related to the Rice Holdings incentive units and $27.3 million of compensation expense related to a cumulative adjustment to equal the cumulative cash payment made by NGP Holdings to NGP Holdings incentive unitholders. In 2015, the $36.1 million expense consisted of $33.7 million of non-cash compensation expense related to the Rice Holdings incentive units and $26.7 million related to payments made to certain holders of NGP Holdings incentive units, offset by $24.3 million of non-cash income related to the fair market value adjustment for the NGP Holdings incentive units which was largely driven by the decline in our stock price as of December 31, 2015. No future expense will be recognized related to the NGP Holdings incentive units as a result of the April 2016 settlement of the remaining NGP Holdings incentive unit obligation. See “Item 1. Financial Statements-Notes to Consolidated Financial Statements-14. Incentive Units” for additional information.

Impairment of gas properties. For the years ended December 31, 2016 and 2015, we recorded $20.9 million and $18.2 million, respectively, in impairment expense related to our gas properties. In 2016, we recognized $20.9 million of impairment expense in the consolidated statement of operations related to lease expirations on non-core assets. In 2015, we determined that the carrying value of our Upper Devonian proved property was not fully recoverable and as a result, we recognized a $10.9 million impairment expense to write-down such proved properties to fair value. In addition, we recognized $7.3 million of impairment expense in 2015 due to changes in our development plans and lease expirations.

Impairment of goodwill. The $294.9 million impairment of goodwill in 2015 related to a full impairment of goodwill associated with our Exploration and Production segment. In performing the annual goodwill impairment analysis, management considered the negative industry and market trends, including the decline in commodity prices and overall market performance of our peers and ourselves, to be the primary reasons of impairment.

Impairment of fixed assets. The $23.1 million impairment expense in 2016 was primarily related to a $20.3 million impairment for pipeline assets that were decommissioned.

General and administrative expense. For the year ended December 31, 2016, general and administrative expense (before stock compensation expense) increased $10.3 million, or 12%, primarily due to the additions of personnel to support our growth activities and related salary and employee benefits. At December 31, 2016, we had 467 employees, a 26% increase compared to December 31, 2015. Additionally, general and administrative expenses increased year-over-year due to an increase in rent expense primarily related to our office leases. On a per unit basis, general and administrative expense (before stock compensation expense) decreased by 26%, from $0.43 per Mcfe during the year ended December 31, 2015 to $0.32 per Mcfe during the year ended December 31, 2016, primarily due to a 51% increase in production. Slightly offsetting the increase in general and administrative expenses was an increase in allocated employee time to capital projects due to increased production.

Included in general and administrative expense is stock compensation expense of $21.3 million and $16.5 million for the years ended December 31, 2016 and December 31, 2015, respectively. The increase is primarily attributable to increased compensation expense associated with restricted stock unit and performance stock unit awards. Please see “Note 16-Stock-Based Compensation” in the notes to the consolidated financial statements in Item 8 of this Annual Report for further information on these awards.

DD&A. The $45.7 million increase in DD&A expense was a result of an increase in production driven by a greater number of producing wells in 2016 compared to 2015. As of December 31, 2016, we had 282 net producing Appalachian wells, an 97% increase when compared to the number of producing wells as of December 31, 2015. In addition, the increase in DD&A was the result of an increase in midstream assets placed in service in 2016 as compared to the prior year and the related depreciation of those assets. As of December 31, 2016, we had 251 miles and 129 miles of gas gathering and water pipeline, respectively, an increase of 50% and 15%, respectively, when compared to the prior year. On a per unit basis, DD&A expense decreased $0.39, or 24%, from $1.60 for the year ended December 31, 2015 to $1.21 for the year ended December 31, 2016.

Acquisition expense. The $4.9 million increase in acquisition expense was primarily attributable to costs associated with the Vantage Acquisition.

Interest expense. The $12.2 million increase in interest expense was primarily attributable to a full year recognition of expense associated with the prior year issuance of $400.0 million of the 2023 Notes. In addition, interest expense increased due to higher average borrowings on our revolving credit facilities during 2016 as compared to 2015 in order to fund our capital expenditures.

(Loss) gain on derivative instruments. The $220.2 million loss on derivative contracts in 2016 was due to net cash receipts of $210.5 million on the settlement of maturing contracts and offset by a $430.8 million unrealized loss. The $273.7 million gain on derivative contracts in 2015 was due to net cash receipts of $193.9 million and a $79.8 million unrealized gain.

Income tax benefit (expense). The $154.3 million decrease in income tax expense year-over-year was driven by our net pre-tax loss, creating an income tax benefit for the year ended December 31, 2016.

Noncontrolling interest. The $2.4 million decrease in net income attributable to noncontrolling interest was attributable to a $54.5 million loss from noncontrolling interest associated with the 16.49% of membership interests in Rice Energy Operating the Vantage Sellers received in connection with the Vantage Acquisition. Offsetting the loss from noncontrolling interest was a decrease in Rice Energy Operating’s indirect ownership in RMP from 41% as of December 31, 2015 to 26% as of December 31, 2016. The decrease in ownership percentage year-over-year was primarily attributable to RMP’s June 2016 and October 2016 equity offerings. In addition, the increase in RMP’s net income year-over-year from $52.5 million in 2015 to $121.6 million in 2016 contributed to the $20.9 million net income in noncontrolling interest balance as of December 31, 2016.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Total operating revenues. The $111.2 million increase in total operating revenues was mainly a result of an increase in natural gas, oil and NGL production in 2015 compared to 2014. The increase in production was a result of increased drilling and completion activity in 2015, mainly in Washington County, Pennsylvania and Belmont County, Ohio. The impact of increased production volumes on operating revenues was offset by a decrease in realized prices. Our realized price in 2015 was $2.21 per Mcf compared to $3.65 per Mcf in 2014, in each case before the effect of hedges. Additionally, operating revenues were positively impacted by a $43.7 million increase in gathering, compression and water service revenues year-over-year. This increase primarily relates to increased third-party volumes and revenues on new gathering contracts. The increase in operating revenues for 2015 were offset by a $22.8 million decrease year-over-year in firm transportation sales, net, from the sale of unutilized capacity as we further utilize our existing contracts for our own operated production.

Lease operating expenses. The $19.4 million increase in lease operating expenses is attributable to an increase in the number of producing wells in 2015 as compared to 2014. However, lease operating expenses per unit of production decreased year-over-year due to improved efficiencies, primarily relating to production water recycling.

Gathering, compression and transportation. Gathering, compression and transportation expense for 2015 of $84.7 million is mainly comprised of $68.2 million of transportation contracts with third parties, $8.3 million of gathering charges from third parties and $4.2 million of charges from our working interest partners on our

non-operated wells. The $49.1 million increase in expense was primarily attributable to increased firm transportation contracts in 2015 compared to 2014, which is consistent with increased production.

Midstream operation and maintenance. The $12.4 million increase in midstream operation and maintenance expense in 2015 compared to 2014 was primarily due to additional contract labor costs, additional leases and on compression equipment and utility costs incurred as a result of our continued midstream build-out.

Incentive unit expense. Incentive unit expense decreased $69.9 million in 2015 compared to 2014. In 2014, the $106.0 million expense primarily consisted of $44.5 million and $41.7 million of non-cash compensation expense related to the Rice Holdings and NGP Holdings incentive units, respectively, $3.4 million of non-cash compensation expense related to extinguishment of the legacy incentive unit burden of Mr. Daniel J. Rice III and $16.4 million related to payments made to certain holders of NGP Holdings incentive units. In 2015, the $36.1 million expense consisted of $33.7 million of non-cash compensation expense related to the Rice Holdings incentive units and $26.7 million related to payments made to certain holders of NGP Holdings incentive units, offset by $24.3 million of non-cash income related to the fair market value adjustment for the NGP Holdings incentive units which was largely driven by the decline in our stock price at December 31, 2015. See “Item 8. Financial Statements and Supplementary Data-Notes to Consolidated Financial Statements-14. Incentive Units” for additional information.

General and administrative expense. The $41.5 million increase in general and administrative expense was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits. At December 31, 2015, we had 371 employees as compared to 290 employees at December 31, 2014. Additionally, general and administrative expenses increased year-over-year as a result of the costs associated with our accounting system implementation and information technology projects to support our growth activities. Included in general and administrative expense is stock compensation expense of $16.5 million and $5.6 million for the years ended December 31, 2015 and December 31, 2014, respectively.

DD&A. The $166.5 million increase in DD&A expense was a result of an increase in production driven by a greater number of producing wells in 2015 compared to 2014, which is consistent with our expanded drilling program and increased production during the year. In addition, the increase was the result of an increase in midstream assets placed in service in 2015 as compared to 2014 and the related depreciation of those assets.

Interest expense. The $37.3 million increase in interest expense was a result of our issuance of $400.0 million of the 2023 Notes and borrowings under our revolving credit facilities to fund midstream capital expenditures in 2015.

Gain on purchase of Marcellus joint venture. The $203.6 million gain on acquisition in the first quarter of 2014 was attributable to our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture in connection with the closing of our IPO. As a result of our acquisition of the remaining 50% ownership in our Marcellus joint venture, we were required to remeasure our equity investment at fair value, which resulted in the non-recurring gain.

Gain on derivative instruments. The $273.7 million gain on derivative contracts in 2015 was due to net cash receipts of $193.9 million on the settlement of maturing contracts and a $79.8 million unrealized gain. The $186.5 million gain on derivative contracts in 2014 was due to net cash payments of $18.8 million and a $205.3 million unrealized gain.

Equity in income (loss) of joint ventures. The $2.7 million decrease in equity income of joint ventures is the result of our acquisition of the remaining 50% interest in our Marcellus joint venture in January 2014, as we consolidate the operations of our Marcellus joint venture subsequent to the acquisition.

Income tax expense. The $79.5 million decrease in income tax expense year-over-year was attributable to a decrease in taxable income and a lower estimated annual effective tax rate.

Noncontrolling interest. The $22.8 million increase in net income attributable to noncontrolling interest was primarily attributable to us recognizing a full year of noncontrolling interest related to our investment in RMP as compared to the 10-day period in 2014.

Business Segment Results of Operations

As a result of changes to our operations and organizational structure in the first quarter of 2016, we now manage our business in three business segments: Exploration and Production, Rice Midstream Holdings and Rice Midstream Partners. We evaluate our business segments based on their contribution to our consolidated results based on operating income. Please see “Note 8-Financial Results by Business Segment” in the notes to the consolidated financial statements in Item 8 of this Annual Report for a break-down of the operating results and assets of our business segments for the years ended December 31, 2016, 2015 and 2014. All prior period results have been revised to reflect the new reporting segment structure.

The following tables set forth selected operating and financial data for each business segment for the year ended December 31, 2016 compared to the year ended December 31, 2015 and the year ended December 31, 2015 compared to the year ended December 31, 2014:

Exploration and Production Segment

(in thousands, except	Year ended December 31,							Year ended December 31,
volumes)	2016		2015		Change			2015		2014		Change
Operating revenues:
Natural gas, oil and NGL sales	$	653,441	$	446,515	$	206,926		$	446,515	$	359,201	$	87,314
Other revenue	24,408		6,447		17,961			6,447		26,237		(19,790		)
Total operating revenues	677,849		452,962		224,887			452,962		385,438		67,524

Operating expenses:
Lease operating	50,708		44,356		6,352			44,356		24,971		19,385
Gathering, compression and transportation	232,478		150,015		82,463			150,015		37,414		112,601
Production taxes and impact fees	13,866		7,609		6,257			7,609		4,647		2,962
Exploration	15,159		3,137		12,022			3,137		4,018		(881		)
Incentive unit expense	49,426		33,873		15,553			33,873		86,020		(52,147		)
Impairment of gas properties	20,853		18,250		2,603			18,250		—		18,250
Impairment of goodwill	—		294,908		(294,908		)	294,908		—		294,908
Impairment of fixed assets	2,765		—		2,765			—		—		—
General and administrative	78,161		78,592		(431		)	78,592		46,229		32,363
Depreciation, depletion and amortization	350,187		308,194		41,993			308,194		151,900		156,294
Other expense	25,653		5,075		20,578			5,075		—		5,075
Acquisition expense	5,500		108		5,392			108		820		(712		)
Total operating expenses	844,756		944,117		(99,361		)	944,117		356,019		588,098

(in thousands, except	Year ended December 31,									Year ended December 31,
volumes)	2016			2015			Change			2015			2014		Change
Operating (loss) income	$	(166,907	)	$	(491,155	)	$	324,248		$	(491,155	)	$	29,419	$	(520,574	)

Operating volumes:
Natural gas production (MMcf):	302,322			199,831			102,491			199,831			97,172		102,659
Oil and NGL production (MBbls):	354			249			105			249			94		155
Total production (MMcfe)	304,443			201,328			103,115			201,328			97,737		103,591

Average costs per Mcfe:
Lease operating	$	0.17		$	0.22		$	(0.05	)	$	0.22		$	0.26	$	(0.04	)
Gathering, compression and transportation	0.76			0.75			0.01			0.75			0.38		0.37
Production taxes and impact fees	0.05			0.04			0.01			0.04			0.02		0.02
General and administrative	0.26			0.39			(0.13		)	0.39			0.47		(0.08		)
Depreciation, depletion and amortization	1.15			1.53			(0.38		)	1.53			1.55		(0.02		)

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Total operating revenues. The $206.9 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in 2016 compared to 2015, as discussed above. In addition, post-acquisition revenue associated with the Vantage Acquisition was $51.6 million for the period from October 19, 2016 through December 31, 2016. The increase in operating revenues was slightly offset by a decrease in realized prices. Our realized price in 2016 was $2.14 per Mcf compared to $2.21 per Mcf in 2015, in each case before the effect of hedges. Additionally, the increase in other revenue of approximately $18.0 million was primarily driven by our natural gas marketing activities.

Lease operating expenses. The $6.4 million increase in lease operating expenses was attributable to an increase in our production base in 2016 as compared to the prior year. However, on a per unit basis, lease operating expenses decreased from $0.22 for the year ended December 31, 2015 to $0.17 for the year ended December 31, 2016 due to improved efficiencies, primarily relating to production water recycling.

Gathering, compression and transportation. Gathering, compression and transportation expense for 2016 of $232.5 million includes $127.9 million of affiliate and third party gathering fees and $105.1 million of transportation contracts with third parties. The $82.5 million increase in gathering, compression and transportation expenses was mainly due to increased volumes under the gathering agreements with the Rice Midstream Partners segment and the Rice Midstream Holdings segment, as well as increased firm transportation expense for the year ended December 31, 2016.

Production taxes and impact fees. Production taxes are directly related to natural gas, oil and NGLs sales. The $6.3 million, or 82%, increase in production taxes for 2016 compared to 2015 is primarily related to the 49% increase in natural gas, oil and NGLs sales.

Exploration. The increase in exploration expense year over year of $12.0 million was primarily due to leasehold write-offs, mainly associated with expired leaseholds.

General and administrative expense. For the year ended December 31, 2016, general and administrative expense (before stock compensation expense) decreased $2.8 million, or 4%, primarily due to a decrease in allocated costs associated with personnel and administrative expenses as the Rice Midstream Holdings segment and the Rice Midstream Partners segment continue to grow. On a per unit basis, general and administrative expense (before stock compensation expense) decreased by 35%, from $0.34 per Mcfe during the year ended December 31, 2015 to $0.22 per Mcfe during the year ended December 31, 2016, primarily due to a 51% increase in production. Included in general and administrative expense is stock compensation expense of $13.4 million and $11.0 million for the years ended December 31, 2016 and December 31, 2015, respectively.

DD&A. The $42.0 million increase was a result of an increase in production and greater number of producing wells in 2016 compared to 2015. As of December 31, 2016, we had 282 net producing Appalachian wells, an 97% increase when compared to the number of producing wells as of December 31, 2015. On a per unit basis,

DD&A expense decreased $0.38 per Mcfe, or 25%, from $1.53 for the year ended December 31, 2015 to $1.15 per Mcfe for the year ended December 31, 2016.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Total operating revenues. The $87.3 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in 2015 compared to 2014 as discussed above. The impact of increased production volumes on operating revenues was offset by a decrease in realized prices. Our realized price in 2015 was $2.21 per Mcf compared to $3.65 per Mcf in 2014, in each case before the effect of hedges. The increase in operating revenues for 2015 were offset by a $22.8 million decrease year-over-year in firm transportation sales, net, from the sale of unutilized capacity as we further utilize our existing contracts for our own operated production.

Lease operating expenses. The $19.4 million increase in lease operating expenses year-over-year was attributable to an increase in the number of producing wells in 2015 as compared to the prior year. However, lease operating expenses per unit of production decreased year-over-year due to improved efficiencies, primarily relating to production water recycling.

Gathering, compression and transportation. Gathering, compression and transportation expense for 2015 of $150.0 million includes $73.6 million of affiliate and third party gathering fees, $68.2 million of transportation contracts with third parties and $4.2 million of charges from our working interest partners on our non-operated wells. The $112.6 million increase in gathering, compression and transportation expenses was mainly due to the gathering agreements with the Rice Midstream Partners segment and the Rice Midstream Holdings segment as well as increased firm transportation expense in 2015 compared to 2014, which is consistent with increased production.

General and administrative expense. The $32.4 million increase in segment general and administrative expense year-over-year was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits. Included in general and administrative expense is stock compensation expense of $11.0 million and $4.5 million for the years ended December 31, 2015 and December 31, 2014, respectively.

DD&A. The $156.3 million increase was a result of an increase in production and greater number of producing wells in 2015 compared to 2014.

Rice Midstream Holdings Segment

(in thousands,	Year Ended December 31,								Year Ended December 31,
except volumes)	2016		2015			Change			2015			2014			Change
Operating revenues:
Gathering revenues	$	53,836	$	26,108		$	27,728		$	26,108		$	852		$	25,256
Compression revenues	10,098		1,256			8,842			1,256			—			1,256
Total operating revenues	63,934		27,364			36,570			27,364			852			26,512

Operating expenses:
Midstream operation and maintenance	3,010		2,078			932			2,078			41			2,037
Incentive unit expense	2,335		1,180			1,155			1,180			6,461			(5,281		)
Impairment of fixed assets	20,292		—			20,292			—			—			—
General and administrative	18,319		6,551			11,768			6,551			3,419			3,132
Depreciation, depletion and amortization	5,760		2,786			2,974			2,786			205			2,581
Acquisition costs	484		1,127			(643		)	1,127			—			1,127
Other expense	125		(51		)	176			(51		)	—			(51		)
Total operating expenses	50,325		13,671			36,654			13,671			10,126			3,545

Operating income (loss)	$	13,609	$	13,693		$	(84	)	$	13,693		$	(9,274	)	$	22,967

Operating volumes:
Gathering volumes (MDth/d):	708		247			461			247			24			223
Compression volumes (MDth/d):	435		51			384			51			—			51

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Total operating revenues. The $36.6 million increase in total operating revenues was mainly the result of a 187% period over period increase in affiliate gathering volumes between the Exploration and Production segment and the Rice Midstream Holdings segment, as well as an increase in third-party gathering volumes, which include revenues associated with the contracts for Strike Force Midstream.

Midstream operation and maintenance. Midstream operation and maintenance expense increased $0.9 million primarily due to pipeline maintenance expenses associated with Strike Force Midstream, which began operations in February 2016.

Impairment of fixed assets. The $20.3 million impairment expense in 2016 was primarily related to pipeline assets that were decommissioned.

General and administrative expense. The $7.7 million increase in segment general and administrative expense year-over-year (before equity compensation expense) was primarily attributable to costs associated with personnel to support the Rice Midstream Holdings segment. Included in general and administrative expense is stock compensation expense of $5.0 million and $1.0 million for the years ended December 31, 2016 and December 31, 2015, respectively. The increase was due to an increase in the allocation of our equity-based compensation expense to the Rice Midstream Holdings segment related to awards made under our equity-based compensation plans in 2016.

DD&A. The $3.0 million increase in DD&A year-over-year was primarily the result of an increase in midstream assets placed in service in 2016 as compared to 2015 and the related depreciation on those assets. As of December 31, 2016, the Rice Midstream Holdings segment had 92 miles of gathering system pipelines, a 71% increase from December 31, 2015 primarily due to the addition of gathering system pipeline assets associated with Strike Force Midstream.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Total operating revenues. The $26.5 million increase in total operating revenues year-over-year was mainly the result of an increase in volumes associated with the gathering contracts between the Exploration and Production segment and Rice Midstream Holdings segment (that were not in place for substantially all of 2014).

Midstream operation and maintenance. Midstream operation and maintenance expense increased $2.0 million year-over-year which primarily related to contract labor and maintenance costs.

Incentive unit expense. Incentive unit expense is allocated to the Rice Midstream Holdings segment based on our estimate of the expense attributable to the Rice Midstream Holdings segment’s operations. The $5.3 million decrease in incentive unit expense year-over-year is consistent with the decrease in incentive unit expense to us.

General and administrative expense. The $3.1 million increase in segment general and administrative expense year-over-year was primarily attributable to costs associated with the additions of personnel to support our growth activities and related salary and employee benefits. Included in general and administrative expense is stock compensation expense of $1.0 million and $0.2 million for the years ended December 31, 2015 and December 31, 2014, respectively.

DD&A. The $2.6 million increase in DD&A year-over-year was primarily the result of an increase in midstream assets placed in service in 2015 as compared to 2014 and the related depreciation on those assets.

Rice Midstream Partners Segment

(in thousands,	Year Ended December 31,							Year Ended December 31,
except volumes)	2016		2015		Change			2015		2014			Change
Operating revenues:
Gathering revenues	$	116,294	$	75,714	$	40,580		$	75,714	$	6,448		$	69,266
Compression revenues	15,805		1,497		14,308			1,497		—			1,497
Water services revenues	69,524		37,248		32,276			37,248		—			37,248
Total operating revenues	201,623		114,459		87,164			114,459		6,448			108,011

Operating expenses:
Midstream operation and maintenance	24,608		14,910		9,698			14,910		4,566			10,344
Incentive unit expense	—		1,044		(1,044		)	1,044		13,480			(12,436		)
General and administrative	21,613		17,895		3,718			17,895		11,922			5,973
Depreciation, depletion and amortization	25,170		16,399		8,771			16,399		4,165			12,234
Amortization of intangible assets	1,634		1,632		2			1,632		1,156			476
Acquisition costs	125		—		125			—		1,519			(1,519		)
Other expense	1,531		543		988			543		207			336
Total operating expenses	74,681		52,423		22,258			52,423		37,015			15,408

Operating income (loss)	$	126,942	$	62,036	$	64,906		$	62,036	$	(30,567	)	$	92,603

Operating volumes:
Gathering volumes (MDth/d):	983		647		336			647		378			269
Compression volumes (MDth/d):	572		64		508			64		—			64
Water services volumes (MMgal):	1,253		777		476			777		—			777

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Total operating revenues. Operating revenues increased from $114.5 million for the year ended December 31, 2015 to $201.6 million for the year ended December 31, 2016, an increase of $87.2 million. The increase in operating revenues primarily relates to increased gathering and compression revenues associated with a 52% and 794% increase in period over period gathering and compression throughput, respectively. In addition, the increase relates to a $32.3 million increase in water services revenues due to a 61% increase in fresh water distribution volumes from 777 MMgal in 2015 to 1,253 MMgal in 2016.

Midstream operation and maintenance. Total operation and maintenance expense increased from $14.9 million for the year ended December 31, 2015 to $24.6 million for the year ended December 31, 2016, an increase of $9.7 million. The increase was primarily due to on and off pad water transfer costs and water procurement, in addition to increased expenses following the Vantage Midstream Asset Acquisition, primarily associated with water transfer costs and pipeline maintenance costs.

Incentive unit expense. Incentive unit expense for the year ended December 31, 2015 of $1.0 million was allocated to the Water Assets by Rice Energy prior to their acquisition. No incentive unit expense was recorded for the year ended December 31, 2016.

General and administrative expense. General and administrative expense (before equity compensation expense) increased from $13.4 million for the year ended December 31, 2015 to $18.8 million for the year ended December 31, 2016, an increase of $5.4 million, or 40%. The increase year-over-year was primarily due to an increase in allocated costs associated with personnel and administrative expenses as the Rice Midstream Partners segment continues to grow. Included in general and administrative expense is equity compensation expense of $2.9 million and $4.5 million for the years ended December 31, 2016 and December 31, 2015, respectively.

Depreciation expense. Depreciation expense increased from $16.4 million for the year ended December 31, 2015 to $25.2 million for the year ended December 31, 2016, an increase of $8.8 million. The increase year-over-year was primarily due to additional assets placed into service in 2016, including assets related to gathering, compression and water handling and treatment services. For the year ended December 31, 2016, our gathering and water pipeline miles increased 40% and 15%, respectively.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Total operating revenues. The $108.0 million increase in total operating revenues year-over-year was mainly the result of the gathering and water service contracts between the Exploration and Production segment and the Rice Midstream Partners segment (that were not in place for substantially all of 2014) as well as an increase in volumes associated with existing third-party gathering contracts.

Midstream operation and maintenance. Midstream operation and maintenance expense for 2015 includes $9.0 million of expense relative to our fresh water services assets and $6.0 million of expense relative to our gathering assets. The $10.4 million increase in expense year-over-year was primarily due to contract labor and maintenance costs as well additional leases and utilities on compression equipment.

Incentive unit expense. Incentive unit expense of $1.0 million for the year ended December 31, 2015 was allocated to the Water Assets prior to their acquisition by RMP. Incentive unit expense of $13.5 million for the year ended December 31, 2014 was allocated to RMP’s gathering and compression assets prior to the RMP IPO and to the Water Assets.

General and administrative expense. The $6.0 million increase in segment general and administrative expense year-over-year was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits. Included in general and administrative expense is equity compensation expense of $4.5 million and $0.8 million for the years ended December 31, 2015 and December 31, 2014, respectively.

DD&A. The $12.2 million increase in DD&A year-over-year was primarily the result of an increase in midstream assets placed in service in 2015 as compared to 2014 and the related depreciation on those assets.

Outlook

During recent years, the oil and natural gas industry experienced a significant decrease in commodity prices driven by a global supply/demand imbalance for oil and an oversupply of natural gas in the United States as a result of increased productivity and warm winters. Our revenues, operating results, cash flows from operations, capital spending and future growth rates are highly dependent on the global commodity-price markets, which affect the value we receive from sales of our natural gas. While commodity price volatility has continued into 2017, we believe the long-term outlook for our business is favorable due to our low cost structure, technological advances, financial strengths, risk management, responsible capital allocation and development strategic capital.

Natural gas prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including, but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars or natural disasters. For example, the Henry Hub spot market price had rose from a low of $1.49 per MMBtu on March 4, 2016 to a high of $3.80 per MMBtu on December 7, 2016. In the future, we expect to be increasingly subject to fluctuations in oil and NGL prices. Sustained periods of low commodity prices could materially and adversely affect our financial condition, our results of operations, the quantities of natural gas that we can economically produce and our ability to access capital.

We use commodity derivative instruments, such as swaps, puts and collars, to manage and reduce price volatility and other market risks associated with our natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Please see “-Commodity Hedging Activities.” In addition, we have entered into long-term firm transportation arrangements pursuant to which our production is shipped to markets that we expect to be less impacted by basis differentials. In recent years, the cost of new firm transportation projects has risen significantly concurrent with the increasing basis differentials experienced in the Appalachian Basin. While entering into these firm transportation arrangements provides flow assurance for our natural gas production, there can be no assurance that the net impact of entering into such arrangements, after giving effect to their costs, will result in more favorable sales prices for our production in the future than local pricing. As such, our net sales prices may be materially less than NYMEX Henry Hub prices as a result of basis differentials and/or firm transportation costs.

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. In 2017, we plan to invest $1,890.0 million in our operations, including $585.0 million for drilling and completion in the Marcellus Shale, $450.0 million for drilling and completion in the Utica Shale, $225.0 million for leasehold acquisitions and $630.0 million for midstream infrastructure development, including $315.0 million expected to be invested by each RMP and Midstream Holdings, respectively. We expect to fund our 2017 capital expenditures with cash on hand, cash generated by operations and borrowings under our revolving credit facilities. Our 2017 capital budget may be further adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Our 2017 capital budget reflects a continuation of the strategy we employed in 2016. We believe that we will be able to fully fund the capital expenditures of our Exploration and Production segment with cash on hand, cash flows from operations and borrowings under our Senior Secured Revolving Credit Facility. Furthermore, we believe that we will be able to fully fund the capital expenditures of our Rice Midstream Holdings and Rice Midstream Partners segments with borrowings under our revolving credit facilities, cash flows from operations and cash on hand.

We will continue to evaluate the natural gas price environments and may adjust our capital spending plans to maintain appropriate levels of liquidity and financial flexibility.

Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy.

We believe that cash on hand, operating cash flows, and available borrowings under our revolving credit facilities will be sufficient to meet our current cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions or future capital expenditures, pay down our Senior Secured Revolving Credit Facility and for general working capital purposes. See “-Debt Agreements” below for additional details on our outstanding borrowings and available liquidity under our various financing arrangements.

Capital Resources and Liquidity

Our primary sources of liquidity have been the proceeds from equity and debt financings and borrowings under our credit facilities. Our primary use of capital has been the acquisition and development of natural gas properties and associated midstream infrastructure. As we pursue reserve and production growth, we monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. We also expect to fund a portion of these requirements with cash flow from operations as we continue to bring additional upstream and midstream production online.

Our and RMP’s credit ratings are subject to revision or withdrawal at any time. We and RMP cannot ensure that a rating will remain in effect for or will not be lowered for any given period of time. If our credit ratings are downgraded, we and RMP may be required to provide additional credit assurances in support of certain commercial agreements, such as pipeline capacity and construction contracts, the amount of which may be significant, and the potential pool of investors and funding sources may decrease.

The table below reflects Rice Energy’s credit rating for debt instruments as of December 31, 2016.

Rating Service	Senior Unsecured Notes	Outlook
Moody’s Investors Service (“Moody’s)	B3	Stable
Standard & Poor’s Rating Service (“S&P)	BB-	Stable

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $485.9 million for the year ended December 31, 2016, compared to $413.0 million of net cash provided by operating activities for the year ended December 31, 2015. The increase in operating cash flow was primarily due to an increase in production in 2016 and cash receipts on settled derivatives, net of increases in cash operating costs, interest expense and a decrease in commodity price.

Net cash provided by operating activities was $413.0 million for the year ended December 31, 2015 compared to $85.1 million of net cash used in operating activities for the year ended December 31, 2014. The increase in operating cash flow was primarily due to an increase in production in 2015 and cash receipts on settled derivatives, offset by an increase in cash operating expenses and interest expense.

Cash Flow Used in Investing Activities

During the year ended December 31, 2016 cash flows used in investing activities was $1,917.6 million, which was primarily associated with the Vantage Acquisition and the acquisition and development of our natural gas properties compared to $1,217.0 million for the year ended December 31, 2015, which primarily included capital expenditures for property and equipment.

Capital expenditures for exploration and production were $690.2 million and $869.1 million for the years ended December 31, 2016 and 2015, respectively. The decrease of $178.9 million was primarily attributable to a decrease in the acquisition and development of our natural gas properties.

Capital expenditures for the Rice Midstream Holdings segment totaled $110.9 million and $156.0 million for the years ended December 31, 2016 and 2015, respectively. The decrease of $45.1 million was due to a decrease in capital expenditures for Rice Olympus Midstream LLC’s midstream infrastructure, offset by an increase in capital expenditures for Strike Force Midstream infrastructure.

Capital expenditures for the Rice Midstream Partners segment totaled $118.1 million and $248.5 million for the years ended December 31, 2016 and 2015, respectively. The decrease of $130.4 million was attributable to a greater focus on capital expenditures for compression stations and well pad connects rather than the build out of our trunk lines.

During the year ended December 31, 2015 cash flows used in investing activities was $1,217.0 million, which primarily included capital expenditures for property and equipment compared to $1,481.5 million for the year ended December 31, 2014 related to $970.3 million of capital expenditures for property and equipment and $524.1 million related to acquisition activity.

Capital expenditures for the Exploration and Production segment were $869.1 million and $693.1 million for the years ended December 31, 2015 and 2014, respectively. The increase of $176.0 million was primarily attributable to the acquisition and development of our natural gas properties.

Capital expenditures for the Rice Midstream Holdings segment totaled $156.0 million and $107.3 million for the years ended December 31, 2015 and 2014, respectively. The increase of $48.7 million was due to the expansion of our midstream infrastructure year-over-year.

Capital expenditures for the Rice Midstream Partners segment totaled $248.5 million and $169.8 million for the years ended December 31, 2015 and 2014, respectively. The decrease of $78.7 million was due to a midstream acquisition in 2014 with no comparable acquisition in 2015.

Cash Flow Provided by Financing Activities

Net cash provided by financing activities of $1,749.8 million during the year ended December 31, 2016 was primarily associated with proceeds from our September 2016 and the April 2016 equity offering, proceeds from the Partnership’s June 2016 offering and proceeds from the Partnership’s at-the-market common unit offering program (the “ATM program”), offset by net repayments on our revolving credit facilities, and distributions to the Partnership’s public unitholders. Net cash provided by financing activities of $699.8 million during the year ended December 31, 2015 was primarily the result of the proceeds from our 2023 Notes offering, borrowings on the Midstream Holdings Revolving Credit Facility (defined below) and the RMP Revolving Credit Facility (defined below), as well as proceeds from the Private Placement (defined below) offset by distributions to the RMP’s public unitholders. Net cash provided by financing activities of $1,620.9 million during the year ended December 31, 2014 was primarily the result of the proceeds from our IPO, the 2022 Notes offering, the RMP IPO and the August 2014 equity offering, which was partially offset by repayments of debt.

Debt Agreements

Senior Notes

We have $900.0 million in aggregate principal amount of 2022 Notes outstanding. The 2022 Notes will mature on May 1, 2022, and interest is payable on the 2022 Notes on each May 1 and November 1. At any time prior to May 1, 2017, we may redeem up to 35% of the 2022 Notes at a redemption price of 106.25% of the principal amount, plus accrued and unpaid interest, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2022 Notes remains outstanding after such redemption. Prior to May 1, 2017, we may redeem some or all of the 2022 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest. Upon the occurrence of a change of control, unless we have given notice to redeem the 2022 Notes, the holders of the 2022 Notes will have the right to require us to repurchase all or a portion of the 2022 Notes at a price equal to 101% of the aggregate principal amount of the 2022 Notes, plus any accrued and unpaid interest. On and after May 1, 2017, we may redeem some or all of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.688% for the twelve-month period beginning on May 1, 2017, 103.125% for the twelve-month period beginning May 1, 2018, 101.563% for the twelve-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020, plus accrued and unpaid interest.

We have $400.0 million in aggregate principal amount of the 2023 Notes outstanding. The 2023 Notes will mature on May 1, 2023, and interest is payable on the 2023 Notes on each May 1 and November 1. At any time prior to May 1, 2018, we may redeem up to 35% of the 2023 Notes at a redemption price of 107.250% of the principal amount, plus accrued and unpaid interest, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2023 Notes remains outstanding after such redemption. Prior to May 1, 2018, we may redeem some or all of the notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest. Upon the occurrence of a change of control (as defined in the indenture governing the 2023 Notes), unless we have given notice to redeem the 2023 Notes, the holders of the 2023 Notes will have the right to require us to repurchase all or a portion of the 2023 Notes at a price equal to 101% of the aggregate principal amount of the 2023 Notes, plus any accrued and unpaid interest. On or after May 1, 2018, we may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438% for the twelve-month period beginning on May 1, 2018, 103.625% for the twelve-month period beginning May 1, 2019, 101.813% for the twelve-month period beginning on May 1, 2020 and 100.000% beginning on May 1, 2021, plus accrued and unpaid interest.

The indentures governing the Notes restrict our ability and the ability of certain of our subsidiaries to: (i) incur or guarantee additional debt or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated debt; (iii) make certain investments; (iv) incur liens;

(v) enter into transactions with affiliates; (vi) merge or consolidate with another company; (vii) transfer and sell assets; and (viii) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Notes are rated investment grade and no default has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

On October 19, 2016, we entered into supplemental indentures that provide for, among other things, the addition of Rice Energy Operating as a co-obligor under each indenture.

Senior Secured Revolving Credit Facility

In April 2013, we entered into a Senior Secured Revolving Credit Facility. In April 2014, we, as borrower, and Rice Drilling B, as predecessor borrower, amended and restated the credit agreement governing the Senior Secured Revolving Credit Facility to, among other things, assign all of the rights and obligations of Rice Drilling B LLC as borrower under the Senior Secured Revolving Credit Facility to us.

In connection with the closing of the Vantage Acquisition on October 19, 2016, we entered into the Fourth Amended and Restated Credit Agreement (the “A&R Credit Agreement”), effective upon the closing of the Vantage Acquisition to, among other things, (i) permit the completion of the Vantage Acquisition, (ii) extend the maturity date of the credit facility from January 29, 2019 to October 19, 2021, (iii) increase the borrowing base from $875.0 million to $1.0 billion without giving effect to the oil and gas properties acquired pursuant to the Vantage Acquisition, (iv) provide for the assignment of our rights and obligations as borrower under the Senior Secured Revolving Credit Facility to Rice Energy Operating, and the addition of us as a guarantor of those obligations, (v) increase the minimum required mortgage percentage (as it applies to proved reserves) to be 85% of proved reserves, (vi) amend the restricted payments covenant to permit certain distributions by Rice Energy Operating to its members, (vii) replace the interest coverage ratio with a consolidated total leverage ratio or consolidated net leverage ratio, as applicable, to commence with the last day of the fiscal quarter ended December 31, 2016, and (viii) adjust the interest rate payable on amounts borrowed thereunder (as described below).

On December 19, 2016, Rice Energy Operating, as borrower, and we, as predecessor borrower, entered into the First Amendment to the A&R Credit Agreement (the “First Amendment”). The lenders under the First Amendment completed an Interim Redetermination (as defined in the A&R Credit Agreement) of the borrowing base to give effect to the Pennsylvania oil and gas properties acquired in the Vantage Acquisition, and, upon the effectiveness of the First Amendment and such Interim Redetermination, our borrowing base and the elected commitment amounts of the lenders under the Senior Secured Revolving Credit Facility increased from $1.0 billion to $1.45 billion.

As of December 31, 2016, the borrowing base under the A&R Credit Agreement was $1.45 billion and the sublimit for letters of credit was $400.0 million. We had no borrowings outstanding and $240.9 million in letters of credit outstanding under the A&R Credit Agreement as of December 31, 2016, resulting in availability of $1.21 billion. The next redetermination of the borrowing base is scheduled for April 2017.

Following the effectiveness of the A&R Credit Agreement, Eurodollar loans under the Senior Secured Revolving Credit Facility bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of borrowing base utilized, and base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 125 to 225 basis points, depending on the percentage of borrowing base utilized.

As of December 31, 2016, the Senior Secured Revolving Credit Facility was secured by liens on at least 85% of the proved oil and gas reserves of us and our subsidiaries (other than any subsidiary that is designated as an unrestricted subsidiary, including Midstream Holdings and its subsidiaries), as well as significant unproved acreage and substantially all of the personal property of us and such restricted subsidiaries, and the Senior Secured Revolving Credit Facility is guaranteed by such restricted subsidiaries.

The A&R Credit Agreement requires us to maintain certain financial ratios, which are measured at the end of each calendar quarter:

· a consolidated current ratio, which is the ratio of consolidated current assets (including unused commitments under the A&R Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the A&R Agreement), of not less than 1.0 to 1.0; or (b) if no borrowings are then outstanding; and

· a consolidated leverage ratio, which is (a) if borrowings are outstanding under the A&R Credit Agreement on the last day of such calendar quarter, the ratio of consolidated total funded debt to EBITDAX (as such term is defined in the A&R Credit Agreement) of not more than 4.0 to 1.0; and

· the ratio of consolidated net funded debt to EBITDAX (as such term is defined in the A&R Credit Agreement) of not more than 4.0 to 1.0.

We were in compliance with such covenants and ratios as of December 31, 2016.

Midstream Holdings Revolving Credit Facility

On December 22, 2014, Midstream Holdings entered into a revolving credit facility (the “Midstream Holdings Revolving Credit Facility”) with Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, and a syndicate of lenders with a maximum credit amount of $300.0 million and a sublimit for letters of credit of $25.0 million. As of December 31, 2016, Midstream Holdings had $53.0 million of borrowings outstanding and no letters of credit outstanding, resulting in availability of $247.0 million. The average daily outstanding balance of the Midstream Holdings Revolving Credit Facility was approximately $27.1 million, and interest was incurred on the facility at a weighted average annual interest rate of 5.6% during 2016. The Midstream Holdings Revolving Credit Facility is available to fund working capital requirements and capital expenditures and to purchase assets and matures on December 22, 2019.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Under the Midstream Holdings Revolving Credit Facility, Midstream Holdings may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 225 to 300 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 125 to 200 basis points, depending on the leverage ratio then in effect. Midstream Holdings also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The Midstream Holdings Revolving Credit Facility is secured by mortgages and other security interests on substantially all of the properties of, and guarantees from, Midstream Holdings and its restricted subsidiaries (which do not include RMP or Rice Midstream Management LLC, a Delaware limited liability company and the general partner of RMP or Rice Energy and its subsidiaries other than Midstream Holdings).

The Midstream Holdings Revolving Credit Facility limits Midstream Holdings’ and its restricted subsidiaries’ ability to, among other things: incur or guarantee additional debt; redeem or repurchase units or make distributions under certain circumstances; make certain investments and acquisitions; incur certain liens or permit them to exist; enter into certain types of transactions with affiliates; merge or consolidate with another company; and transfer, sell or otherwise dispose of assets.

The Midstream Holdings Revolving Credit Facility will also require Midstream Holdings to maintain the following financial ratios:

· an interest coverage ratio, which is the ratio of Midstream Holdings’ consolidated EBITDA (as defined within the Midstream Holdings Revolving Credit Facility) to our consolidated current interest expense of at least 2.50 to 1.0 at each end of each fiscal quarter; and

· a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.25 to 1.0.

The Midstream Holdings Revolving Credit Facility also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Midstream Holdings Revolving Credit Facility to be immediately due and payable. Midstream Holdings was in compliance with its covenants and ratios effective as of December 31, 2016.

RMP Revolving Credit Facility

On December 22, 2014, Rice Midstream OpCo entered into a revolving credit facility (the “RMP Revolving Credit Facility”) with Wells Fargo, as administrative agent, and a syndicate of lenders. The RMP Revolving Credit Facility provides for lender commitments of $450.0 million with an additional $200.0 million of commitments available under an accordion feature, subject to lender approval. The RMP Revolving Credit Facility provides for a letter of credit sublimit of $50.0 million. In connection with RMP’s completion of the Vantage Midstream Asset Acquisition, on October 19, 2016, Rice Midstream OpCo entered into a second amendment (the “Second Amendment”) to its credit agreement to, among other things, (i) permit the completion of the Vantage Midstream Asset Acquisition, (ii) increase RMP’s ability to borrow under the facility from $450.0 million to $850.0 million, without exercise of any portion of the $200.0 million accordion feature and (iii) adjust the interest rate payable on amounts borrowed thereunder (as described below).

As of December 31, 2016, Rice Midstream OpCo had $190.0 million of borrowings outstanding and no letters of credit under this facility, resulting in availability of $660.0 million. The average daily outstanding balance of the RMP Revolving Credit Facility was approximately $110.0 million and interest was incurred on the facility at a weighted average annual interest rate of 4.7% during 2016. The RMP Revolving Credit Facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes. The RMP Revolving Credit Facility matures on December 22, 2019. RMP and its restricted subsidiaries are the guarantors of the obligations under the credit facility.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Under the RMP Revolving Credit Facility, Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Following the effectiveness of the Second Amendment, Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 200 to 300 basis points, depending on the leverage ratio then in effect, and base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the leverage ratio then in effect. Following the effectiveness of the Second Amendment, Rice Midstream OpCo also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The RMP Revolving Credit Facility is secured by mortgages and other security interests on substantially all of RMP’s properties and guarantees from RMP and its restricted subsidiaries.

The RMP Revolving Credit Facility limits the ability of RMP and its restricted subsidiaries to, among other things: incur or guarantee additional debt; redeem or repurchase units or make distributions under certain circumstances; make certain investments and acquisitions; incur certain liens or permit them to exist; enter into certain types of transactions with affiliates; merge or consolidate with another company; and transfer, sell or otherwise dispose of assets.

The RMP Revolving Credit Facility also requires RMP to maintain the following financial ratios:

· an interest coverage ratio, which is the ratio of RMP’s consolidated EBITDA (as defined within the revolving credit facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter;

· a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.75 to 1.0, and after electing to issue senior unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.0, and, in each case, with certain increases in the permitted total leverage ratio following the completion of a material acquisition; and

· if RMP elects to issue senior unsecured notes, a consolidated senior secured leverage ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.50 to 1.0.

The RMP Revolving Credit Facility also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the RMP Revolving Credit Facility to be immediately due and payable. RMP was in compliance with its covenants and ratios effective as of December 31, 2016.

Midstream Holdings Investment

On February 17, 2016, the Company, Midstream Holdings and GP Holdings entered into a securities purchase agreement (the “Securities Purchase Agreement”) with EIG Energy Fund XVI, L.P., EIG Energy Fund XVI-E, L.P., and EIG Holdings (RICE) Partners, LP (collectively, the “Purchasers”) pursuant to which (i) Midstream Holdings agreed to issue and sell 375,000 Series B Units (“Series B Units”) with an aggregate liquidation preference of $375.0 million and (ii) GP Holdings agreed to issue and sell common units representing an 8.25% limited partner interest in GP Holdings (“GP Common Units”) for aggregate consideration of $375.0 million in a private placement (the “Midstream Holdings Investment”) exempt from the registration requirements under the Securities Act. In conjunction with the Securities Purchase Agreement, Midstream Holdings issued 1,000 Series A Units to Rice Energy Operating. The Midstream Holdings Investment closed on February 22, 2016 (the “Closing Date”).

After September 30, 2016 and prior to the eighteen-month anniversary of the Closing Date, upon the satisfaction of certain financial and operational metrics, Midstream Holdings has the right to require the Purchasers to purchase additional Series B Units and GP Holdings common units (“GP Common Units”) on the terms set forth above. Midstream Holdings may require the Purchasers to purchase at least $25.0 million of additional units on up to three occasions, up to a total aggregate amount of $125.0 million. Pursuant to the Securities Purchase Agreement, Midstream Holdings is required to pay the Purchasers a quarterly cash commitment fee of 2.0% per annum on any undrawn amounts of the additional $125.0 million commitment. Midstream Holdings used approximately $75.0 million of the proceeds to reduce outstanding borrowings under its credit facility and to pay transaction fees and expenses, and the remaining $300.0 million was distributed to us.

April 2016 Equity Offering

On April 15, 2016, we issued and completed the April 2016 Equity Offering of an aggregate of 34,337,725 shares of common stock at a price to the public of $16.35 per share, which included 20,000,000 shares sold by us and 9,858,891 shares sold by NGP Holdings. On April 21, 2016, NGP Holdings sold an additional 4,478,834 shares of common stock pursuant to the exercise of the underwriter’s option to purchase additional shares. After deducting underwriting discounts and commissions of $15.0 million and transaction costs, we received net proceeds of $311.8 million. We received no proceeds from the sale of shares by NGP Holdings. We used the net proceeds for general corporate purposes.

June 2016 Common Unit Offering

On June 13, 2016, RMP completed an underwritten public offering of an aggregate of 9,200,000 common units representing limited partner interests in RMP at a price to the public of $18.50 per unit, which included 1,200,000 common units sold pursuant to the exercise of the underwriters’ option to purchase additional units. After deducting underwriting discounts and commissions of approximately $6.0 million and transaction costs, RMP

received net proceeds of approximately $164.1 million. RMP used a portion of the net proceeds to repay outstanding debt and intends to use the remainder for general partnership purposes, including the repayment of debt, acquisitions and capital expenditures.

September 2016 Equity Offering

On September 30, 2016, we issued and completed the September 2016 Equity Offering of an aggregate of 40,000,000 shares of common stock at a price to the public of $25.50 per share. On October 11, 2016, we sold an additional 6,000,000 shares of common stock pursuant to the exercise of the underwriters’ option to purchase additional shares of common stock in connection with the September 2016 Equity Offering. After deducting underwriting discounts and commissions of approximately $17.9 million and transaction costs, we received net proceeds of approximately $1.2 billion, which includes proceeds from the exercised underwriters’ option. We used the net proceeds from the offering to fund a portion of the Vantage Acquisition. We will use any remaining proceeds for general corporate purposes. See Note 13 for additional information.

Private Placement

On October 7, 2016, RMP issued 20,930,233 common units representing limited partner interests in RMP in a private placement for gross proceeds of approximately $450.0 million, or $21.50 per unit (the “Private Placement”). After deducting underwriting discounts and commissions of $9.4 million, RMP received net proceeds of $440.6 million. RMP primarily used the proceeds of the Private Placement to fund a portion of the Vantage Midstream Asset Acquisition. The Private Placement closed on October 7, 2016. As a result of the Private Placement, as of December 31, 2016, GP Holdings owned approximately 28% of RMP, consisting of 3,623 common units, 28,753,623 subordinated units and all of the incentive distribution rights.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in oil and natural gas prices, we have entered into financial commodity derivative contracts in the form of swaps, zero cost collars, calls, puts and basis swaps to ensure that we receive minimum prices for a portion of our future oil and natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas. Pursuant to our Amended Credit Agreement, we are now permitted to hedge the greater of (i) the percentage of proved reserve volumes (Column A) or (ii) the percentage of internally forecasted production (Column B).

Months next succeeding the time as of which compliance is measured	Column A		Column B
Months 1 through 18	85	%	90	%
Months 19 through 36	85	%	75	%
Months 37 through 60	85	%	50	%

production. For a description of our commodity derivative contracts, please see Notes 5 and 6 under Item 8 in the notes to the consolidated financial statements. We do not designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings. Please read “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of our commodity derivative contracts.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with six different counterparties. As of December 31, 2016, our contracts with JP Morgan Chase Bank, N.A. (“JP Morgan”), Wells Fargo Bank, N.A. (“Wells Fargo”) and Bank of Montreal accounted for 24%, 19% and 19% of the net fair market value of our derivative assets, respectively. We are not required to provide credit support or collateral to Wells Fargo under current contracts, nor are they required to provide credit support or collateral to us. As of December 31, 2016 we did not have any past due receivables from counterparties.

Contractual Obligations. A summary of our contractual obligations as of December 31, 2016 is provided in the following table.

	Payments due by period For the Year Ended December 31,
(in thousands)	2017		2018		2019		2020		2021		Thereafter		Total
Senior Notes Due 2022	$	56,250	$	56,250	$	56,250	$	56,250	$	56,250	$	918,750	$	1,200,000
Senior Notes Due 2023	29,000		29,000		29,000		29,000		29,000		438,667		583,667
Midstream Holdings Revolving Credit Facility	—		—		53,000		—		—		—		53,000
RMP Revolving Credit Facility	—		—		190,000		—		—		—		190,000
Drilling rig commitments (1)	27,694		8,969		—		—		—		—		36,663
Frac sand commitments	15,150		15,150		15,432		—		—		—		45,732
Gathering and firm transportation	165,638		240,719		233,990		233,741		233,369		3,809,811		4,917,268
Lease obligations	22,782		8,549		617		71		—		—		32,019
Water infrastructure	—		—		—		—		—		29,215		29,215
Asset retirement obligations (2)	2,341		324		77		—		29		798,744		801,515
Other	6,376		6,126		5,370		4,009		3,747		36,252		61,880
Total	$	325,231	$	365,087	$	583,736	$	323,071	$	322,395	$	6,031,439	$	7,950,959

(1) As of December 31, 2016, we had three horizontal drilling rigs under contract, two of which expire in 2017 and one of which expires in 2018. We also have one tophole drilling rig under contract, which expires in 2018. Any other rig performing work for us is done on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the table above. The

values in the table represent the gross amounts that we are committed to pay as operator. However, we will record in our consolidated financial statements our proportionate share of the amounts shown based on our working interest.

(2) Represents gross retirement costs with no discounting impact.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. See Note 1 of the notes to the consolidated financial statements for an expanded discussion of our significant accounting policies and estimates made by management.

Revenue Recognition

Natural Gas Properties

We use the successful efforts method of accounting for natural gas-producing activities. Costs to acquire mineral interests in natural gas properties are capitalized as unproved properties whereas costs to drill and equip exploratory wells that result in proved reserves are capitalized as proved properties. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. The sale of a partial interest in our proved properties is accounted as a recovery of cost, and we do not recognize gain or loss as long as the units of production amortization rate is not significantly affected. A gain or loss is recognized for the sale of all other producing properties.

Capitalized costs of unproved properties are evaluated at least annually for recoverability on a prospective basis. This evaluation includes consideration of current economic conditions, changes in development plans or business strategy, expected lease expirations and historical experience. If it is determined that it is unlikely for an unproved property to yield proved reserves prior to lease expiration, an impairment of the respective unproved property is recognized in the period in which that determination is made. For the year ended December 31, 2016, we recognized $20.9 million of impairment expense in the consolidated statement of operations related to lease expirations on non-core assets. In addition, for the year ended December 31, 2016, we recognized $13.5 million of leasehold write-offs included in exploration expense in the consolidated statement of operations. For the year ended December 31, 2015, we recognized $7.3 million of impairment expense in the consolidated statement of operations, primarily the result of changes in the Company’s development plans and lease expirations. Upon the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

Management’s estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future

under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, we adjust natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have a material effect on our net income or loss.

The carrying values of our proved properties are reviewed periodically when events or circumstances indicate that the remaining carrying amount may not be recoverable. This evaluation is performed at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets by comparing estimated undiscounted cash flows to the carrying value and including risk-adjusted probable and possible reserves, if deemed reasonable. Key assumptions utilized in determining the estimated undiscounted future cash flows include future development plans, estimated production from reserves, future natural gas market prices adjusted for firm transportation and basis differentials, and future operating and capital costs. If the carrying value of proved properties exceeds the estimated undiscounted future cash flows, they are written down to fair value. Fair value of proved properties is estimated by discounting the estimated future cash flows using discount rates and consideration of expected assumptions that would be used by a market participant. During 2016, the Company performed a recoverability test on its proved properties. No impairment was recorded as a result of the recoverability test. Due to the significant decline in commodity prices in 2015, there were indications that the carrying values of certain proved properties may not be fully recoverable when compared to their fair value. We determined that the carrying value of Upper Devonian proved properties was not fully recoverable utilizing a discount rate of 12%. As a result, we recognized $10.9 million of impairment expense in the consolidated statement of operations to write-down such proved properties to fair value of $7.3 million. The estimated undiscounted future cash flows of Marcellus and Utica proved properties, which significantly exceeded their carrying values and were not sensitive to significant assumptions. However, actual future results could differ from our current estimates and assumptions as future natural gas market prices are often volatile and other significant assumptions are highly judgmental and difficult to predict. Due to this uncertainty, we are unable to predict if impairment charges will be recognized in any future period.

Depletion

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, is computed using proved developed reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.

Midstream Properties

Our other properties primarily consist of gathering and water pipelines and impoundment facilities and is stated at the lower of historical cost less accumulated depreciation, or fair value, if impaired. We capitalize construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred.

Depreciation is computed over the asset’s estimated useful life using the straight-line method, based on estimated useful lives and salvage values of assets. Gathering pipelines and compressor stations are depreciated over a useful life of 60 years and water assets are depreciated over a useful life of 10 to 15 years. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to environmental matters, including air and water quality, restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, management makes estimates with respect to useful lives and salvage values that management believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts.

The carrying value of long-lived assets other than proved and unproved oil and gas properties are reviewed by us whenever events or changes in circumstances indicate that a potential impairment has occurred if projected future undiscounted cash flows are less than the carrying value of the assets. The estimate of cash flows includes management’s assumptions of cash inflows and outflows directly resulting from the use of those assets in operations. When a potential impairment has occurred, an impairment write-down is recorded if the carrying value of the long-lived asset exceeds its fair value. Such valuations include estimations of fair values and incremental direct costs to transact a sale. If we commit to a plan to dispose of a long-lived asset before the end of its previously estimated useful life, estimated cash flows are revised accordingly and we may be required to record an asset impairment write-down. During 2016, the Rice Midstream Holdings segment decommissioned and recorded impairment related to pipeline assets of $20.3 million.

Derivative Financial Instruments

We enter into derivative transactions in order to manage our exposure to gas price volatility, including commodity swap agreements, basis swap agreements, collar agreements and other similar agreements relating to the price risk associated with a portion of our production. To the extent legal right of offset with a counterparty exists, we report derivative assets and liabilities on a net basis. We have exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation, however, we actively monitor the creditworthiness of counterparties and assess the impact, if any, on our derivative position. We record derivative instruments on the consolidated balance sheets as either an asset or a liability measured at fair value and records changes in the fair value of derivatives in the consolidated statements of operations as they occur.

Asset Retirement Obligations

We record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. Our retirement obligations relate to the abandonment of gas-producing facilities and include costs to reclaim drilling sites and dismantle and relocate or dispose of water services assets, wells, and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.

When a new liability is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. To the extent future revisions to assumptions impact the present value of the existing asset retirement obligation a corresponding adjustment is made to the natural gas and oil property balance. For example, as we analyze actual plugging and abandonment information, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.

Goodwill

Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. We evaluate goodwill for impairment at least annually during the fourth quarter, or whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A reporting unit is an operating segment or a component of an operating segment for which discrete financial information is available and reviewed by management on a regular basis. In 2014, $39.1 million of goodwill was allocated to the Rice Midstream Partners segment as a result of the acquisition of the remaining 50% interest in Alpha Natural Resources, Inc. in its Marcellus joint venture. In 2016, as a result of the Vantage Acquisition, $384.5 million and $455.4 million of goodwill was allocated to the Exploration and Production segment and the Rice Midstream Partners segment, respectively.

We may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. To the extent that such indicators exist, we would complete the two-step goodwill impairment test. We may also perform the two-step goodwill impairment test at our discretion without performing the qualitative assessment. The first step compares the fair value of a reporting unit to its carrying value. If the carrying amount of a reporting unit exceeds its fair value, the second step is required which compares the implied fair value of the goodwill of a reporting unit to its carrying value. If the carrying value of the goodwill of a reporting unit exceeds its implied fair value, the difference is recognized as an impairment charge.

We use a combination of an income and market approach to estimate the fair value of a reporting unit. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. Although we believe the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the calculated fair value. Additionally, future results could differ from our current estimates and assumptions.

Our fourth quarter 2016 annual test included the assessment of factors to determine whether it was more likely than not that the fair value of each reporting unit is less than its carrying value. The qualitative assessment encompassed a review of events and circumstances specific to the reporting units with goodwill as well as circumstances specific to the entity as a whole. Our qualitative assessment considered, among other things, factors such as macroeconomic conditions, industry and market considerations, including changes in our stock price and market multiples, projected financial performance, cost factors, changes in carrying values and other relevant factors. In considering the totality of the qualitative factors assessed, based on the weight of evidence, circumstances did not exist that would indicate it was more likely than not that goodwill was impaired. Accordingly, we did not perform a two-step quantitative analysis and, accordingly, no impairment was recorded.

For the year ended December 31, 2015, we elected the option to default immediately to the first step of the annual goodwill impairment test. The results of the first step indicated that the carrying value of the Exploration and Production reporting unit exceeded its fair value. Due to the result of step one of the annual goodwill impairment test for the Exploration and Production reporting unit, we performed the second step of the goodwill impairment analysis comparing the implied fair value of the reporting unit’s goodwill to its carrying amount and determined that such goodwill was fully impaired. As a result, we recorded an impairment charge of $294.9 million to eliminate the carrying value of goodwill of the Exploration and Production reporting unit at December 31, 2015. Management considered the negative industry and market trends, including the decline in commodity prices and overall market performance of our peers and us, to be the primary reasons of impairment.

No impairment was recorded for the year ended December 31, 2014.

Income Taxes

We are a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings and, as such, our future income taxes will be dependent upon our future taxable income. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO in January 2014 because Rice Drilling B, our accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of our business into a corporation in connection with the closing of the IPO required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of the completion of the IPO as it represents a transaction among shareholders. Additionally, we have presented pro forma earnings per share for the year ended December 31, 2014 assuming a statutory rate as disclosed in the Consolidated Statements of Operations was applied for the full year ended December 31, 2014.

We follow ASC 740-10-25, which requires the use of a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized. We did not have any uncertain tax positions as of December 31, 2016.

Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740-Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We will record a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by us and may be challenged by the taxation authorities.

Business Combinations

Accounting for the acquisition of a business requires the identifiable assets and liabilities to be recorded at fair value. The purchase price is allocated to assets acquired and liabilities assumed based on their estimated fair values at the time of acquisition. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value.

The most significant assumptions involve the estimated fair values of the oil and gas properties acquired. The fair value of proved natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs from our engineers and outside consultants. Critical assumptions and estimates include gas prices; projections of estimated quantities of natural gas reserves; projections of future rates of production; timing and amount of future development and operating costs; projected reserve recovery factors; and weighted average cost of capital. We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the business combination based upon our cost of capital.

Unproved properties generally represent the value of probable and possible reserves related to undeveloped acreage. We utilize the guideline transaction method to estimate the fair value of unproved properties acquired in a business combination.

The current year Vantage Acquisition included substantial midstream activities. We allocate purchase prices to tangible long-lived midstream assets based upon the calculated fair value of midstream facilities and equipment, generally consisting of pipeline systems and compression stations. We estimate the fair value of these assets using the replacement cost approach which include certain assumptions including the replacement costs for similar assets.

The excess purchase price over the fair values of the net identifiable assets acquired is recorded as goodwill. Please see “Note 3-Acquisitions” in the notes of the consolidated financial statements under Item 8 of this Annual Report for further information regarding our current year acquisition of Vantage and certain assets from Murray Energy.

New Accounting Pronouncements

Please see “Item 8. Financial Statements-Notes to Consolidated Financial Statements-20. New Accounting Pronouncements” for further detail regarding new accounting pronouncements.

Off-Balance Sheet Arrangements

As of December 31, 2016, we did not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See “Note 9-Commitments and Contingencies” in the notes of the consolidated financial statements under Item 8 of this Annual Report for a description of our commitments and contingencies.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from

adverse changes in oil and natural gas 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 exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity price risk and hedges

Our primary market risk exposure is in the price we receive for our natural gas production. Realized pricing is primarily driven by market prices applicable to our U.S. natural gas production. Pricing for natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate some of the potential negative impact on our cash flow caused by changes in commodity prices, we enter into financial commodity swap contracts to receive fixed prices for a portion of our natural gas production to mitigate the potential negative impact on our cash flow.

Our financial hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. The counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. These contracts may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, cashless price collars that set a floor and ceiling price for the hedged production, or basis differential swaps. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference.

As of December 31, 2016, we have entered into derivative instruments with various financial institutions, fixing the price we receive for a portion of our natural gas through December 31, 2021. Our commodity hedge position as of December 31, 2016 is summarized in Note 5 to our consolidated financial statements included elsewhere in the Annual Report. Our financial hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to price fluctuations.

By removing price volatility from a portion of our expected natural gas production through December 2017, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the hedge prices.

Interest rate risks

Our primary interest rate risk exposure results from our credit facilities.

As of December 31, 2016, we had no borrowings and approximately $240.9 million in letters of credit outstanding under our Senior Secured Revolving Credit Facility. As of December 31, 2016, we had availability under the borrowing base of our Senior Secured Revolving Credit Facility of approximately $1.21 billion and the borrowing base was $1.45 billion. We have a choice of borrowing in Eurodollars or at the base rate. Under the A&R Credit Agreement, Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 125 to 225 basis points, depending on the percentage of our borrowing base utilized.

As of December 31, 2016, Midstream Holdings had $53.0 million in borrowings outstanding and no letters of credit under the Midstream Holdings Revolving Credit Facility. Midstream Holdings may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate

plus an applicable margin ranging from 225 to 300 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 125 to 200 basis points, depending on the leverage ratio then in effect.

The average annual weighted interest rate incurred on the Midstream Holdings Revolving Credit Facility during 2016 was approximately 5.6%. A 1.0% increase in the applicable average interest rates for 2016 would have resulted in an estimated $0.3 million increase in interest expense.

As of December 31, 2016, Rice Midstream OpCo had $190.0 million borrowings outstanding and no letters of credit under the RMP Revolving Credit Facility. Rice Midstream OpCo has a choice of borrowing in Eurodollars or at the base rate. Following the effectiveness of the Second Amendment, Eurodollar loans will bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 200 to 300 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the leverage ratio then in effect.

The average annual weighted interest rate incurred on the RMP Revolving Credit Facility during 2016 was approximately 4.7%. A 1.0% increase in the applicable average interest rates for 2016 would have resulted in an estimated $1.1 million increase in interest expense.

As of December 31, 2016, we did not have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.

Counterparty and customer credit risk

Our principal exposures to credit risk are through joint interest receivables ($53.6 million in receivables as of December 31, 2016) and the sale of our natural gas production ($145.9 million in receivables as of December 31, 2016), which we market to multiple natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have minimal ability to choose who participates in our wells. We are also subject to credit risk with two natural gas marketing companies that hold a significant portion of our natural gas receivables. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to review annually, or on an as-needed basis. We have derivative instruments in place with six different counterparties. As of December 31, 2016, our contracts with JP Morgan, Well Fargo and Bank of Montreal accounted for 24%, 19% and 19% of the net fair market value of our derivative assets, respectively. We believe these counterparties are acceptable credit risks. We are not required to post letters of credit as collateral to JP Morgan, Wells Fargo and Bank of Montreal under current contracts, nor are they required to provide credit support or collateral to us. As of December 31, 2016 we did not have any past due receivables from counterparties.

Item 8. Financial Statements and Supplementary Data

		Page
Rice Energy Inc.
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Rice Energy Inc.

We have audited the accompanying consolidated balance sheets of Rice Energy Inc. as of December 31, 2016 and 2015, and the related consolidated statements of operations, cash flows and equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Rice Energy Inc. at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Rice Energy Inc.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our reported dated March 1, 2017 expressed an unqualified opinion thereon.

	/s/ Ernst & Young LLP


Pittsburgh, Pennsylvania
March 1, 2017

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Rice Energy Inc.

We have audited Rice Energy Inc.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Rice Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Vantage Acquisition, which are included in the 2016 consolidated financial statements of Rice Energy Inc. and constituted approximately 41% and 59% of total and net assets, respectively, as of December 31, 2016 and approximately 7% of operating revenues for the year then ended. Our audit of internal control over financial reporting of Rice Energy Inc. also did not include an evaluation of the internal control over financial reporting of the entities acquired in the Vantage Acquisition.

In our opinion, Rice Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Rice Energy Inc. as of December 31, 2016 and 2015, and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2016 of Rice Energy Inc. and our report dated March 1, 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 1, 2017

Rice Energy Inc.

Consolidated Balance Sheets

	December 31,
(in thousands)	2016			2015
Assets
Current assets:
Cash	$	470,043		$	151,901
Accounts receivable	218,625			154,814
Prepaid expenses, deposits and other	5,059			5,488
Derivative instruments	689			186,960
Total current assets	694,416			499,163

Gas collateral account	5,332			4,077
Property, plant and equipment, net	6,117,912			3,243,131
Deferred financing costs, net	36,384			8,811
Goodwill	879,011			39,142
Intangible assets, net	44,525			46,159
Other non-current assets	614			2,670
Derivative instruments	39,328			105,945
Total assets	$	7,817,522		$	3,949,098

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	18,244		$	83,553
Royalties payable	87,098			40,572
Accrued capital expenditures	124,700			79,747
Leasehold payable	22,869			17,338
Derivative instruments	139,388			499
Other accrued liabilities	140,447			78,632
Total current liabilities	532,746			300,341

Long-term liabilities:
Long-term debt	1,522,481			1,435,790
Leasehold payable	9,237			6,289
Deferred tax liabilities	358,626			271,988
Derivative instruments	26,477			16,344
Other long-term liabilities	81,348			13,878
Total liabilities	2,530,915			2,044,630

Mezzanine equity:
Redeemable noncontrolling interest, net (Note 10)	382,525			—

Stockholders’ equity:
Common stock, $0.01 par value; authorized - 650,000,000 shares; issued and outstanding 202,606,908 shares and 136,387,194 shares, respectively	2,026			1,364
Preferred stock, $0.01 par value; authorized - 50,000,000 shares; 40,000 shares issued	—			—
Additional paid in capital	3,313,917			1,416,523
Accumulated earnings	(407,741		)	(137,990		)
Stockholders’ equity before noncontrolling interest	2,908,202			1,279,897
Noncontrolling interests in consolidated subsidiaries	1,995,880			624,571
Total liabilities and stockholders’ equity	$	7,817,522		$	3,949,098

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Energy Inc.

Consolidated Statements of Operations

	Years Ended December 31,
(in thousands, except share data)	2016			2015			2014
Operating revenues:
Natural gas, oil and natural gas liquids (NGL) sales	$	653,441		$	446,515		$	359,201
Gathering, compression and water services	101,057			49,179			5,504
Other revenue	24,408			6,447			26,237
Total operating revenues	778,906			502,141			390,942

Operating expenses:
Lease operating	50,574			44,356			24,971
Gathering, compression and transportation	123,852			84,707			35,618
Production taxes and impact fees	13,866			7,609			4,647
Exploration	15,159			3,137			4,018
Midstream operation and maintenance	23,215			16,988			4,607
Incentive unit expense	51,761			36,097			105,961
Impairment of gas properties	20,853			18,250			—
Impairment of goodwill	—			294,908			—
Impairment of fixed assets	23,057			—			—
General and administrative	118,093			103,038			61,570
Depreciation, depletion and amortization	368,455			322,784			156,270
Acquisition expense	6,109			1,235			2,339
Amortization of intangible assets	1,634			1,632			1,156
Other expense	27,308			5,567			207
Total operating expenses	843,936			940,308			401,364

Operating loss	(65,030		)	(438,167		)	(10,422		)
Interest expense	(99,627		)	(87,446		)	(50,191		)
Gain on purchase of Marcellus joint venture	—			—			203,579
Other income	1,406			1,108			893
(Loss) gain on derivative instruments	(220,236		)	273,748			186,477
Amortization of deferred financing costs	(7,545		)	(5,124		)	(2,495		)
Loss on extinguishment of debt	—			—			(7,654		)
Write-off of deferred financing costs	—			—			(6,896		)
Equity in loss of joint ventures	—			—			(2,656		)
(Loss) income before income taxes	(391,032		)	(255,881		)	310,635
Income tax benefit (expense)	142,212			(12,118		)	(91,600		)
Net (loss) income	(248,820		)	(267,999		)	219,035
Less: Net income attributable to noncontrolling interests	(20,931		)	(23,337		)	(581		)
Net (loss) income attributable to Rice Energy Inc.	(269,751		)	(291,336		)	218,454
Less: Preferred dividends and accretion of redeemable noncontrolling interests	(28,450		)	—			—
Net (loss) income attributable to Rice Energy Inc. common stockholders	$	(298,201	)	$	(291,336	)	$	218,454
Weighted average number of shares of common stock - basic	162,225,505			136,344,076			128,151,171
Weighted average number of shares of common stock - diluted	162,225,505			136,344,076			128,255,155
(Loss) income earnings per share-basic	$	(1.84	)	$	(2.14	)	$	1.70
(Loss) income earnings per share-diluted	$	(1.84	)	$	(2.14	)	$	1.70
Pro forma income tax benefit (unaudited)							$	5,560
Pro forma net income (unaudited)							$	224,596
Pro forma earnings per share-basic (unaudited)							$	1.75
Pro forma earnings per share-diluted (unaudited)							$	1.75

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Energy Inc.

Consolidated Statements of Cash Flows

	Years Ended December 31,
(in thousands)	2016			2015			2014
Cash flows from operating activities:
Net (loss) income	$	(248,820	)	$	(267,999	)	$	219,035
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	368,455			322,784			156,270
Impairment of gas properties	20,853			18,250			—
Impairment of goodwill	—			294,908			—
Impairment of fixed assets	23,057			—			—
Amortization of deferred finance costs and loss on extinguishment of debt	7,545			5,124			10,149
Amortization of intangibles	1,634			1,632			1,156
Exploration	15,159			3,137			2,211
Incentive unit expense	51,761			36,097			105,961
Write-off of deferred financing costs	—			—			6,896
Gain from sale of interest in gas properties	—			(953		)	—
Stock compensation expense	21,915			16,528			5,553
Derivative instruments fair value loss (gain)	220,236			(273,748		)	(186,477		)
Cash receipts (payments) for settled derivatives	202,178			193,908			(18,784		)
Deferred income tax (benefit) expense	(175,298		)	8,079			87,639
Fair value gain on purchase of Marcellus joint venture	—			—			(203,579		)
Equity in loss of joint ventures	—			—			2,656
Changes in operating assets and liabilities:
Accounts receivable and receivable from affiliate	(44,160		)	45,175			(151,427		)
Prepaid expenses and other assets	1,050			(5,384		)	(1,996		)
Accounts payable	(52,799		)	(18,439		)	4,661
Accrued liabilities and other	40,223			30,488			25,280
Royalties payable	32,896			3,400			19,871
Net cash provided by operating activities	485,885			412,987			85,075

Cash flows from investing activities:
Capital expenditures for property and equipment	(880,514		)	(1,246,274		)	(970,274		)
Acquisition of Vantage Energy, net of cash acquired	(981,080		)	—			—
Acquisition of Murray Assets	(44,266		)	—			—
Other acquisitions	(11,700		)	19,054			(524,082		)
Proceeds from sale of interest in gas properties	—			10,201			12,891
Net cash used in investing activities	(1,917,560		)	(1,217,019		)	(1,481,465		)

Cash flows from financing activities:
Proceeds from borrowings	338,000			913,932			1,090,000
Repayments of debt obligations	(963,101		)	(358,619		)	(689,873		)
Restricted cash for convertible debt	—			—			8,268
Distributions to the Partnership’s public unitholders	(47,875		)	(17,017		)	—
Debt issuance costs	(31,971		)	(10,266		)	(24,543		)
Proceeds from issuance of common stock, net of offering costs	1,465,671			(129		)	793,342
Proceeds from issuance of common units sold by RMP, net of offering costs	620,330			171,902			441,739
Proceeds from conversion of warrants	89			—			1,975
Proceeds from issuance of non-controlling redeemable interest	368,747			—			—
Contribution to Strike Force Midstream by Gulfport Midstream	11,030			—			—
Preferred dividends to redeemable noncontrolling interest holders	(6,900		)	—			—
Employee tax withholding for settlement of stock compensation award vestings	(4,203		)	—			—
Net cash provided by financing activities	1,749,817			699,803			1,620,908

Net increase (decrease) in cash	318,142			(104,229		)	224,518
Cash at the beginning of the year	151,901			256,130			31,612
Cash at the end of the year	$	470,043		$	151,901		$	256,130

Rice Energy Inc.

Consolidated Statements of Cash Flows

	Years Ended December 31,
(in thousands)	2016			2015			2014
Supplemental disclosure of noncash investing and financing activities
Capital expenditures for natural gas properties financed by accounts payable	$	14,357		$	77,882		$	144,053
Capital expenditures for natural gas properties financed by other accrued liabilities	124,701			79,747			108,290
Natural gas properties financed through deferred payment obligations	32,106			23,628			34,984
Issuance of Rice Energy Operating units	1,001,200			—			—
Asset contribution to Strike Force Midstream by Gulfport Midstream	22,500			—			—
Application of advances from joint interest owners	(4,801		)	(6,994		)	(7,304		)

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Energy Inc.

Statements of Consolidated Equity

(in thousands)	Common Stock ($0.01 par)		Additional Paid-In Capital			Accumulated (Deficit) Earnings			Stockholders Equity before Non-Controlling Interest			Non-Controlling Interest			Total Equity
Balance, January 1, 2014	$	880	$	362,875		$	(65,108	)	$	298,647		$	—		$	298,647
Shares of common stock issued in initial public offering, net of offering costs	300		593,113			—			593,413			—			593,413
Shares of common stock issued in purchase of Marcellus joint venture	95		221,905			—			222,000			—			222,000
Conversion of restricted units into shares of common stock at our IPO	—		36,306			—			36,306			—			36,306
Conversion of convertible debentures into shares of common stock after our IPO	6		6,599			—			6,605			—			6,605
Conversion of warrants into shares of common stock after our IPO	7		1,968			—			1,975			—			1,975
Shares of common stock issued in August 2014 Equity Offering, net of offering costs	75		196,179			—			196,254			—			196,254
Shares of common units issued in RMP IPO, net of offering costs	—		—			—			—			441,739			441,739
Incentive unit compensation	—		105,961			—			105,961			—			105,961
Stock compensation	—		5,415			—			5,415			138			5,553
Tax impact of our IPO and corporate reorganization	—		(162,320		)	—			(162,320		)	—			(162,320		)
Consolidated net income	—		—			218,454			218,454			581			219,035
Balance, December 31, 2014	$	1,363	$	1,368,001		$	153,346		$	1,522,710		$	442,458		$	1,965,168
Incentive unit compensation	—		36,097			—			36,097			—			36,097
Stock compensation	1		12,425			—			12,426			4,020			16,446
Distributions to the Partnership’s public unitholders	—		—			—			—			(17,017		)	(17,017		)
Offering costs related to the Partnership’s IPO	—		—			—			—			(129		)	(129		)
Shares of common units issued by RMP, net of offering costs	—		—			—			—			171,902			171,902
Consolidated net income (loss)	—		—			(291,336		)	(291,336		)	23,337			(267,999		)
Balance, December 31, 2015	$	1,364	$	1,416,523		$	(137,990	)	$	1,279,897		$	624,571		$	1,904,468

(in thousands)	Common Stock ($0.01 par)		Additional Paid-In Capital			Accumulated (Deficit) Earnings			Stockholders Equity before Non-Controlling Interest			Non-Controlling Interest			Total Equity
Incentive unit compensation	—		51,761			—			51,761						51,761
Stock compensation	—		19,580			—			19,580			2,825			22,405
Issuance of common stock upon vesting of stock compensation awards, net of tax withholdings	2		(1,686		)	—			(1,684		)	—			(1,684		)
Issuance of phantom units upon vesting of equity-based compensation, net of tax withholdings	—		(8,177		)	—			(8,177		)	5,658			(2,519		)
Shares of common stock issued, net of offering costs	660		1,465,011			—			1,465,671			—			1,465,671
Conversion of warrants into shares of common stock	—		89			—			89			—			89
Preferred dividends on redeemable noncontrolling interest	—		(26,176		)	—			(26,176		)	—			(26,176		)
Accretion of redeemable noncontrolling interest	—		(2,274		)	—			(2,274		)	—			(2,274		)
Common units issued pursuant to the Partnership in June 2016 offering, net of offering costs	—		—			—			—			163,985			163,985
Common units issued pursuant to the Partnership’s ATM program, net of offering costs	—		—			—			—			15,713			15,713
Common units issued pursuant to the Partnership’s October 2016 private placement, net of offering costs	—		—			—			—			440,632			440,632
Contribution from noncontrolling interest	—		—			—			—			33,530			33,530
Distributions to the Partnership’s public unitholders	—		—			—			—			(47,875		)	(47,875		)
Change in ownership of consolidated subsidiaries	—		399,266			—			399,266			735,910			1,135,176
Consolidated net (loss) income	—		—			(269,751		)	(269,751		)	20,931			(248,820		)
Balance, December 31, 2016	$	2,026	$	3,313,917		$	(407,741	)	$	2,908,202		$	1,995,880		$	4,904,082

The accompanying notes are an integral part of these Consolidated Financial Statements.

Rice Energy Inc.
Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies and Related Matters

Organization, Operations and Principles of Consolidation

The accompanying consolidated financial statements of Rice Energy Inc. (“Rice Energy,” the “Company,” “we,” “our,” and “us”) have been prepared by the Company’s management in accordance with generally accepted accounting principles in the United States (“GAAP”) for financial information and applicable rules and regulations promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries. Rice Midstream GP Holdings LP, an indirect subsidiary of the Company (“GP Holdings”), owns a 28% interest in Rice Midstream Partners LP, a subsidiary of the Company, (“RMP” or the “Partnership”). The financial results of the Partnership are consolidated and, after giving effect to EIG’s ownership in GP Holdings, the approximate 74% interest in the Partnership is reflected as noncontrolling interest in the consolidated financial statements. All intercompany transactions have been eliminated in consolidation.

On October 19, 2016, the Company completed the acquisition of Vantage Energy, LLC and Vantage Energy II, LLC (collectively, “Vantage”) and their subsidiaries (the “Vantage Acquisition”) pursuant to the terms of a Purchase and Sale Agreement (the “Vantage Purchase Agreement”) dated September 26, 2016 by the Company, Vantage Energy Investment LLC, Vantage Energy Investment II LLC and Vantage. Pursuant to the terms of the Vantage Purchase Agreement, Rice Energy Operating LLC (“Rice Energy Operating” or “REO”) acquired Vantage from certain affiliates of Quantum Energy Partners, Riverstone Holdings LLC and Lime Rock Partners (such affiliates, the “Vantage Sellers”). As of December 31, 2016, the Company owned an 83.51% membership interest in Rice Energy Operating. The remaining 16.49% membership interest in Rice Energy Operating is owned by the Vantage Sellers and is reflected as noncontrolling interest in the consolidated financial statements. See Note 3 for further information on the Company’s acquisition of Vantage.

Following completion of the Vantage Acquisition, the Company operates Vantage through Rice Energy Operating. As part of the consideration for the Vantage Acquisition, the Vantage Sellers received membership interests in Rice Energy Operating. In connection with the issuance of such membership interests to the Vantage Sellers, the Company and the Vantage Sellers entered into Rice Energy Operating’s third amended and restated limited liability company agreement (the “Third A&R LLC Agreement”). Under the Third A&R LLC Agreement, the Company controls all of the day-to-day business affairs and decision making of Rice Energy Operating without approval of any other member, unless otherwise stated in the Third A&R LLC Agreement. As such, the Company, through its officers and directors, are responsible for all operational and administrative decisions of Rice Energy Operating and the day-to-day management of Rice Energy Operating’s business. Pursuant to the terms of the Third A&R LLC Agreement, the Company cannot, under any circumstances, be removed or replaced as the sole manager of Rice Energy Operating, except by its own election so long as it remains a member of Rice Energy Operating. Provisions regarding the operations of Rice Energy Operating, and the rights and obligations of the holders of Rice Energy Operating common units, are set forth in the Third A&R LLC Agreement.

Nature of Business

The Company is an independent natural gas and oil company focused on the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. The Company operates in three business segments, which are managed separately in determining the allocation of the Company’s resources. The Company’s three reporting segments are as follows:

Exploration and Production. This segment is engaged in the acquisition, exploration and development of natural gas.

Rice Midstream Holdings. This segment is engaged in the gathering and compression of natural gas production in Belmont and Monroe Counties, Ohio.

Rice Midstream Partners. This segment is engaged in the gathering and compression of natural gas, oil and NGL production in Washington and Greene Counties, Pennsylvania, and in the provision of water services to support the well completion services of us and third parties in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio.

Risks and Uncertainties

The prices the Company receives for its natural gas production heavily influence its revenue, operating results profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas is a commodity and, therefore, its price is subject to wide fluctuation in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. The prices the Company receives for its production, and the levels of its production, depend on numerous factors beyond its control. See “Item 1A. Risk Factors” for a further discussion on risks and uncertainties relevant to the Company.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates and changes in these estimates are recorded when known.

Revenue Recognition

Sales of natural gas, NGLs and oil are recognized when the products have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with the Company’s natural gas marketers. Pricing provisions are generally tied to the Platts Gas Daily market prices. Some transportation costs incurred by the Company are marketed for resale and are not incurred to transport gas produced by the Company’s Exploration and Production segment. These transportation costs are reflected as a deduction from the related firm transportation sales revenue at the time the transportation is provided to the customer. Revenue from the gathering and compression of natural gas and water services is recognized in the month in which the service is provided.

Cash

The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has no accounts that are considered cash equivalents.

Accounts Receivable

Accounts receivable are primarily from the Company’s joint interest partners and natural gas marketers. The Company extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. Allowances for uncollectible accounts were not material for the periods presented. Accounts receivable as of December 31, 2016 and 2015 are detailed below.

	December 31,
(in thousands)	2016		2015
Joint interest	$	53,577	$	76,985
Natural gas sales	145,887		67,444
Other	19,161		10,385
Total accounts receivable	$	218,625	$	154,814

Noncontrolling Interest

Noncontrolling interests represent third-party equity ownership of the Partnership and Rice Energy Operating and are presented as a component of equity in the consolidated balance sheets. In the consolidated statements of operations, noncontrolling interest reflects the allocation of earnings to these third parties. As of December 31, 2016, the Company owned an 83.51% membership interest in Rice Energy Operating while the Vantage Sellers own the remaining 16.49%. The financial results of Rice Energy Operating are consolidated and the remaining percentage owned by the Vantage Sellers is reflected as noncontrolling interest in the consolidated financial statements. See Note 3 for further discussion of the Vantage Acquisition. In addition, as of December 31, 2016, GP Holdings owned a 28% equity interest in the Partnership. The financial results of the Partnership are consolidated and, after giving effect to the EIG ownership in GP Holdings, the approximate 74% interest in the Partnership is reflected as noncontrolling interest in the consolidated financial statements. See Note 7 for further discussion of noncontrolling interests related to the Partnership.

Property, Plant and Equipment

Natural gas properties

The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties are capitalized as unproved properties, whereas costs to drill and equip exploratory wells that result in proved reserves are capitalized as proved properties. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and costs of carrying and retaining unproved properties are expensed.

Capitalized costs of producing oil and gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the units of production method.

Capitalized costs of unproved properties are evaluated at least annually for recoverability on a prospective basis. This evaluation includes consideration of current economic conditions, changes in development plans or business strategy, expected lease expirations and historical experience. If it is determined that it is unlikely for an unproved property to yield proved reserves prior to lease expiration, an impairment of the respective unproved property is recognized in the period in which that determination is made. For the year ended December 31, 2016, the Company recognized $20.9 million of impairment expense in the consolidated statement of operations related to lease expirations on non-core assets. In addition, for the year ended December 31, 2016, the Company recognized $13.5 million of leasehold write-offs included in exploration expense in the consolidated statement of operations. For the year ended December 31, 2015, the Company recognized $7.3 million of impairment expense in the consolidated statement of operations, primarily the result of changes in the Company’s development plans and lease expirations. Upon the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale. No significant gains or losses were realized from the sale of unproved properties in the periods presented. Unproved oil and gas properties had a net book value of $2,001.8 million and $1,050.0 million at December 31, 2016 and 2015, respectively.

The carrying values of the Company’s proved properties are reviewed periodically when events or circumstances indicate that the remaining carrying amount may not be recoverable. This evaluation is performed at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets by comparing estimated undiscounted cash flows to the carrying value and including risk-adjusted probable and possible reserves, if deemed reasonable. Key assumptions utilized in determining the estimated undiscounted future cash flows are generally consistent with assumptions used in the Company’s budgeting and forecasting processes. If the carrying value of proved properties exceeds the estimated undiscounted future cash flows, they are written down to fair value. Fair value of proved properties is estimated by discounting the estimated future cash flows using discount rates and consideration of expected assumptions that would be used by a market participant.

During 2016, the Company performed a recoverability test on its proved properties. No impairment was recorded as a result of the recoverability test. Due to the significant decline in commodity prices in 2015, there were indications that the carrying values of certain proved properties may not be fully recoverable when compared to their fair value. The fair value was determined using an income approach based on estimated future production, future commodity prices adjusted for firm transportation and basis differentials, future operating and capital costs, and an assumed discount rate of 12%. As the assumptions used to calculate the estimated fair value were significant unobservable inputs, the valuation of the proved properties was considered to be a Level 3 fair value measurement. The Company determined that the carrying value of Upper Devonian proved properties was not fully recoverable and as a result, for the year ended December 31, 2015, the Company recognized $10.9 million of impairment expense in the consolidated statement of operations to write-down such proved properties to fair value of $7.3 million. For the year ended December 31, 2014, the Company did not recognize impairment charges for proved or unproved properties.

Midstream properties

Midstream property and equipment is recorded at cost and is being depreciated over estimated useful lives on a straight-line basis. Gathering pipelines and compressor stations are depreciated over a useful life of 60 years. Water pipelines, pumping stations and impoundment facilities are depreciated over a useful life of 10 to 15 years.

The Company evaluates its long-lived assets for impairment when events and circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. Long-lived assets assessed for impairment are grouped at the lowest level for which identifiable cash flows are largely independent of the cash flows for other assets and liabilities. Impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value with an offsetting charge to impairment expense.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as changes in contract rates or terms, the condition of an asset, or management’s intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. A reduction of carrying value of fixed assets would represent a Level 3 fair value measure. No impairments for such assets have recorded for the years presented herein.

During the fourth quarter of 2016, the Company recorded a $20.3 million impairment within the Rice Midstream Holdings segment related to pipeline assets that were decommissioned.

Interest

The Company capitalizes interest on expenditures for significant exploration and development and midstream projects while activities are in progress to bring the assets to their intended use. Upon completion of construction of the asset, the associated capitalized interest costs are included within our asset base and depleted accordingly. The following table summarizes the components of the Company’s interest incurred for the years ended December 31, 2016, 2015 and 2014:

(in thousands)	2016		2015		2014
Interest incurred:
Interest expensed	$	99,627	$	87,446	$	50,191
Interest capitalized	223		195		905
Total incurred	$	99,850	$	87,641	$	51,096

Goodwill

Goodwill is the cost of an acquisition less the fair value of the identifiable net assets of the acquired business. The Company evaluates goodwill for impairment at least annually during the fourth quarter, or whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A reporting unit is an operating segment or a component of an operating segment for which discrete financial information is available and reviewed by management on a regular basis. In 2014, $39.1 million of goodwill was allocated to the Rice Midstream Partners segment as a result of the acquisition of the remaining 50% interest in Alpha Natural Resources, Inc. in its Marcellus joint venture. In 2016, as a result of the Vantage Acquisition, $384.5 million and $455.4 million of goodwill was allocated to the Exploration and Production segment and the Rice Midstream Partners segment, respectively.

The Company may first consider qualitative factors to assess whether there are indicators that it is more likely than not that the fair value of a reporting unit may not exceed its carrying amount. To the extent that such indicators exist, the Company will complete the two-step goodwill impairment test. The Company may also perform the two-step goodwill impairment test at its discretion without performing the qualitative assessment. The first step compares the fair value of a reporting unit to its carrying value. If the carrying amount of a reporting unit exceeds its fair value, the second step is required which compares the implied fair value of the goodwill of a reporting unit to its carrying value. If the carrying value of the goodwill of a reporting unit exceeds its implied fair value, the difference is recognized as an impairment charge. The Company uses a combination of an income and market approach to estimate the fair value of a reporting unit. The fair value estimation process requires considerable judgment and determining the fair value is sensitive to changes in assumptions impacting management’s estimates of future financial results. Although the Company believes the estimates and assumptions used in estimating the fair value are reasonable and appropriate, different assumptions and estimates could materially impact the calculated fair value. Additionally, future results could differ from our current estimates and assumptions.

The Company’s fourth quarter 2016 annual test included the assessment of qualitative factors to determine whether it was more likely than not that the fair value of each reporting unit is less than its carrying value. The qualitative assessment encompassed a review of events and circumstances specific to the reporting units with goodwill as well as circumstances specific to the entity as a whole. The Company’s qualitative assessment considered, among other things, factors such as macroeconomic conditions, industry and market considerations, including changes in the Company’s stock price and market multiples, projected financial performance, cost factors, changes in carrying values and other relevant factors. In considering the totality of the qualitative factors assessed, based on the weight of evidence, circumstances did not exist that would indicate it was more likely than not that goodwill was impaired. Accordingly, the Company did not perform a two-step quantitative analysis and no impairment was recorded.

For the year ended December 31, 2015, given the overall market conditions, the Company elected the option to default immediately to the first step of the annual goodwill impairment test. The results of the first step indicated that the carrying value of the Exploration and Production reporting unit exceeded its fair value. Due to the result of step one of the annual goodwill impairment test for the Exploration and Production reporting unit, the Company performed the second step of the goodwill impairment analysis comparing the implied fair value of the reporting unit’s goodwill to its carrying amount and determined that such goodwill was fully impaired. As a result, the Company recorded an impairment charge of $294.9 million to eliminate the carrying value of goodwill of the Exploration and Production reporting unit at December 31, 2015. Management considered the negative industry and market trends, including the decline in commodity prices and overall market performance of the Company’s peers and the Company, to be the primary reasons of impairment.

No impairment was recorded for the year ended December 31, 2014.

Goodwill as of December 31, 2016 and 2015 is detailed below.

(in thousands)	Exploration and Production			Rice Midstream Partners
Balance, December 31, 2014	$	294,908		$	39,142
Impairment	(294,908		)	—
Balance, December 31, 2015	—			39,142
Additions (1)	384,431			455,438
Balance, December 31, 2016	$	384,431		$	494,580

(1) 2016 additions to goodwill are associated with the Vantage Acquisition. Please see Note 2 for further information.

Intangible Assets

Intangible assets are recorded under the acquisition method of accounting at their estimated fair values at the acquisition date. Fair value is calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The Company’s intangible assets are comprised of customer contracts acquired in our April 2014 acquisition of certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania. The customer contracts acquired had initial contract terms of 10 years with five and one-year renewal options. The Company calculates amortization of intangible assets using the straight-line method over the estimated useful life of the intangible assets, or 30 years. Amortization expense recorded in the consolidated statements of operations for the year ended December 31, 2016, 2015 and 2014 was $1.6 million, $1.6 million and $1.2 million, respectively. The estimated annual amortization expense over the next five years is as follows: 2017 $1.6 million, 2018 $1.6 million, 2019 $1.6 million, 2020 $1.6 million and 2021 $1.6 million.

Intangible assets, net as of December 31, 2016 and 2015 are detailed below.

(in thousands)	December 31, 2016			December 31, 2015
Intangible assets	$	48,947		$	48,947
Less: accumulated amortization	(4,422		)	(2,788		)
Intangible assets, net	44,525			46,159

Deferred Financing Costs

Deferred financing costs are amortized on a straight-line basis, which approximates the interest method, over the term of the related agreement. Accumulated amortization was $16.1 million and $8.6 million at December 31, 2016 and 2015, respectively. Amortization expense was $7.5 million, $5.1 million, and $2.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Asset Retirement Obligations

The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For oil and gas properties, this is the period in which an oil or gas well is acquired or drilled. The Company’s retirement obligations relate to the abandonment of oil and gas producing facilities and include costs to reclaim drilling sites and dismantle and reclaim or dispose of water services assets, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates. While components within our gathering systems will be replaced in the ordinary course of business, these systems will continue to exist indefinitely. Therefore, the timing of asset retirement obligations of our gathering systems is uncertain and a reasonable estimate cannot be established due to the lack of sufficient information.

When a new liability is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis. See Note 12 for additional information regarding asset retirement obligations.

Income Taxes

The Company is a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings. The Company did not report any income tax benefit or expense for periods prior to the consummation of its initial public offering (“IPO”) in January 2014 because Rice Drilling B LLC (“Rice Drilling B”), the Company’s accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of the Company’s business into a corporation in connection with the closing of its IPO required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of the completion of the IPO as it represents a transaction among shareholders. Additionally, the Company has presented pro forma earnings per share (“EPS”) for the year ended December 31, 2014 assuming a statutory rate as disclosed in the accompanying consolidated statements of operations was applied for the full year ended December 31, 2014.

The two-step approach is used for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized. Based on management’s analysis, the Company did not have any uncertain tax positions as of December 31, 2016.

The Company will record a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations requires judgment by us and may be challenged by the taxation authorities.

Segment Reporting

Business segments are components of the Company for which separate financial information is produced internally and are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources. The Company reports its operations in three segments: (i) the Exploration and Production segment, (ii) the Rice Midstream Holdings segment and (iii) the Rice Midstream Partners segment. Operating segments are evaluated for their contribution to the Company’s combined results based on operating income. All of the Company’s operating revenues, income from operations and assets are located in the United States. See Note 8 for additional information regarding segment reporting.

Reclassifications

Certain reclassifications have been made to prior period financial information related to the presentation of debt issuance costs associated with the Company’s credit facilities. In the first quarter of 2016, the Company adopted Accounting Standards Updates (“ASU”) 2015-03 “Interest-Imputation of Interest (Subtopic 835-30): Simplification of Debt Issuance Costs.” and ASU 2015-15 “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” The Company has retrospectively applied the guidance in ASU 2015-03 and ASU 2015-15, which resulted in the reclassification of $21.4 million of deferred financing costs related

to the Notes (defined herein) from deferred financing costs, net, to long-term debt on the consolidated balance sheet at December 31, 2015.

2. Property, Plant and Equipment

The Company’s property, plant and equipment are as follows as of December 31, 2016 and 2015.

	December 31,
(in thousands)	2016			2015
Oil and gas producing properties	$	5,791,284		$	2,870,691
Impairment of fixed assets	(2,765		)	—
Impairment of gas properties	(20,853		)	(18,250		)
Accumulated depreciation	(883,055		)	(498,467		)
Oil and gas producing properties, net	4,884,611			2,353,974
Midstream property and equipment	1,274,150			889,776
Impairment of fixed assets	(20,292		)	—
Accumulated depreciation	(54,771		)	(25,662		)
Midstream property and equipment, net	1,199,087			864,114
Other property and equipment	50,731			34,425
Accumulated depreciation	(16,517		)	(9,382		)
Other property and equipment, net	34,214			25,043
Property, plant and equipment, net	$	6,117,912		$	3,243,131

3. Acquisitions

Vantage Acquisition

On October 19, 2016, the Company completed the Vantage Acquisition pursuant to the terms of the Purchase and Sale Agreement (the “Vantage Purchase Agreement”) dated September 26, 2016 by the Company, Vantage Energy Investment LLC, Vantage Energy Investment II LLC and Vantage. Pursuant to the terms of the Vantage Purchase Agreement, Rice Energy Operating acquired Vantage from the Vantage Sellers for approximately $2.7 billion, which consisted of approximately $1.0 billion in cash, the assumption of net debt of approximately $707.0 million and the issuance of 40.0 million units in Rice Energy Operating that were immediately exchangeable into 40.0 million shares of common stock of the Company, valued at approximately $1.0 billion. In connection with executing the Vantage Purchase Agreement, the Company transferred $270.0 million to escrow as an acquisition deposit which was released in connection with the completion of the Vantage Acquisition to the Vantage Sellers as a portion of the cash consideration. Concurrent with the completion of the Vantage Acquisition, the Company extinguished the debt assumed from the Vantage Sellers for $707.0 million in cash, which approximated the fair value of the debt at the time of extinguishment. In addition, the Vantage Sellers were issued 1/1,000th of a share of Company preferred stock for each REO common unit they received. These shares of preferred stock are intended to provide holders with non-economic voting rights in the Company and are extinguished upon conversion of the associated REO common units into Company common stock. On September 30, 2016, the Company issued and completed a public offering (the “September 2016 Equity Offering”) of common stock, the net proceeds from which were used to pay for a portion of the Vantage Acquisition. Pursuant to the Vantage Purchase Agreement, the Company acquired approximately 85,000 net core Marcellus acres in Greene County, Pennsylvania, with rights to the deeper Utica Shale on approximately 52,000 net acres and approximately 36,000 net acres in the Barnett Shale.

On September 26, 2016, the Company entered into a Purchase and Sale Agreement (the “Midstream Purchase Agreement”) by and between the Company and the Partnership. Pursuant to the terms of the Midstream Purchase Agreement, as amended, immediately following the close of the Vantage Acquisition on October 19, 2016, the Partnership acquired from Rice Energy Operating all of the outstanding membership interests of Vantage Energy II Access, LLC and Vista Gathering, LLC (collectively, the “Vantage Midstream Entities”). The Partnership’s acquisition of the Vantage Midstream Entities from Rice Energy Operating is accounted for as a combination of entities under common control at historical cost. The Vantage Midstream Entities, which became wholly-owned subsidiaries of the Partnership upon the completion of the acquisition of the Vantage Midstream Entities, own

midstream assets, including approximately 30 miles of dry gas gathering and compression assets. In consideration for the acquisition of the Vantage Midstream Entities, the Partnership paid Rice Energy Operating $600.0 million in aggregate cash consideration, which the Partnership funded through the net proceeds of a private placement of Partnership common units and borrowings under its revolving credit facility. Acquisition costs of $5.4 million were incurred related to the Vantage Acquisition.

Allocation of Purchase Price

The Vantage Acquisition has been accounted for as a business combination, using the acquisition method. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets and liabilities assumed based on the fair value as of October 19, 2016, with any excess of the purchase price over the estimated fair value of the identified net assets acquired recorded as goodwill. Approximately, $384.5 million and $455.4 million of goodwill has been allocated to the Exploration and Production segment and Rice Midstream Partners segment, respectively. Goodwill primarily relates to the Company’s ability to control the Vantage acquired assets and recognize synergies related to administrative and capital efficiencies, extended laterals and the creation of additional contiguous leasing opportunities not previously available. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, title defect analysis and final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation once the Company has received all of the necessary information, during which time the value of the assets and liabilities may be revised as appropriate. Goodwill associated with the Vantage Acquisition is fully deductible for tax purposes.

(in thousands)
Consideration Given:
Fair value of issued Rice Energy Operating units	$	1,001,200
Cash consideration, net of cash acquired	981,080
Total consideration	$	1,982,280

Estimated Fair Value of Assets Acquired and Liabilities Assumed:
Current assets, net of cash acquired	$	49,532
Natural gas and oil properties	2,178,076
Midstream property, plant and equipment	144,562
Other non-current assets	27,437
Current liabilities	(103,322		)
Fair value of debt assumed	(706,912		)
Other non-current liabilities	(51,052		)
Noncontrolling interest in Rice Energy Operating	(395,910		)
Total estimated fair value of assets acquired and liabilities assumed	$	1,142,411
Goodwill	839,869

The fair value of natural gas and oil properties are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of natural gas and oil properties were measured using valuation techniques that convert future cash flows into a single discounted amount. Significant inputs to the valuation of natural gas and oil properties included 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 cost of capital rate. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive and may be subject to change. The fair value of undeveloped property was determined based upon a market approach of comparable transactions using Level 3 inputs.

The fair value measurements of the debt assumed were determined using Level 1 inputs. The debt balance includes amounts related to Vantage’s second lien note and amounts outstanding under Vantage’s credit facility, which were assumed by the Company and repaid concurrent to the Vantage Acquisition.

The valuation of Rice Energy Operating common units issued as consideration were primarily calculated based upon Level 1 inputs. The common unit value was included as an input in determining the fair value of the

noncontrolling interests which were further adjusted using level 3 inputs to reflect the value of the 16.49% ownership retained by the Vantage Sellers.

Post-Acquisition Operating Results

Subsequent to the completion of the Vantage Acquisition, the acquired entities contributed the following to the Company’s consolidated operating results for the period from October 19, 2016 through December 31, 2016.

(in thousands)
Revenue attributable to Rice Energy Inc.	$	51,645
Net income attributable to noncontrolling interests	$	914
Net income attributable to Rice Energy Inc.	$	4,629

Pro Forma Information

The following unaudited pro forma combined financial information presents the Company’s results as though the Vantage Acquisition had been completed at January 1, 2015. The pro forma combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the Vantage Acquisition taken place on January 1, 2015; furthermore, the financial information is not intended to be a projection of future results.

	Year Ended December 31,
(in thousands, except per share data) (unaudited)	2016			2015
Pro forma operating revenues	$	935,639		$	661,701
Pro forma net loss	$	(521,336	)	$	(202,292	)
Pro forma net loss attributable to noncontrolling interests	$	(85,961	)	$	(33,355	)
Pro forma net loss attributable to Rice Energy	$	(435,375	)	$	(181,055	)
Pro forma loss per share (basic)	$	(2.68	)	$	(1.33	)
Pro forma loss per share (diluted)	$	(2.68	)	$	(1.33	)

Murray Energy Acquisition

On October 26, 2016, the Company entered into a purchase and sale agreement (the “Murray Purchase Agreement”) by and between the Company and Murray Energy Corporation (“Murray Energy”), an Ohio-based privately owned coal company. Pursuant to the Murray Purchase Agreement, Murray Energy agreed to sell approximately 5,900 Utica Shale acres located in Belmont and Monroe Counties, Ohio to the Company for $60.6 million, which consisted of a cash payment at closing of approximately $44.3 million, payments of $7.5 million in cash due in each of October 2017 and October 2018, and the assumption of net debt of approximately $1.3 million. On November 4, 2016, the Company completed the Murray Energy acquisition, which included all sub-surface rights, including any royalty and working interests owned by Murray Energy in the underlying acreage.

4. Long-Term Debt

Long-term debt consists of the following as of December 31, 2016 and 2015:

	December 31,
(in thousands)	2016		2015
Long-term Debt
Senior Notes Due 2022, net of unamortized deferred financing costs and original discount issuances of $12,023 and $14,316, respectively (a)	$	887,977	$	885,684
Senior Notes Due 2023, net of unamortized deferred financing costs and original discount issuances of $8,496 and $9,894, respectively (b)	391,504		390,106
Senior Secured Revolving Credit Facility(c)	—		—
Midstream Holdings Revolving Credit Facility(d)	53,000		17,000
RMP Revolving Credit Facility(e)	190,000		143,000
Total debt	$	1,522,481	$	1,435,790
Less current portion	—		—
Long-term debt	$	1,522,481	$	1,435,790

Senior Notes

6.25% Senior Notes Due 2022 (a)

The Company has $900.0 million in aggregate principal amount of 6.25% senior notes due 2022 outstanding (the “2022 Notes”). The 2022 Notes will mature on May 1, 2022, and interest is payable on the 2022 Notes on each May 1 and November 1. At any time prior to May 1, 2017, the Company may redeem up to 35% of the 2022 Notes at a redemption price of 106.25% of the principal amount, plus accrued and unpaid interest, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2022 Notes remains outstanding after such redemption. Prior to May 1, 2017, the Company may redeem some or all of the 2022 Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest. Upon the occurrence of a change of control, unless the Company has given notice to redeem the 2022 Notes, the holders of the 2022 Notes will have the right to require the Company to repurchase all or a portion of the 2022 Notes at a price equal to 101% of the aggregate principal amount of the 2022 Notes, plus any accrued and unpaid interest. On or after May 1, 2017, the Company may redeem some or all of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.688% for the twelve-month period beginning on May 1, 2017, 103.125% for the twelve-month period beginning May 1, 2018, 101.563% for the twelve-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020, plus accrued and unpaid interest.

7.25% Senior Notes Due 2023 (b)

The Company issued $400.0 million in aggregate principal amount of 7.25% senior notes due 2023 outstanding (the “2023 Notes”). For the years ended December 31, 2016 and 2015, the Company recorded $0.4 million and $0.3 million, respectively, of amortization of the debt discount as interest expense using the effective interest rate method and a rate of 7.345%.

The 2023 Notes will mature on May 1, 2023, and interest is payable on the 2023 Notes on each May 1 and November 1, commencing on November 1, 2015. At any time prior to May 1, 2018, the Company may redeem up to 35% of the 2023 Notes at a redemption price of 107.250% of the principal amount, plus accrued and unpaid interest, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2023 Notes remains outstanding after such redemption. Prior to May 1, 2018, the Company may redeem some or all of the notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest. Upon the occurrence of a change of control, unless the Company has given notice to redeem the 2023 Notes, the holders of the 2023 Notes will have the right to require the Company to repurchase all or a portion of the 2023 Notes at a price equal to 101% of the aggregate principal amount of the 2023 Notes, plus any accrued and unpaid interest. On or after May 1, 2018, the Company may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438% for the twelve-month period beginning on May 1, 2017, 103.625% for the twelve-month period beginning May 1, 2019, 101.813% for the twelve-month period beginning on May 1, 2020 and 100.000% beginning on May 1, 2021, plus accrued and unpaid interest.

The 2022 Notes and the 2023 Notes (collectively, the “Notes”) are the Company’s senior unsecured obligations, rank equally in right of payment with all of the Company’s existing and future senior debt, and will rank senior in right of payment to all of the Company’s future subordinated debt. The Notes will be effectively subordinated to all of the Company’s existing and future secured debt to the extent of the value of the collateral securing such indebtedness. The Notes are jointly and severally, fully and unconditionally, guaranteed by the Company’s Guarantors.

Senior Secured Revolving Credit Facility (c)

In April 2013, the Company entered into a Senior Secured Revolving Credit Facility (the “Senior Secured Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders. In April 2014, the Company, as borrower, and Rice Drilling B, as predecessor borrower, amended and restated the credit agreement governing the Senior Secured Revolving Credit Facility (the “Amended Credit Agreement”) to, among other things, assign all of the rights and obligations of Rice Drilling B as borrower under the Senior Secured Revolving Credit Facility to the Company.

In connection with the closing of the Vantage Acquisition, on October 19, 2016, the Company entered into a Fourth Amended and Restated Credit Agreement (the “A&R Credit Agreement”) effective upon the closing of the Vantage Acquisition to, among other things, (i) permit the completion of the Vantage Acquisition, (ii) extend the maturity date of the credit facility from January 29, 2019 to October 19, 2021, (iii) increase the borrowing base from $875.0 million to $1.0 billion without giving effect to the oil and gas properties acquired pursuant to the Vantage Acquisition, (iv) provide for the assignment of the Company’s rights and obligations as borrower under the Senior Secured Revolving Credit Facility to Rice Energy Operating and the addition of the Company as a guarantor of those obligations, (v) increase the minimum required mortgage percentage (as it applies to proved reserves) to be 85% of proved reserves, (vi) amend the restricted payments covenant to permit certain distributions by Rice Energy Operating to its members, (vii) replace the interest coverage ratio with a consolidated total leverage ratio or consolidated net leverage ratio, as applicable, to commence with the last day of the fiscal quarter ended December 31, 2016 and (viii) adjust the interest rate payable on amounts borrowed thereunder (as described below).

On December 19, 2016, Rice Energy Operating, as borrower, and the Company, as predecessor borrower, entered into the First Amendment to the A&R Credit Agreement among Rice Energy Operating, the Company, Wells Fargo Bank, N.A., as administrative agent, and the lenders and other parties thereto (the “First Amendment”). The lenders under the A&R Credit Agreement completed an Interim Redetermination (as defined in the A&R Credit Agreement) of the borrowing base to give effect to the Pennsylvania oil and gas properties acquired in the Vantage Acquisition and, upon the effectiveness of the First Amendment and such Interim Redetermination, the Company’s borrowing base and the elected commitment amounts of the lenders under the Senior Secured Revolving Credit Facility increased from $1.0 billion to $1.45 billion.

As of December 31, 2016, the borrowing base was $1.45 billion and the sublimit for letters of credit was $400.0 million. The Company had zero borrowings outstanding and $240.9 million in letters of credit outstanding under the A&R Credit Agreement as of December 31, 2016, resulting in availability of $1.21 billion. The next redetermination of the borrowing base is scheduled for April 2017.

As of December 31, 2016, the Senior Secured Revolving Credit Facility was secured by liens on at least 85% of the proved oil and gas reserves of the Company and its subsidiaries (other than any subsidiary that is designated as an unrestricted subsidiary, including Midstream Holdings and its subsidiaries), as well as significant unproved acreage and substantially all of the personal property of the Company and such restricted subsidiaries, and the Senior Secured Revolving Credit Facility is guaranteed by such restricted subsidiaries.

The A&R Credit Agreement requires us to maintain certain financial ratios, which are measured at the end of each calendar quarter:

· a consolidated current ratio, which is (a) the ratio of consolidated current assets (including unused commitments under the A&R Credit Agreement and excluding non-cash derivative assets) to

consolidated current liabilities (excluding current maturities under the A&R Credit Agreement), of not less than 1.0 to 1.0; or (b) if no borrowings are then outstanding; and

· a consolidated leverage ratio, which is if borrowings are outstanding under the A&R Credit Agreement on the last day of such calendar quarter, the ratio of consolidated total funded debt to EBITDAX (as such term is defined in the A&R Credit Agreement) of not more than 4.0 to 1.0; and

· the ratio of consolidated net funded debt to EBITDAX (as such term is defined in the A&R Credit Agreement) of not more than 4.0 to 1.0.

The Company was in compliance with its covenants and ratios effective as of December 31, 2016.

Midstream Holdings Revolving Credit Facility (d)

On December 22, 2014, Rice Midstream Holdings LLC (“Midstream Holdings”) entered into a revolving credit facility (the “Midstream Holdings Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $300.0 million and a sublimit for letters of credit of $25.0 million. As of December 31, 2016, Midstream Holdings had $53.0 million of borrowings outstanding and no letters of credit under this facility, resulting in availability of $247.0 million. The average daily outstanding balance of the Midstream Holdings Revolving Credit Facility was approximately $27.1 million and interest was incurred on the facility at a weighted average annual interest rate of 5.6% during 2016. The Midstream Holdings Revolving Credit Facility is available to fund working capital requirements and capital expenditures and to purchase assets. The maturity date of the Midstream Holdings Revolving Credit Facility is December 22, 2019.

The Midstream Holdings Revolving Credit Facility limits Midstream Holdings’ and its restricted subsidiaries’ ability to, among other things, incur or guarantee additional debt; redeem or repurchase units or make distributions under certain circumstances; make certain investments and acquisitions; incur certain liens or permit them to exist; enter into certain types of transactions with affiliates; merge or consolidate with another company; and transfer, sell or otherwise dispose of assets.

The Midstream Holdings Revolving Credit Facility will also require Midstream Holdings to maintain the following financial ratios:

· an interest coverage ratio, which is the ratio of Midstream Holdings’ consolidated EBITDA (as defined within the Midstream Holdings Revolving Credit Facility) to its consolidated current interest expense of at least 2.50 to 1.0 at each end of each fiscal quarter; and

· a consolidated total leverage ratio, which is the ratio of Midstream Holdings consolidated debt to its consolidated EBITDA, of not more than 4.25 to 1.0.

RMP Revolving Credit Facility (e)

On December 22, 2014, Rice Midstream OpCo LLC (“Rice Midstream OpCo”), a wholly-owned subsidiary of the Partnership, entered into a revolving credit facility (the “RMP Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders. The RMP Revolving Credit Facility provides for lender commitments of $450.0 million with an additional $200.0 million of commitments available under an accordion feature, subject to lender approval. The RMP Revolving Credit Facility provides for a letter of credit sublimit of $50.0 million. In connection with the completion of the Partnership’s acquisition of the midstream assets associated with the Vantage Acquisition from the Company (the “Vantage Midstream Asset Acquisition”), on October 19, 2016, Rice Midstream OpCo entered into a second amendment (the “Second Amendment”) to its credit agreement to, among other things, (i) permit the completion of the Vantage Midstream Asset Acquisition, (ii) increase the Partnership’s ability to borrow under the facility from $450.0 million to $850.0 million, without exercise of any portion of the $200.0 million accordion feature and (iii) adjust the interest rate payable on amounts borrowed thereunder (as described below).

As of December 31, 2016, Rice Midstream OpCo had $190.0 million borrowings outstanding and no letters of credit under this facility, resulting in availability of $660.0 million. The average daily outstanding balance of the RMP Revolving Credit Facility was approximately $110.0 million and interest was incurred on the facility at a weighted average annual interest rate of 4.7% during 2016. The RMP Revolving Credit Facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes and matures on December 22, 2019. The Partnership is the guarantor of the obligations under the credit facility.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Under the RMP Revolving Credit Facility, Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Following the effectiveness of the Second Amendment, Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 200 to 300 basis points, depending on the leverage ratio then in effect, and base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the leverage ratio then in effect. Following the effectiveness of the Second Amendment, Rice Midstream OpCo also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The RMP Revolving Credit Facility is secured by mortgages and other security interests on substantially all of RMP’s properties and guarantees from RMP and its restricted subsidiaries. The RMP Revolving Credit Facility limits the ability of RMP and its restricted subsidiaries to, among other things, incur or guarantee additional debt; redeem or repurchase units or make distributions under certain circumstances; make certain investments and acquisitions; incur certain liens or permit them to exist; enter into certain types of transactions with affiliates; merge or consolidate with another company; and transfer, sell or otherwise dispose of assets.

The RMP Revolving Credit Facility also requires RMP to maintain the following financial ratios:

· an interest coverage ratio, which is the ratio of RMP’s consolidated EBITDA (as defined within the RMP Revolving Credit Facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter;

ratio of not more than 5.25 to 1.0, and, in each case, with certain increases in the permitted total leverage ratio following the completion of a material acquisition; and

Expected Aggregate Maturities

Expected aggregate maturities of the notes payable as of December 31, 2016 are as follows (in thousands):

Year Ending December 31, 2017	$	—
Year Ending December 31, 2018	—
Year Ending December 31, 2019	243,000
Year Ending December 31, 2020 and Beyond	1,279,481
Total	$	1,522,481

Interest paid in cash was $98.7 million, $82.1 million and $36.7 million for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 1 for information on capitalized interest.

5. Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. Substantially all of the Company’s derivative counterparties share in the Senior Secured Revolving Credit Facility collateral. The Company has entered into various derivative contracts to manage price risk and to achieve more predictable cash flows. As a result of the Company’s hedging activities, the Company may realize prices that are greater or less than the market prices that it would have received otherwise.

As of December 31, 2016, the Company has entered into derivative instruments with various financial institutions, fixing the price it receives for a portion of its futures sales of produced natural gas. The Company’s fixed price derivatives primarily include swap and collar contracts that are tied to the commodity prices on NYMEX. As of December 31, 2016, the Company has entered into NYMEX hedging contracts through December 31, 2020 covering a total of approximately 941 Bcf of our projected natural gas production at a weighted average price of $3.09 per MMBtu. Additionally, the Company has entered into basis swap contracts to hedge the difference between the NYMEX index price and various local index prices. The fixed price and basis hedging contracts the Company has entered into through December 31, 2021 at other various sales points cover a total of approximately 784 Bcf.

The Company recognizes all derivative instruments as either assets or liabilities at fair value per the FASB ASC 815. The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized currently in earnings. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value:

	As of December 31, 2016
(in thousands)	Derivative instruments, gross		Derivative instruments subject to master netting arrangements			Derivative Instruments, net
Derivative assets	$	103,507	$	(63,490	)	$	40,017
Derivative liabilities	$	286,019	$	(120,154	)	$	165,865

	As of December 31, 2015
(in thousands)	Derivative instruments, gross		Derivative instruments subject to master netting arrangements			Derivative Instruments, net
Derivative assets	$	372,414	$	(79,509	)	$	292,905
Derivative liabilities	$	21,043	$	(4,200	)	$	16,843

6. Fair Value of Financial Instruments

The Company determines the fair value of its financial instruments, which are comprised primarily of derivative instruments, on a recurring basis as these instruments are required to be recorded at fair value for each reporting amount. Certain amounts in the Company’s financial statements were measured at fair value on a nonrecurring basis including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Company has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The Company’s fair value measurements relating to derivative instruments are included in Level 2. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.

Items included in Level 3 are valued using internal models that use significant unobservable inputs. Items included in Level 2 are valued using management’s best estimate of fair value corroborated by third-party quotes.

The following assets and liabilities were measured at fair value on a recurring basis during the period (refer to Note 5 for details relating to derivative instruments):

	As of December 31, 2016
			Fair Value Measurements at Reporting Date Using
(in thousands)	Carrying Value		Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value	$	40,017	$	40,017	$	—	$	40,017	$	—
Total assets	$	40,017	$	40,017	$	—	$	40,017	$	—

Liabilities:
Derivative instruments, at fair value	$	165,865	$	165,865	$	—	$	165,865	$	—
Total liabilities	$	165,865	$	165,865	$	—	$	165,865	$	—

	As of December 31, 2015
			Fair Value Measurements at Reporting Date Using
(in thousands)	Carrying Value		Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value	$	292,905	$	292,905	$	—	$	292,905	$	—
Total assets	$	292,905	$	292,905	$	—	$	292,905	$	—

Liabilities:
Derivative instruments, at fair value	16,844		16,844		—		16,844		—
Total liabilities	$	16,844	$	16,844	$	—	$	16,844	$	—

The carrying value of cash equivalents approximates fair value due to the short maturity of the instruments. The Company’s non-financial assets, such as property, plant and equipment, goodwill and intangible assets are recorded at fair value upon business combination and are remeasured at fair value only if an impairment charge is recognized. To the extent necessary, the Company applies unobservable inputs and management judgment due to the absence of quoted market prices (Level 3) to the valuation methodologies for these non-financial assets.

The estimated fair value and gross carrying amount of long-term debt as reported on the consolidated balance sheets as of December 31, 2016 and 2015 is shown in the table below (refer to Note 4 for details relating to the debt instruments). The fair value was estimated using Level 2 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position. The gross carrying value of the revolving credit facilities approximates fair value for the periods presented below.

	As of December 31, 2016				As of December 31, 2015
Long-Term Debt (in thousands)	Carrying Value		Fair Value		Carrying Value		Fair Value
Senior Notes Due 2022	$	900,000	$	929,250	$	900,000	$	650,250
Senior Notes Due 2023	397,601		428,000		397,222		294,000
Midstream Holdings Revolving Credit Facility	53,000		53,000		17,000		17,000
RMP Revolving Credit Facility	190,000		190,000		143,000		143,000
Other	—		—		—		—
Total	$	1,540,601	$	1,600,250	$	1,457,222	$	1,104,250

7. Rice Midstream Partners LP

In August 2014, the Company formed the Partnership to own, operate, develop and acquire midstream assets in the Appalachian Basin. The Partnership’s assets consist of gathering pipelines and compressor stations, as well as water handling and treatment facilities. The Partnership provides gathering and compression and water services to the Company and third parties.

The Partnership completed its IPO in December 2014, issuing 28,750,000 common units representing limited partner interests in the Partnership, which represented 50% of the Partnership’s outstanding equity. The Company retained a 50% limited partner interest in the Partnership, consisting of 3,623 common units and 28,753,623 subordinated units. In connection with the RMP IPO, the Company contributed to the Partnership 100% of Rice

Poseidon Midstream LLC. Rice Midstream Management LLC, a wholly-owned subsidiary of the Company, serves as the general partner of the Partnership.

In February 2016, Midstream Holdings assigned all of its equity interests in the Partnership, consisting of 3,623 common units, 28,753,623 subordinated units and all of its incentive distribution rights in the Partnership, to GP Holdings.

In June 2016, the Partnership completed an underwritten public offering of 9,200,000 common units representing limited partner interests in the Partnership at a price to the public of $18.50 per unit, which included 1,200,000 common units sold pursuant to the exercise of the underwriters’ option to purchase additional units. After deducting underwriting discounts and commissions of approximately $6.0 million and transaction costs, the Partnership received net proceeds of approximately $164.1 million. The Partnership used a portion of the net proceeds to repay outstanding debt and the remainder for general partnership purposes, including acquisitions and capital expenditures.

During the second quarter of 2016, the Partnership entered into an equity distribution agreement that established an at-the-market common unit offering program (the “ATM program”), pursuant to which the Partnership may sell from time to time through a group of managers, acting as the Partnership’s sales agents, the Partnership’s common units having an aggregate offering price of up to $100.0 million. As of December 31, 2016, the Partnership had issued and sold 944,700 common units at an average price per unit of $17.21 through its ATM program. The Partnership used the net proceeds of $15.8 million for general partnership purposes, including repayment of outstanding debt, acquisitions and capital expenditures.

On September 26, 2016, the Company entered into the Midstream Purchase Agreement by and between the Company and the Partnership. Pursuant to the terms of the Midstream Purchase Agreement, as amended, immediately following the close of the Vantage Acquisition on October 19, 2016, the Partnership acquired from Rice Energy the Vantage Midstream Entities. The Partnership’s acquisition of the Vantage Midstream Entities from Rice Energy Operating is accounted for as a combination of entities under common control at historical cost. In consideration for the acquisition of the Vantage Midstream Asset Acquisition, the Partnership paid Rice Energy Operating $600.0 million in aggregate cash consideration, which the Partnership funded through the net proceeds of a private placement of Partnership common units and borrowings under its revolving credit facility. In addition, in connection with the Vantage Midstream Asset Acquisition, the Partnership acquired a 67.5% interest in the Wind Ridge Gathering System previously owned by Access Midstream Partners for approximately $14.3 million, of which $10.9 million was ascribed to property and equipment and $3.4 million to goodwill.

On October 7, 2016, the Partnership issued 20,930,233 common units representing limited partner interests in the Partnership in a private placement (the “Private Placement”) for gross proceeds of approximately $450.0 million, or $21.50 per unit. After deducting underwriting discounts and commissions of approximately $9.4 million, the Partnership received net proceeds of $440.6 million. The Partnership used the proceeds of the Private Placement to fund a portion of the Vantage Midstream Asset Acquisition.

The following table presents the Partnership’s common and subordinated units issued from January 1, 2015 through December 31, 2016:

	Limited Partners			GP Holdings
	Common	Subordinated	Total	Ownership %
Balance, January 1, 2015	28,753,623	28,753,623	57,507,246	50	%
Equity offering in November 2015	13,409,961	—	13,409,961
Vested phantom units, net	165	—	165
Balance, December 31, 2015	42,163,749	28,753,623	70,917,372	41	%
Equity offering in June 2016	9,200,000	—	9,200,000
Equity offering in October 2016	20,930,233	—	20,930,233
Common units issued under ATM program	944,700	—	944,700
Vested phantom units, net	280,451	—	280,451
Balance, December 31, 2016	73,519,133	28,753,623	102,272,756	28	%

As of December 31, 2016 and 2015, GP Holdings owned approximately 28% and 41%, respectively, and Rice Energy Operating indirectly owned approximately 26% and 41% of the Partnership, respectively, consisting of 3,623 common units, 28,753,623 subordinated units and all of the incentive distribution rights. The 16.49% membership interest in Rice Energy Operating owned by the Vantage Sellers does not impact Rice Energy Operating’s indirect ownership in the Partnership.

The Company consolidates the results of the Partnership and records an income tax provision only as to its ownership percentage. The Company records the noncontrolling interest of the public limited partners in its consolidated financial statements for net income of the Partnership attributed to third party unitholders for periods subsequent to the RMP IPO. Net income attributable to noncontrolling interests, before taking into consideration the Vantage Sellers membership interest of 16.49% and EIG’s 8.25% ownership interest in GP Holdings, was $80.0 million and $23.3 million for the years ended December 31, 2016 and 2015, respectively.

On January 20, 2017, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2016 of $0.2505 per common and subordinated unit. The cash distribution was paid on February 16, 2017 to unitholders of record at the close of business on February 7, 2017. Also on February 16, 2017, a cash distribution of $0.9 million was made to GP Holdings related to its incentive distribution rights in the Partnership in accordance with the Partnership agreement.

8. Financial Information by Business Segment

As a result of changes to the Company’s operations in the first quarter of 2016, management evaluated how the Company is organized and operates and identified the Exploration and Production segment, the Rice Midstream Holdings segment and the Rice Midstream Partners segment as separate operating segments. The segments represent components of the Company that engage in activities (a) from which revenue is earned and expenses are incurred; (b) whose operating results are regularly reviewed by the Chief Operating Decision Maker, who makes decisions about resources to be allocated to the segment and (c) for which discrete financial information is available. As a result of the changes to the Company’s operating segments, all prior period information has been revised to reflect the new operating segment structure. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Other income and expenses, interest and income taxes are managed on a consolidated basis. The segment accounting policies are the same as those described in Note 1 of this report.

The operating results and assets of the Company’s reportable segments were as follows as of and for the year ended December 31, 2016:

(in thousands)	Exploration and Production			Rice Midstream Holdings		Rice Midstream Partners		Elimination of Intersegment Transactions			Consolidated Total
Total operating revenues	$	677,849		$	63,934	$	201,623	$	(164,500	)	$	778,906
Total operating expenses	844,756			50,325		74,681		(125,826		)	843,936
Operating (loss) income	$	(166,907	)	$	13,609	$	126,942	$	(38,674	)	$	(65,030	)

Segment assets	$	6,120,530		$	360,292	$	1,399,217	$	(62,517	)	$	7,817,522
Goodwill	$	384,431		$	—	$	494,580	$	—		$	879,011
Depreciation, depletion and amortization	$	350,187		$	5,760	$	25,170	$	(12,662	)	$	368,455
Capital expenditures for segment assets	$	690,212		$	110,889	$	118,087	$	(38,673	)	$	880,514

The operating results and assets of the Company’s reportable segments were as follows as of and for the year ended December 31, 2015:

(in thousands)	Exploration and Production			Rice Midstream Holdings		Rice Midstream Partners		Elimination of Intersegment Transactions			Consolidated Total
Total operating revenues	$	452,962		$	27,364	$	114,459	$	(92,644	)	$	502,141
Total operating expenses	944,117			13,671		52,423		(69,903		)	940,308
Operating (loss) income	$	(491,155	)	$	13,693	$	62,036	$	(22,741	)	$	(438,167	)

Segment assets	$	2,982,793		$	300,148	$	689,790	$	(23,633	)	$	3,949,098
Goodwill	$	—		$	—	$	39,142	$	—		$	39,142
Depreciation, depletion and amortization	$	308,194		$	2,786	$	16,399	$	(4,595	)	$	322,784
Capital expenditures for segment assets	$	869,134		$	156,013	$	248,463	$	(27,336	)	$	1,246,274

The operating results and assets of the Company’s reportable segments were as follows as of and for the year ended December 31, 2014:

(in thousands)	Exploration and Production		Rice Midstream Holdings			Rice Midstream Partners			Elimination of Intersegment Transactions			Consolidated Total
Total operating revenues	$	385,438	$	852		$	6,448		$	(1,796	)	$	390,942
Total operating expenses	356,019		10,126			37,015			(1,796		)	401,364
Operating income (loss)	$	29,419	$	(9,274	)	$	(30,567	)	$	—		$	(10,422	)
Segment assets	$	2,935,814	$	149,044		$	443,091		$	—		$	3,527,949
Goodwill	$	294,908	$	—		$	39,142		$	—		$	334,050
Depreciation, depletion and amortization	$	151,900	$	205		$	4,165		$	—		$	156,270
Capital expenditures for segment assets	$	693,129	$	107,319		$	169,826		$	—		$	970,274

9. Commitments and Contingencies

On October 14, 2013, the Company entered into a Development Agreement and Area of Mutual Interest Agreement (collectively, the “Utica Development Agreements”) with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. Pursuant to the Utica Development Agreements, the Company had approximately 68.7% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Goshen and Smith Townships (the “Northern Contract Area”) and an approximately 48.2% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Wayne and Washington Townships (the “Southern Contract Area”), each within Belmont County, Ohio. The majority of the remaining participating interests are held by Gulfport. The participating interests of the Company and Gulfport in each of the Northern and Southern Contract Areas approximated the Company’s then-current relative acreage positions in each area.

The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and the Company and Gulfport shall remain operators of drilling units located in the Northern and Southern Contract Areas, respectively, following such termination.

Firm Transportation

The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments under these contracts as of December 31, 2016 totaled $4,917.2 million (2017 - $165.6 million, 2018 - $240.7 million, 2019 - $234.0 million, 2020 - $233.7 million, 2021 - $233.4 million and thereafter - $3,809.8 million).

Drilling Rig Service Commitments

The Company has three horizontal rigs under contract, of which two expire in 2017 and one expires in 2018. The Company also has one tophole drilling rig under contract, which expires in 2018. Future payments under these contracts as of December 31, 2016 totaled $36.7 million (2017 - $27.7 million and 2018 - $9.0 million). Any other rig performing work for the Company is performed on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well, the costs of which have not been included in the amounts above. The values above represent the gross amounts that the Company is committed to pay without regard to its proportionate share based on its working interest.

Frac Sand Commitments

Commencing in January 2017, the Company has commitments for frac sand to be used as a proppant in its hydraulic fracturing operations. Future commitments under these contracts as of December 31, 2016 totaled $45.7 million (2017 - $15.2 million, 2018 - $15.2 million and 2019 - $15.4 million).

Litigation

From time to time the Company is party to various legal and/or regulatory proceedings arising in the ordinary course of business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, the Company believes that all such matters are without merit and involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows. When it is determined that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.

In 2016, the Company reached a settlement with the Pennsylvania Department of Environmental Protection (“PADEP”) related to civil penalties for certain Notices of Violations (“NOVs”) received from December 2011 through April 2016 under the Clean Streams Law, the 2012 Oil and Gas Act, the Solid Waste Management Act, and the Dam Safety and Encroachments Act and has paid fines to settle such NOVs with the PADEP for $3.6 million.

10. Mezzanine Equity

On February 17, 2016, the Company, Midstream Holdings and GP Holdings entered into a securities purchase agreement (the “Securities Purchase Agreement”) with EIG Energy Fund XVI, L.P., EIG Energy Fund XVI-E, L.P., and EIG Holdings (RICE) Partners, LP (collectively, the “Investors”) pursuant to which (i) Midstream Holdings agreed to issue and sell 375,000 Series B Units (“Series B Units”) with an aggregate liquidation preference of $375.0 million and (ii) GP Holdings agreed to issue and sell common units representing an 8.25% limited partner interest in GP Holdings (“GP Common Units”) for aggregate consideration of $375.0 million in a private placement (the “Midstream Holdings Investment”) exempt from the registration requirements under the Securities Act. In conjunction with the Securities Purchase Agreement, Midstream Holdings issued 1,000 Series A Units to Rice Energy Operating. The Midstream Holdings Investment closed on February 22, 2016 (the “Closing Date”).

In connection with the Closing Date, (i) REO and the Investors entered into the Amended and Restated Limited Liability Company Agreement of Midstream Holdings (the “LLC Agreement”), which defines the preferences, rights, powers and duties of holders of the Series B Units and (ii) Rice Midstream GP Management LLC (“GP Management”), as general partner of GP Holdings, and Midstream Holdings and the Investors, as limited partners, entered into the Amended and Restated Agreement of Limited Partnership of GP Holdings, which defines the preferences, rights, powers and duties of holders of the GP Holdings Common Units (the “GP Holdings A&R LPA”).

In connection with the Midstream Holdings Investment, Midstream Holdings received gross proceeds of $375.0 million, less transaction fees and expenses of approximately $6.2 million. Midstream Holdings used approximately $69.0 million of the proceeds to reduce outstanding borrowings under the Midstream Holdings Revolving Credit Facility, and $300.0 million was distributed to the Company.

Series B Units

Pursuant to the LLC Agreement, the Series B Units rank senior to all other equity interests in Midstream Holdings with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. The Series B Units will pay quarterly distributions at a rate of 8% per annum, payable in cash or “in-kind” through the issuance of additional Series B Units, subject to certain exceptions, at Midstream Holdings’ option for the first two years, and in cash thereafter. Distributions are payable on January 1, April 1, July 1 and October 1 of each year that the Series B Units remain outstanding. For the year ended December 31, 2016, the Company paid $26.2 million in distributions, of which $14.7 million was paid in cash and $11.5 million was paid in-kind.

In relation to the Series B Units, the occurrence of certain events or violations of certain financial and non-financial restrictions will constitute “Triggering Events” (as defined in the Securities Purchase Agreement) that may result in various consequences, including additional restrictions on the activities of Midstream Holdings, including the termination of the Investor’s additional commitment, increases in the distribution rate, additional governance rights for the Investors and other measures depending on the applicable Triggering Event. As of December 31, 2016, the Company views the likelihood of the occurrence of a Triggering Event to be remote.

In the event that Midstream Holdings or GP Holdings pursues an initial public offering, Midstream Holdings may redeem the Series B Units at a redemption price equal to the Liquidation Preference on the date of the closing of the applicable initial public offering plus all additional distributions that would have otherwise been paid through the third anniversary of the Closing Date. Midstream Holdings may satisfy this redemption price in cash or common equity interests of the entity that completes an initial public offering. In the event of any liquidation and winding up of Midstream Holdings, profits and losses will be allocated to the holders of the Series B Units so that, to the maximum extent possible, the capital accounts of the Series B unitholders will equal the aggregate Liquidation Preference.

GP Common Units

Pursuant to the GP Holdings A&R LPA, the holders of the GP Common Units are entitled to distributions of GP Holdings in proportion to their pro rata share of the outstanding GP Common Units. Distributions will occur upon GP Holdings receipt of any distributions of cash in respect of the equity interests in the Partnership held by GP Holdings.

The Investors holding GP Common Units have tag-along rights in connection with a sale of the common equity interests in GP Holdings to a third-party. The holders of GP Common Units will have drag-along rights in connection with a sale of the majority of the common equity interests in GP Holdings to a third-party, subject to the achievement of an agreed-upon minimum return. If a qualifying initial public offering of GP Holdings is not consummated prior to the fifth anniversary of the Closing Date, the holders of the GP Common Units shall have the right to require GP Holdings to repurchase all of their GP Common Units for cash in an aggregate purchase price of $125.0 million. In the event of a Change in Control or a GP Change in Control (as each term is defined in the GP Holdings A&R LPA) of the Company, Midstream Holdings or GP Holdings, the Purchasers shall have the right to require GP Holdings to repurchase all of their GP Common Units for an aggregate purchase price of $125.0 million. The holders of the GP Common Units do not have the power to vote or dispose of the Partnership’s units held by GP Holdings.

In the event GP Holdings sells any of its assets, subject to certain exceptions, GP Holdings may only make distributions of such proceeds to the extent that GP Holdings meets certain requirements, including the requirement to retain a certain amount of cash or cash equivalents following the sale of such assets. In the event of any liquidation and winding up of GP Holdings, GP Management, in its capacity as general partner, will appoint a liquidator to wind up the affairs and make final distributions as provided for in the GP Holdings A&R LPA.

From September 30, 2016 until the eighteen-month anniversary of the closing of the Midstream Holdings Investment, upon the satisfaction of certain financial and operational metrics, Midstream Holdings has the right to require the Investors to purchase additional Series B Units and GP Common Units. Midstream Holdings may require the Investors to purchase at least $25.0 million of additional units on up to three occasions, up to a total aggregate amount of $125.0 million. Pursuant to the Securities Purchase Agreement, Midstream Holdings is required to pay the Investors a quarterly cash commitment fee of 2% per annum on any undrawn amounts of the additional $125.0 million commitment. The commitment fee paid in cash was approximately $2.1 million for the year ended December 31, 2016. No additional units have been purchased by the Investors since the closing of the Midstream Holdings Investment.

As the Investors have an option to redeem the Series B Units and GP Common Units for cash at a future date, the proceeds from the redeemable noncontrolling interest (net of accretion and issuances costs and fees) are not considered to be a component of stockholders’ equity on the consolidated balance sheet, and such Series B Units and GP Common Units are reported as mezzanine equity on the consolidated balance sheet. The following table represents the value allocated to the Series B Units and GP Common Units at inception.

(in thousands)
At Inception
Noncontrolling interest in Series B Units	$	341,661
Noncontrolling interest in GP Holdings Common Units	33,339
Less: issuance costs and fees	(6,242		)
Carrying amount of redeemable noncontrolling interest at inception	$	368,758

While the Series B Units are not currently redeemable, the initial value allocated to them will be accreted to their full redemption value through February 22, 2026 using the effective interest rate method, as it is considered probable that they will become redeemable. The following table represents detail of the balance of redeemable noncontrolling interest, net on the consolidated balance sheet as of December 31, 2016.

(in thousands)
As of December 31, 2016
Face amount of Series B Units	$	375,000
Plus: distributions paid in kind	11,504
Less: discount	(31,592		)
Carrying amount of noncontrolling interest in Series B Units	354,912
Plus: Noncontrolling interest in GP Holdings Common Units	33,339
Less: unamortized issuance costs and fees	(5,726		)
Redeemable noncontrolling interest, net	$	382,525

11. Lease Obligations

The Company leases drilling rights under agreements which expire at various times. In addition, the Company leases various office spaces under lease agreements. The following represents the future minimum lease payments under these agreements as of December 31, 2016:

(in thousands)
2017	$	27,878
2018	13,536
2019	5,165
2020	3,772
2021 and thereafter	39,999
Total future minimum lease payments	$	90,350

Current lease obligations related to future minimum payments for leasehold bonuses are included in leasehold payable in the accompanying consolidated balance sheets.

12. Asset Retirement Obligations

The Company is subject to certain legal requirements which result in recognition of a liability related to the obligation to incur future plugging and abandonment costs of oil and gas producing facilities and costs to reclaim drilling sites and dismantle and reclaim or dispose of water services assets, wells and related structures. The Company records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Company’s credit adjusted risk-free rate. The current portion of asset retirement obligations are recorded in other accrued liabilities and the long term portion of asset retirement obligations are recorded in other long-term liabilities on the consolidated balance sheets.

A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2016 and 2015 is as follows:

(in thousands)
Balance at December 31, 2014	$	9,542
Liabilities incurred	5,198
Liabilities settled	(1,131		)
Accretion expense	890
Revisions in estimated cash flows	(3,085		)
Balance at December 31, 2015	$	11,414
Liabilities incurred	1,692
Liabilities assumed in Vantage Acquisition	33,401
Liabilities settled	(46		)
Accretion expense	1,372
Revisions in estimated cash flows (1)	25,708
Balance at December 31, 2016	$	73,540

(1) Current year revisions relate to an increase in the Company’s estimated cost to plug and abandon wells due to increased regulation of the locations in which the Company operates, as well as increases in estimated service costs.

13. Stockholders’ Equity

The Company’s Board of Directors did not declare or pay a dividend for the twelve months ended December 31, 2016. On January 20, 2017, a cash distribution of $0.2505 per common and subordinated unit was declared by the Partnership to the Partnership’s unitholders related to the fourth quarter of 2016. The cash distribution was paid on February 16, 2017 to unitholders of record at the close of business on February 7, 2017. Also on February 16, 2017, a cash distribution of $0.9 million was made to GP Holdings related to its incentive distribution rights in the Partnership in accordance with the partnership agreement.

On April 15, 2016, the Company issued and completed a public offering (the “April 2016 Equity Offering”) of an aggregate of 34,337,725 shares of common stock at a price to the public of $16.35 per share, which included 20,000,000 shares sold by the Company and 9,858,891 shares sold by NGP Rice Holdings LLC (“NGP Holdings”). On April 21, 2016, NGP Holdings sold an additional 4,478,834 shares of common stock pursuant to the exercise of the underwriter’s option to purchase additional shares. After deducting underwriting discounts and commissions of $15.0 million and transaction costs, the Company received net proceeds of $311.8 million. The Company received no proceeds from the sale of shares by NGP Holdings. The Company used the net proceeds of the April 2016 Equity Offering for general corporate purposes.

On September 30, 2016, the Company issued and completed the September 2016 Equity Offering of an aggregate of 40,000,000 shares of common stock at a price to the public of $25.50 per share. On October 11, 2016, the Company sold an additional 6,000,000 shares of common stock pursuant to the exercise of the underwriters’ option to purchase additional shares of common stock in connection with the September 2016 Equity Offering. After deducting underwriting discounts and commissions of approximately $17.9 million and transaction costs, the Company received net proceeds of approximately $1.2 billion, which includes proceeds from the exercised underwriters’ option. The Company used the net proceeds from the offering primarily to fund a portion of the Vantage Acquisition. The Company will use the remaining proceeds for general corporate purposes.

The Company’s authorized common stock includes 650,000,000 shares of common stock, $0.01 par value per share. The following table presents a summary of changes to the Company’s common shares from January 1, 2015 through December 31, 2016:

Balance, January 1, 2015		136,280,766
Conversion of warrants into shares of common stock		8,331
Common stock awards vested, net		98,097
Balance, December 31, 2015		136,387,194
April 2016 Equity Offering		20,000,000
September 2016 Equity Offering		46,000,000
Conversion of warrants into shares of common stock		30,242
Common stock awards vested, net		189,472
Balance, December 31, 2016		202,606,908

14. Incentive Units

In connection with the Company’s IPO and the related corporate reorganization, the REO incentive unit holders contributed their REO incentive units to NGP Holdings and Rice Energy Holdings LLC (“Rice Holdings”) in return for (i) incentive units in such entities that, in the aggregate, were substantially similar to the REO incentive units they previously held and (ii) shares of common stock in the amount of $3.4 million related to the extinguishment of the incentive burden attributable to Mr. Daniel J. Rice III. No payments were made in respect of incentive units prior to the completion of the Company’s IPO. As a result of the IPO, the payment likelihood related to the NGP Holdings and Rice Holdings incentive units was deemed probable, requiring the Company to recognize compensation expense. The compensation expense related to these interests is treated as additional paid in capital from NGP Holdings and Rice Holdings in the Company’s financial statements and is not deductible for federal or state income tax purposes. The compensation expense recognized is a non-cash charge, with the settlement obligation resting on NGP Holdings and Rice Holdings, and as such the incentive units are not dilutive to Rice Energy Inc.

NGP Holdings

The NGP Holdings incentive units are considered a liability-based award and are adjusted to fair market value on a quarterly basis until all payments have been made. As a result of NGP’s sale of its remaining shares of the Company’s common stock in connection with the Company’s April 2016 Equity Offering, NGP Holdings paid approximately $47.5 million to holders of certain classes of NGP Holdings incentive units which resulted in the settlement of the remaining NGP Holdings incentive unit obligation. As such, the cumulative expense attributable to the NGP Holdings incentive units as of June 30, 2016 was adjusted to equal the cumulative cash payments made by NGP Holdings to NGP Holdings incentive unit holders. As a result, the Company recognized $27.3 million of compensation expense for the year ended December 31, 2016. No future expense will be recognized related to the NGP Holdings incentive units as a result of the April 2016 settlement of the remaining NGP Holdings incentive unit obligation. The Company recognized ($24.3) million and $44.5 million of non-cash compensation (income) expense for the twelve months ended December 31, 2015 and 2014.

Rice Holdings

The Rice Holdings incentive units are considered an equity-based award with the fair value of the award determined at the grant date and amortized over the service period of the award using the straight-line method. Compensation expense relative to the Rice Holdings incentive units was $24.5 million, $33.7 million and $41.7 million for the year ended December 31, 2016, 2015 and 2014, respectively. The Company will recognize approximately $14.7 million of additional compensation expense over the next year related to the Rice Holdings incentive units.

In August 2014, the triggering event for the Rice Holdings incentive units was achieved. As a result, in September 2014, 2015, and 2016 Rice Holdings distributed one quarter, one third and one half, respectively, of its then-remaining assets (consisting solely of shares of the Company’s common stock) to its members pursuant to the terms of its limited liability company agreement. In addition, in September 2017, Rice Holdings will distribute all of its then-remaining assets (consisting solely of shares of the Company’s common stock) to its members pursuant to the terms of its limited liability company agreement. As a result, over time, the shares of the Company’s common stock held by Rice Holdings will be transferred in their entirety to the members of Rice Holdings.

Combined

Total combined compensation expense (income) attributable to the incentive units was $51.8 million, $36.1 million and $106.0 million for the year ended December 31, 2016, 2015 and 2014, respectively. Of the total compensation expense recognized for the year ended December 31, 2015, approximately $12.8 million related to changes in certain service condition assumptions.

The three tranches of the incentive units having a time vesting feature were fully vested as of December 31, 2016.

Two tranches of the incentive units do not have a time vesting feature, and their payouts are triggered upon a future payment condition. As such, none of these awards have legally vested as of December 31, 2016. The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:

Rice Holdings
Valuation Date	1/29/2014
Dividend Yield	0.00	%
Expected Volatility	47.00	%
Risk-Free Rate	1.11	%
Expected Life (Years)	4.0

Rice Holdings
Valuation Date	4/14/2014
Dividend Yield	0.00	%
Expected Volatility	45.19	%
Risk-Free Rate	1.13	%
Expected Life (Years)	3.8

Rice Holdings
Valuation Date	4/16/2014
Dividend Yield	0.00	%
Expected Volatility	44.32	%
Risk-Free Rate	1.18	%
Expected Life (Years)	3.8

15. Variable Interest Entities

Pursuant to an evaluation performed upon adoption of ASU 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” the Company concluded that the Partnership, GP Holdings, Strike Force Midstream LLC (“Strike Force Midstream”), a subsidiary of Midstream Holdings and Gulfport Midstream Holdings LLC (“Gulfport Midstream”), a wholly owned subsidiary of Gulfport, and Rice Energy Operating each meet the criteria for variable interest entity (“VIE”) classification, as described in further detail below.

Rice Midstream Partners LP

The Company evaluated the Partnership for consolidation and determined the Partnership to be a VIE. The Company determined that the primary beneficiary of the Partnership is GP Holdings. As of December 31, 2016, Midstream Holdings held a significant indirect interest in the Partnership through (i) its ownership of a 91.75% limited liability partnership interest in GP Holdings, which owned an approximate 28% limited partner interest in the Partnership, and (ii) through ownership of its wholly-owned subsidiary Rice Midstream Management LLC (the “GP”), which holds all of the substantive voting and participating rights in the Partnership. As a result, through this ownership, the Company holds the power to direct the activities of the Partnership that most significantly impact the Partnership’s economic performance and the obligation to absorb losses or the right to receive benefits from the Partnership that could potentially be significant to the Partnership.

As of December 31, 2016, the Company consolidated the Partnership, recording noncontrolling interest related to the net income of the Partnership attributable to its public unitholders. The following table presents summary information of assets and liabilities of the Partnership that is included in the Company’s consolidated balance sheets that are for the use or obligation of the Partnership.

(in thousands)	December 31, 2016			December 31, 2015
Assets (liabilities):
Cash	$	21,834		$	7,597
Accounts receivable	8,758			9,926
Other current assets	64			192
Property and equipment, net	805,027			578,026
Goodwill and intangible assets, net	539,105			85,301
Deferred financing costs, net	12,591			2,310
Accounts payable	(4,172		)	(13,484		)
Accrued capital expenditures	(9,074		)	(15,277		)
Other current liabilities	(8,376		)	(3,067		)
Long-term debt	(190,000		)	(143,000		)
Other long-term liabilities	(5,189		)	(3,128		)

The following table presents summary information of the Partnership’s financial performance included in the consolidated statements of operations and cash flows for the twelve months ended December 31, 2016 and 2015, inclusive of affiliate amounts.

	Years Ended December 31,
(in thousands)	2016			2015
Operating revenues	$	201,623		$	114,459
Operating expenses	74,681			52,423
Net income	121,610			52,495

Net cash provided by operating activities	$	154,117		$	70,006
Net cash used in investing activities	(721,087		)	(379,991		)
Net cash provided by financing activities	581,207			290,748

The following table presents the Company’s change in limited partner ownership of the Partnership for the periods presented.

	Partnership units owned by GP Holdings (Common and Subordinated)	Total Partnership Units Outstanding	GP Holdings % Ownership in the Partnership		% Ownership in the Partnership Retained by the Company
As of:
December 31, 2015	28,757,246	70,917,372	41	%	41	%
Equity offering in June 2016	—	9,200,000
Equity offering in October 2016	—	20,930,233
Units issued under ATM program	—	944,700
Vested phantom units, net	—	280,451
December 31, 2016	28,757,246	102,272,756	28	%	26	%

Rice Midstream GP Holdings LP

The Company evaluated GP Holdings for consolidation and determined GP Holdings to be a VIE. The Company determined that the primary beneficiary of GP Holdings is Midstream Holdings. Midstream Holdings holds a 91.75% limited partnership interest in GP Holdings and GP Management holds all of the substantive voting and participating rights to direct the activities of GP Holdings. As a result, through this ownership, the Company holds the power to direct the activities of GP Holdings that most significantly impact GP Holdings’ economic performance and the obligation to absorb losses or the right to receive benefits from GP Holdings that could potentially be significant to GP Holdings.

As of December 31, 2016, the Company consolidates GP Holdings, recording noncontrolling interest related to the ownership interests of GP Holdings attributable to the Investors. GP Holdings has no significant assets, liabilities or operations other than consolidation of the Partnership.

Strike Force Midstream Holdings LLC

On February 1, 2016, Strike Force Midstream Holdings LLC (“Strike Force Holdings”), a wholly-owned subsidiary of Midstream Holdings, and Gulfport Midstream Holdings entered into an Amended and Restated Limited Liability Company Agreement (the “Strike Force LLC Agreement”) of Strike Force Midstream to engage in the natural gas midstream business in approximately 319,000 acres in Belmont and Monroe Counties, Ohio. Under the terms of the Strike Force LLC Agreement, Strike Force Holdings made an initial contribution to Strike Force Midstream of certain pipelines, facilities and rights of way and cash in the amount of $41.0 million in exchange for a 75% membership interest in Strike Force Midstream. Gulfport Midstream made an initial contribution of a gathering system and related assets in exchange for a 25% membership interest in Strike Force Midstream. The assets contributed by Gulfport Midstream have a fair value of $22.5 million, which was determined using Level 3 valuation inputs included in the discounted cash flow method within the income approach. The income approach includes estimates and assumptions related to future throughput volumes, operating costs, capital spending and changes in working capital. Estimating the fair value of these assets required judgment and determining the fair value is sensitive to changes in assumptions. Additionally, on February 1, 2016, Strike Force Midstream and Strike Force Holdings entered into a services agreement whereby Strike Force Holdings will provide all of the services necessary to operate, manage and maintain Strike Force Midstream.

The Company evaluated Strike Force Midstream for consolidation and determined Strike Force Midstream to be a VIE. Strike Force Holdings was determined to be the primary beneficiary as a result of its power to direct the activities of Strike Force Midstream that most significantly impact Strike Force Midstream’s economic performance and the obligation to absorb losses or the right to receive benefits through its 75% membership interest in Strike Force Midstream.

As of December 31, 2016, the Company consolidates Strike Force Midstream, recording noncontrolling interest related to the ownership interests of Strike Force Midstream attributable to Gulfport Midstream. The following table presents summary information of assets and liabilities of Strike Force Midstream that is included in the Company’s consolidated balance sheet that are for the use or obligation of Strike Force Midstream.

(in thousands)	December 31, 2016
Assets (liabilities):
Cash	$	36,572
Accounts receivable	2,529
Property and equipment, net	100,232
Accounts payable	(3,863		)
Accrued capital expenditures	(18,962		)
Other current liabilities	(44		)

The following table presents summary information for Strike Force Midstream’s financial performance included in the consolidated statement of operations and cash flows for the period from February 1, 2016 through December 31, 2016, inclusive of affiliate amounts.

(in thousands)
Operating revenues	$	7,687
Operating expenses (1)	26,059
Net loss	(18,354		)

Net provided by operating activities	$	835
Net cash used in investing activities	(49,263		)
Net cash provided by financing activities	85,000

(1) As of December 31, 2016, the Company recorded a $20.3 million impairment related to pipeline assets that were decommissioned.

Rice Energy Operating LLC

Following completion of the Vantage Acquisition, the Company operates the Vantage assets through Rice Energy Operating. As part of the consideration for the Vantage Acquisition, the Vantage Sellers received an aggregate 16.49% membership interest in Rice Energy Operating. The reduction in the Company’s ownership of Rice Energy Operating resulted in an increase in noncontrolling interests and additional paid in capital as reflected in the Change in ownership of consolidated subsidiaries within the Statements of Consolidated Equity. In connection with the issuance of such membership interests to the Vantage Sellers, the Company and the Vantage Sellers entered into the Third A&R LLC Agreement. Under the Third A&R LLC Agreement, the Company controls all of the day-to-day business affairs and decision making of Rice Energy Operating without approval of any other member, unless otherwise stated in the Third A&R LLC Agreement. As such, the Company, through its officers and directors, are responsible for all operational and administrative decisions of Rice Energy Operating and the day-to-day management of Rice Energy Operating’s business. Pursuant to the terms of the Third A&R LLC Agreement, the Company cannot, under any circumstances, be removed or replaced as the sole manager of Rice Energy Operating, except by its own election so long as it remains a member of Rice Energy Operating.

The Company evaluated Rice Energy Operating for consolidation and determined it to be a VIE. The Company determined that it is the primary beneficiary of Rice Energy Operating as it had both (i) the power, through control of all day-to-day business affairs and decision making of Rice Energy Operating that most significantly impact its economic performance and (ii) obligation to absorb losses or the right to receive benefits through its 83.51% membership interest in Rice Energy Operating. The 16.49% ownership held by the Vantage Sellers as of December 31, 2016 is presented as noncontrolling interest in the consolidated financial statements.

As of December 31, 2016, the Company consolidates Rice Energy Operating, recording noncontrolling interest related to the ownership interests of Rice Energy Operating attributable to the Vantage Sellers. The financial results of Rice Energy Operating do not materially differ from the Company’s year-end 2016 consolidated financial statements.

16. Stock-Based Compensation

Restricted Stock Unit Awards

Restricted stock unit awards are valued based upon the price of the Company’s common stock on the grant date and vest over periods from one to three years, with compensation expense being recognized on a straight-line basis over the requisite service period. Compensation expense related to the restricted stock unit awards was $9.6 million, $5.7 million and $2.6 million for the years ended December 31, 2016, 2015 and 2014, respectively, and is recorded in general and administrative, lease operating and midstream operating and maintenance expenses on the consolidated statements of operations. The following table summarizes the restricted stock unit award activity during the year ended December 31, 2016 and 2015.

	Number of shares		Weighted average grant date fair value
Total unvested, January 1, 2015	322,659		$	28.38
Granted	538,637		19.25
Vested	(121,138	)	27.98
Forfeited	(34,027	)	24.13
Total unvested, December 31, 2015	706,131		21.69
Granted	1,336,525		10.85
Vested	(271,364	)	21.99
Forfeited	(133,593	)	14.89
Total unvested - December 31, 2016	1,637,699		$	13.35

The following table details the scheduled vesting of the outstanding unvested restricted stock unit awards at December 31, 2016.

Vesting Date		Number of shares
2017		658,723
2018		593,192
2019		376,730
2020		9,054
		1,637,699

Total unrecognized compensation expense expected to be recognized in the future related to the restricted stock unit awards as of December 31, 2016 is $12.6 million.

Performance Stock Unit Awards

Under the LTIP, the Company has granted certain employees performance stock unit awards, which entitles the holders to shares of common stock subject to the achievement of certain performance metrics established by the Compensation Committee of the Board of Directors. Each grant of performance stock units is subject to a designated three-year initial performance period. The number of performance stock units to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) and the absolute shareholder return (“ASR”) achieved with respect to shares of the Company’s common stock against the TSR and ASR achieved by a defined peer group at the end of the performance period. Depending on the Company’s performance relative to the defined peer group, award recipients will earn between 0% and 200% of the initial performance stock units granted. The following table summarizes the performance stock unit award activity during the year ended December 31, 2016 and 2015.

	Number of shares		Weighted average grant date fair value
Total unvested, January 1, 2015	270,104		$	29.05
Granted	432,626		18.95
Vested	—		—
Forfeited	(6,120	)	22.94
Total unvested, December 31, 2015	696,610		22.83
Granted	979,970		8.97
Vested	—		—
Forfeited	(25,866	)	15.10
Total unvested - December 31, 2016	1,650,714		$	14.72

The following table details the scheduled vesting of the outstanding unvested performance stock unit awards at December 31, 2016.

Vesting Date		Number of shares
2017		263,206
2018		422,052
2019		965,456
		1,650,714

The compensation expense related to these awards is being recognized on a straight-line basis and the awards will cliff vest over the requisite service period of approximately three years. Compensation expense related to the performance unit stock awards was $10.0 million, $6.7 million and $2.8 million for the years ended December 31, 2016, 2015 and 2014, respectively, and is recorded in general and administrative expenses on the consolidated statements of operations.

The Company uses a Monte Carlo simulation valuation model to determine the fair value of the performance stock unit awards on the grant date. The key valuation assumptions for the Monte Carlo model are the initial value, risk-free interest rate, volatility and correlation coefficients. The risk-free interest rate is the U.S. Treasury bond rate on the date of grant. The initial value is the average of the volume weighted average prices for the 20 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.

The following table presents information regarding the assumptions used in determining the fair value of the performance stock unit awards granted in 2016, 2015 and 2014.

	2016			2015			2014
Dividend Yield	0.00		%	0.00		%	0.00		%
Expected Volatility	64.34		%	49.69		%	43.73		%
Risk-Free Rate	0.91		%	1.00		%	0.70		%
Expected Life (Years)	2.84			2.89			2.65
Weighted average fair value of performance stock unit awards	$	10.78		$	21.61		$	38.77

Total unrecognized compensation expense expected to be recognized in the future related to the performance stock unit awards as of December 31, 2016 is $10.6 million.

RMP Phantom Unit Awards

Additionally, from time to time, phantom unit awards are granted under the Rice Midstream Partners LP 2014 Long Term Incentive Plan (“RMP LTIP”) to certain non-employee directors of the Partnership and executive officers and employees of the Company that provide services to the Partnership under an omnibus agreement. Pursuant to the RMP LTIP, the maximum aggregate number of common units that may be issued pursuant to any and all awards under the RMP LTIP shall not exceed 5,000,000 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or the expiration of awards, as provided under the RMP LTIP. The equity-based awards are valued based upon the price of the Partnership’s common units on the grant date and will cliff vest over the requisite service period from one to two years. The Partnership recorded $2.8 million, $4.1 million and $0.1 million of stock compensation expense related to these awards for the years ended December 31, 2016, 2015 and 2014, respectively, and is recorded in general and administrative and midstream operating and maintenance expenses within the Company’s consolidated statements of operations. Total unrecognized compensation expense expected to be recognized over the remaining vesting period as of December 31, 2016 is $0.2 million for these awards.

The following table summarizes the activity for the equity-based awards during the year ended December 31, 2016 and 2015.

	Number of units		Weighted average grant date fair value
Total unvested, January 1, 2015	434,094		$	16.50
Granted	18,196		16.87
Vested	(242	)	16.50
Forfeited	(19,420	)	16.50
Total unvested, December 31, 2015	432,628		16.52
Granted	30,352		17.81
Vested	(399,158	)	16.52
Forfeited	(33,470	)	16.50
Total unvested - December 31, 2016	30,352		$	17.81

Combined

Further information on stock-based compensation recorded for the years ended December 31, 2016, 2015 and 2014 in the consolidated financial statements is detailed below.

	Year Ended December 31,
(in thousands)	2016		2015		2014
General and administrative expense	$	21,290	$	16,528	$	5,553
Lease operating and midstream operation and maintenance expense	625		—		—
Property, plant and equipment, net	578		—		—
Total cost of stock-based compensation plans	$	22,493	$	16,528	$	5,553

17. Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for the years ended December 31, 2016, 2015 and 2014.

	Year Ended December 31,
	2016			2015			2014
Income (loss) (numerator):
Net (loss) income attributable to Rice Energy (in thousands)	$	(269,751	)	$	(291,336	)	$	218,454
Less: Preferred dividends on redeemable noncontrolling interest	(26,176		)	—			—
Less: Accretion of redeemable noncontrolling interest	(2,274		)	—			—
Net (loss) income available to common stockholders	(298,201		)	(291,336		)	218,454

Weighted-average shares (denominator):
Weighted-average number of shares of common stock - basic	162,225,505			136,344,076			128,151,171
Weighted-average number of shares of common stock - diluted	162,225,505			136,344,076			128,255,155

Income (loss) earnings per share:
Basic	$	(1.84	)	$	(2.14	)	$	1.70
Diluted	$	(1.84	)	$	(2.14	)	$	1.70

There were no conversions of the 40,000,000 Rice Energy Operating common units (the “REO Common Units”) into Company common stock for the period from October 19, 2016 through December 31, 2016. The REO Common Units were issued in connection with the Vantage Acquisition and the holders of the REO Common Units, other than the Company, are entitled to redeem, from time to time, all or a portion of their REO Common Units. Each REO Common Unit will be redeemed for, at Rice Energy Operating’s option, a newly-issued share of common stock of the Company or a cash payment equal to the volume-weighted average closing price of a share of the Company’s common stock for the five trading days prior to and including the last full trading day immediately prior to the date that the member delivers a notice of redemption (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). Upon the exercise of the redemption right, the redeeming member surrenders its REO Common Units to Rice Energy Operating and the corresponding number of 1/1000ths of shares of preferred stock in respect of each redeemed Common Unit to Rice Energy Operating for cancellation. For the year ended December 31, 2016, 11,075,107 shares attributable to equity awards and convertible securities were not included in the diluted earnings per share calculation. For the year ended December 31, 2015, 133,611 shares attributable to equity awards were not included in the diluted earnings per share calculation as the Company incurred a net loss for the period presented herein.

18. Income Taxes

The Company is a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO in January 2014 because Rice Drilling B, our accounting predecessor, is a limited liability company that was not subject to federal income tax. The reorganization of our business into a corporation in connection with the closing of our IPO required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of our IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of the completion of our IPO as it represents a transaction among shareholders. Additionally, the pro forma EPS for the year ended December 31, 2014 disclosed in the accompanying consolidated statements of operations assumes a statutory tax rate.

The components of the income tax provision are as follows:

	Year Ended December 31,
(in thousands)	2016			2015			2014
Current tax (benefit) expense:
Federal	$	33,086		$	4,039		$	3,961
State	—			—			—
Total	33,086			4,039			3,961
Deferred tax (benefit) expense:
Federal	(150,538		)	19,878			68,846
State	(24,760		)	(11,799		)	18,793
Total	(175,298		)	8,079			87,639
Total income tax (benefit) expense	$	(142,212	)	$	12,118		$	91,600

The effective tax rate for the year ended December 31, 2016 differs from the statutory rate due principally to nondeductible incentive unit expense, state income taxes and noncontrolling interest. The effective tax rate for the year ended December 31, 2015 differs from the statutory rate due principally to nondeductible incentive unit expense, impairment losses and noncontrolling interest.

Prior to 2016, the noncontrolling interest was principally due to RMP earnings. During 2016, the Company formed several partnerships in addition to RMP and these new partnerships are reflected in noncontrolling interest.

Income tax (benefit) expense differs from amounts computed at the federal statutory rate of 35% on pre-tax income as follows:

	Year Ended December 31,
(in thousands)	2016			2015			2014
Tax at statutory rate	$	(136,861	)	$	(89,560	)	$	108,722
Permanent tax differences	41			74			18
State income taxes	(16,094		)	(7,668		)	12,216
Partnership earnings (1/1/14 - 1/28/14)	—			—			(66,239		)
Noncontrolling partners’ share of partnership earnings	(7,326		)	(8,168		)	(203		)
Goodwill impairment	—			103,218			—
Incentive unit expense	17,299			12,634			37,086
Other, net	729			1,588			—
Income tax (benefit) expense	$	(142,212	)	$	12,118		$	91,600
Effective tax rate	36.37		%	(4.74		)%	29.49		%

The Company recognizes deferred tax liabilities for temporary differences between the financial statement and tax basis of assets and liabilities. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted. Prior to 2016, the deferred tax liabilities primarily relate to intangible drilling costs, depreciation and depletion. As a result of the Vantage Acquisition, all intangible drilling costs and depletion reported as drilling and development costs are reclassified to the investment in partnership component. Additionally, $70.6 million of depreciation and $35.5 million of hedging loss has also been reclassified to the investment in partnerships component. The following table summarizes the source and tax effects of temporary differences that give rise to the deferred tax assets and deferred tax liabilities at December 31, 2016 and December 31, 2015.

	Year Ended December 31,
(in thousands)	2016			2015
Deferred income taxes:
Total deferred tax assets	$	336,257		$	299,032
Total deferred tax liabilities	(694,883		)	(571,020		)
Total net deferred tax liabilities	(358,626		)	(271,988		)

Principal components of deferred tax assets and liabilities:
Drilling and development costs expensed for tax	—			(368,949		)
Tax depreciation in excess of book depreciation	4,846			(92,710		)
Investment in partnerships	(694,883		)	57,227
Incentive compensation	7,435			5,576
Net operating loss carryforwards	30,432			153,558
Hedging loss	20,799			(109,352		)
AMT tax credit	41,085			7,999
IDC 59e election	230,351			73,977
Other	1,309			686
Total	$	(358,626	)	$	(271,988	)

As of December 31, 2016, the Company had a federal income tax net operating loss (“NOL”) carryforward of approximately $87.0 million. The associated deferred tax assets related to the NOL carryforward was $30.4 million. The NOL carryforward will expire in 2035. The value of these carryforwards depends on the Company’s ability to generate taxable income.

The Company is subject to the alternative minimum tax (“AMT”) if the computed AMT liability exceeds the regular tax liability for the year. As a result of certain AMT preference items related to intangible drilling costs, the Company has generated AMT carryforwards. Because AMT taxes paid can be credited against regular tax and have an indefinite carryforward, this item is reflected as a deferred tax asset in the amount of $41.1 million at December 31, 2016.

Pursuant to an agreement between the Partnership and the IRS regarding our 2016 tax reporting, we will have two short tax years for the calendar year 2016 as a result of a technical termination that occurred on February 22, 2016. This technical termination will result in a significant deferral of depreciation deductions that were otherwise allowable in computing the taxable income of the Partnership’s unitholders for the period February 23, 2016 through December 31, 2016. The Partnership expects to provide a single Schedule K-1 to each unitholder reflecting the unitholder’s taxable income for the full calendar year.

Based on management’s analysis, the Company did not have any uncertain tax positions as of December 31, 2016.

19. Related Party Transactions

Prior to our IPO, the Company reimbursed Rice Energy Family Holdings, LP (“Rice Partners”) for expenses incurred on behalf of the Company. General and administrative expenses incurred by the Rice Partners and reimbursed by the Company were $1.8 million for the year ended December 31, 2014. Prior to the closing of our IPO, the Company terminated its agreement to reimburse Rice Partners for expenses incurred on its behalf.

20. New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606).” The FASB created Topic 606 which supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 will enhance comparability of revenue recognition practices across entities, industries and capital markets compared to existing guidance. Additionally, ASU 2014-09 will reduce the number of requirements which an entity must consider in recognizing revenue, as this update will replace multiple locations for guidance. In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers (Topic 606) - Identifying Performance Obligations and Licensing.” In May 2016, the FASB issued ASU 2016-11, “Revenue from Contracts with Customers (Topic 606) and Derivatives and Hedging (Topic 815) - Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting” and ASU 2016-12, “Revenue from Contracts with Customers (Topic 606) - Narrow Scope Improvements and Practical Expedients.” These updates do not change the core principle of the guidance in Topic 606 (as amended by ASU 2014-09), but rather provide further guidance with respect to the implementation of ASU 2014-09. The effective date for ASU 2016-10, 2016-11, 2016-12 and ASU 2014-09, as amended by ASU 2015-14, is for annual reporting periods beginning after December 15, 2017, including interim periods within those years. In preparation for the adoption of the new standard in the fiscal year beginning January 2018, the Company has obtained representative samples of contracts and other forms of agreements with its customers and are evaluating the provisions contained therein in light of the five-step model specified by the new guidance. That five-step model includes: (1) determination of whether a contract-an agreement between two or more parties that creates legally enforceable rights and obligations-exists; (2) identification of the performance obligations in the contract; (3) determination of the transaction price; (4) allocation of the transaction price to the performance obligations in the contract; and (5) recognition of revenue when (or as) the performance obligation is satisfied. The Company anticipates adopting the standard using the modified retrospective approach at adoption. The Company will be evaluating individual customer contracts within each of our business segments as we continue to evaluate the impact of the adoption of this standard.

In August 2014, the FASB issued ASU 2014-15, “Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which specifies the responsibility an entity’s management has to evaluate whether there is substantial doubt about the entity’s ability to continue as a going concern. The new guidance is effective for annual and interim periods beginning after December 15, 2016. The Company has adopted ASU 2014-15 in the fourth

quarter of 2016 and has determined that substantial doubt does not exist about its ability to continue as a going concern.

In April 2015, the FASB issued ASU, 2015-03, “Interest-Imputation of Interest (Subtopic 835-30): Simplification of Debt Issuance Costs.” ASU 2015-03 was issued to simplify the presentation of debt issuance costs by requiring debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts. ASU 2015-03 is effective for periods beginning after December 15, 2015. In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” ASU 2015-15 clarifies the guidance in ASU 2015-03 regarding presentation and subsequent measurement of debt issuance costs related to line-of-credit arrangements. The Securities and Exchange Commission (“SEC”) staff announced they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company adopted ASU 2015-03 in the first quarter of 2016 and presents debt issuance costs associated with its Notes as a deduction from the carrying amount of the Notes. The Company also adopted ASU 2015-15 in the first quarter and presents debt issuance costs associated with the Company’s revolving credit facilities as deferred financing costs, net in its consolidated balance sheets. The Company has retrospectively applied the guidance in ASU 2015-03 and ASU 2015-15, which resulted in the reclassification of $21.4 million of deferred financing costs related to the Notes from deferred financing costs, net, to long-term debt on the consolidated balance sheet at December 31, 2015.

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” ASU 2016-02 requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact of the new guidance on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016-09 affects entities that issue share-based payment awards to their employees. ASU 2016-09 is designed to simplify several aspects of accounting for share-based payment award transactions, which include: (i) income tax consequences, (ii) classification of awards as either equity or liabilities, (iii) classification on the statement of cash flows and (iv) forfeiture rate calculations. The updated guidance is effective for annual periods beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption of the update is permitted. The Company plans to adopt ASU 2016-09 in the first quarter of 2017. The Company does not anticipate that this guidance will have a material impact on its consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” ASU 2016-15 clarifies and provides specific guidance on eight cash flow classification issues that are not currently addressed by current GAAP and thereby reduce the current diversity in practice. ASU 2016-15 is effective for public business entities for annual periods, including interim periods within those annual periods, beginning after December 15, 2017, with early application permitted. The Company does not anticipate that this guidance will have a material impact on its consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This ASU eliminates Step 2 from the goodwill impairment test which previously required measurement of any goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. Under the new standard, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, without exceeding the total amount of goodwill allocated to that reporting unit. The provisions of this ASU are effective for fiscal years, and any interim goodwill impairment tests within those fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing

dates after January 1, 2017. A reporting entity should apply the amendment on a prospective basis. The Company plans to adopt ASU 2017-04 in the first quarter of 2017.

21. Guarantor Financial Information

On April 25, 2014, the Company issued $900.0 million in aggregate principal amount of the 2022 Notes and on March 26, 2015, the Company issued $400.0 million in aggregate principal amount of the 2023 Notes. The obligations under the Notes are fully and unconditionally guaranteed by the Guarantors, subject to release provisions described in Note 3. In connection with the closing of the Vantage Acquisition, the Company and Rice Energy Operating entered into a Debt Assumption Agreement dated as of October 19, 2016 pursuant to which Rice Energy Operating agreed to become a co-obligor of the Notes and certain entities acquired in the Vantage Acquisition became wholly-owned became subsidiaries of Rice Energy Operating and Guarantors of the Notes. Each of the Guarantors is 100% owned by Rice Energy Operating.

The Company is a holding company whose sole material asset is an equity interest in Rice Energy Operating. The Company is a member and the sole manager of Rice Energy Operating. Rice Energy owns an approximate 83.51% membership in Rice Energy Operating as of December 31, 2016. Rice Energy is responsible for all operational, management and administrative decisions related to Rice Energy Operating’s business. In accordance with Rice Energy Operating’s Third Amended and Restated Limited Liability Company Agreement, the Company may not be removed as the sole manager of Rice Energy Operating so long as it continues to be a member of Rice Energy Operating.

As of December 31, 2016, the Company held approximately 83.51% of the economic interest in Rice Energy Operating, with the remaining 16.49% membership interest collectively held by the Vantage Sellers. The Vantage Sellers have no voting rights with respect to their membership interest in Rice Energy Operating. In connection with the closing of the Transaction, the Company issued shares of preferred stock to the Vantage Sellers in an amount equal to 1/1000 of the number of REO Common Units they received at the closing of the Vantage Acquisition. Pursuant to the certificate of designation setting forth the terms, rights and obligations and preferences of the preferred stock, each 1/1000 share of preferred stock entitles the holder to one vote on all matters submitted to a vote of the holders of common stock. Accordingly, the Vantage Sellers collectively have a number of votes in the Company equal to the aggregate number of REO Common Units that they hold.

The Vantage Sellers have a redemption right to cause Rice Energy Operating to redeem, from time to time, all or a portion of their Common Units. Each REO Common Unit will be redeemed for, at Rice Energy Operating’s option, a newly-issued share of common stock of the Company or a cash payment equal to the volume-weighted average closing price of a share of the Company’s common stock for the five trading days prior to and including the last full trading day immediately prior to the date that the member delivers a notice of redemption (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). Upon the exercise of the redemption right, the redeeming member surrenders its REO Common Units to Rice Energy Operating and the corresponding number of 1/1000ths of shares of preferred stock in respect of each redeemed Common Unit to Rice Energy Operating for cancellation. The Third A&R LLC Agreement requires that the Company contribute cash or shares of its common stock to Rice Energy Operating in exchange for a number of REO Common Units equal to the number of Rice Energy Operating Common Units to be redeemed from the member. Rice Energy Operating will then distribute such cash or shares of the Company’s common stock to such Vantage Seller to complete the redemption. Upon the exercise of the redemption right, the Company may, at its option, effect a direct exchange of the REO Common Units (and the corresponding shares of preferred stock (or fractions thereof) from the redeeming Vantage Seller.

As a result, the Company expects that over time it will have an increasing economic interest in Rice Energy Operating as the Vantage Sellers elect to exercise their redemption right. Moreover, any transfers of Common Units by the Vantage Sellers (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over Rice Energy Operating.

with respect to the Company, Rice Energy Operating and the Guarantors and the Non-Guarantor subsidiaries. Separate financial statements for Rice Energy Operating will be provided in Rice Energy Operating’s Annual Report on Form 10-K. The principal elimination entries below eliminate investment in subsidiaries and certain intercompany balances and transactions.

Balance Sheet as of December 31, 2016

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC		Guarantors		Non-Guarantors			Eliminations			Consolidated
Assets
Current assets:
Cash	$	2,756		$	230,944	$	164,522	$	71,821		$	—		$	470,043
Accounts receivable	22,525			—		201,122		28,990			(34,012		)	218,625
Receivable from affiliate				—		—					—			—
Prepaid expenses, deposits and other	2,651			—		2,214		194			—			5,059
Derivative instruments	—			689		—		—			—			689
Total current assets	27,932			231,633		367,858		101,005			(34,012		)	694,416

Gas collateral account	—			—		5,220		112			—			5,332
Investments in subsidiaries	2,928,250			4,406,023		6,101		—			(7,340,374		)	—
Property, plant and equipment, net	25,622			—		4,947,518		1,203,047			(58,275		)	6,117,912
Deferred financing costs, net	—			21,372		—		15,012			—			36,384
Goodwill	—			384,430		—		494,581			—			879,011
Intangible assets, net	—			—		—		44,525			—			44,525
Derivative instruments	138			27,894		11,296		—			—			39,328
Other non-current assets	—			—		614		—			—			614
Total assets	$	2,981,942		$	5,071,352	$	5,338,607	$	1,858,282		$	(7,432,661	)	$	7,817,522

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	926		$	—	$	8,724	$	8,594		$	—		$	18,244
Royalties payables	—			—		87,098		—			—			87,098
Accrued capital expenditures	—			—		89,403		35,297			—			124,700
Leasehold payables	—			—		22,869		—			—			22,869
Derivative instruments	—			72,391		66,997		—			—			139,388
Other accrued liabilities	54,064			18,994		84,950		16,451			(34,012		)	140,447
Total current liabilities	54,990			91,385		360,041		60,342			(34,012		)	532,746

Long-term liabilities:
Long-term debt	—			1,279,481		—		243,000			—			1,522,481
Leasehold payable	—			—		9,237		—			—			9,237
Deferred tax liabilities	—			26,561		209,276		122,789			—			358,626
Derivative instruments	—			9,766		16,711		—			—			26,477
Other long-term liabilities	8,858			—		66,949		5,541			—			81,348
Total liabilities	63,848			1,407,193		662,214		431,672			(34,012		)	2,530,915
Mezzanine equity:
Redeemable noncontrolling interest	—			—		—		382,525			—			382,525
Stockholders’ equity before noncontrolling interest	2,972,578			2,928,250		4,676,393		(270,370		)	(7,398,649		)	2,908,202
Noncontrolling interests in consolidated subsidiaries	(54,484		)	735,909		—		1,314,455			—			1,995,880
Total liabilities and stockholders’ equity	$	2,981,942		$	5,071,352	$	5,338,607	$	1,858,282		$	(7,432,661	)	$	7,817,522

Balance Sheet as of December 31, 2015

(in thousands)	Rice Energy Inc.		Rice Energy Operating LLC			Guarantors		Non-Guarantors		Eliminations			Consolidated
Assets
Current assets:
Cash	$	78,474	$	2		$	57,798	$	15,627	$	—		$	151,901
Accounts receivable	27,817		—			140,493		18,675		(32,171		)	154,814
Prepaid expenses, deposits and other	4,376		—			817		295		—			5,488
Derivative instruments	—		47,262			139,698		—		—			186,960
Total current assets	110,667		47,264			338,806		34,597		(32,171		)	499,163

Gas collateral account	—		—			3,995		82		—			4,077
Investments in subsidiaries	1,200,143		2,378,292			—		—		(3,578,435		)	—
Property, plant and equipment, net	21,443		—			2,382,878		865,040		(26,230		)	3,243,131
Deferred financing costs, net	—		3,896			—		4,915		—			8,811
Goodwill	—		—			—		39,142		—			39,142
Intangible assets, net	—		—			—		46,159		—			46,159
Derivative instruments	—		29,972			75,973		—		—			105,945
Other non-current assets	$	—	2,618			52		—		—			2,670
Total assets	$	1,332,253	$	2,462,042		$	2,801,704	$	989,935	$	(3,636,836	)	$	3,949,098

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	4,179	$	—		$	48,191	$	31,183	$	—		$	83,553
Royalties payables	—		—			40,572		—		—			40,572
Accrued capital expenditures	—		—			45,240		34,507		—			79,747
Leasehold payables	—		—			17,338		—		—			17,338
Derivative instruments	—		132			367		—		—			499
Other accrued liabilities	21,946		14,208			71,282		3,367		(32,171		)	78,632
Total current liabilities	26,125		14,340			222,990		69,057		(32,171		)	300,341

Long-term liabilities:
Long-term debt	—		1,275,790			—		160,000		—			1,435,790
Leasehold payable	—		—			6,289		—		—			6,289
Deferred tax liabilities	—		(47,663		)	299,741		19,910		—			271,988
Derivative liabilities	—		16,344			—		—		—			16,344
Other	—		3,088			7,661		3,129		—			13,878
Total liabilities	26,125		1,261,899			536,681		252,096		(32,171		)	2,044,630
Stockholders’ equity before noncontrolling interest	1,306,128		1,200,143			2,265,023		113,268		(3,604,665		)	1,279,897
Noncontrolling interests in consolidated subsidiaries	—		—			—		624,571		—			624,571
Total liabilities and stockholders’ equity	$	1,332,253	$	2,462,042		$	2,801,704	$	989,935	$	(3,636,836	)	$	3,949,098

Statement of Operations for the Year Ended December 31, 2016

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and natural gas liquids (NGL) sales	$	—		$	—		$	653,441		$	—		$	—		$	653,441
Gathering, compression and water services	—			—			—			265,556			(164,499		)	101,057
Other revenue	—			—			24,408			—			—			24,408
Total operating revenues	—			—			677,849			265,556			(164,499		)	778,906

Operating expenses:
Lease operating	—			—			50,708			—			(134		)	50,574
Gathering, compression and transportation	—			—			232,478			—			(108,626		)	123,852
Production taxes and impact fees	—			—			13,866			—			—			13,866
Exploration	—			—			15,159			—			—			15,159
Midstream operation and maintenance	—			—			—			27,618			(4,403		)	23,215
Incentive unit expense	—			—			49,426			2,335			—			51,761
Impairment of gas properties	—						20,853			—			—			20,853
Impairment of fixed assets	—						—			23,057			—			23,057
General and administrative	—			—			78,094			39,999			—			118,093
Depreciation, depletion and amortization	—			—			350,865			31,298			(13,708		)	368,455
Acquisition expense	—			—			5,500			609			—			6,109
Amortization of intangible assets	—			—			—			1,634			—			1,634
Other expense	—			—			25,652			1,656			—			27,308
Total operating expenses	—			—			842,601			128,206			(126,871		)	843,936

Operating (loss) income	—			—			(164,752		)	137,350			(37,628		)	(65,030		)
Interest expense	—			(91,734		)	(68		)	(7,825		)	—			(99,627		)
Other income (expense)	—			(898		)	2,206			98			—			1,406
Gain on derivative instruments	—			(83,324		)	(136,912		)	—			—			(220,236		)
Amortization of deferred financing costs	—			(5,283		)	—			(2,262		)	—			(7,545		)
Equity in income (loss) in affiliate	(324,235		)	(322,022		)	(3,197		)	—			649,454			—
(Loss) income before income taxes	(324,235		)	(503,261		)	(302,723		)	127,361			611,826			(391,032		)
Income tax benefit (expense)	—			179,026			(8,242		)	(28,572		)	—			142,212
Net (loss) income	(324,235		)	(324,235		)	(310,965		)	98,789			611,826			(248,820		)
Less: net (income) loss attributable to noncontrolling interests	54,484			—			—			(75,415		)	—			(20,931		)
Net (loss) income attributable to Rice Energy	(269,751		)	(324,235		)	(310,965		)	23,374			611,826			(269,751		)
Less: accretion and preferred dividends on redeemable noncontrolling interests	—			—			(28,450		)	—			—			(28,450		)
Net (loss) income attributable to Rice Energy Inc. common stockholders	$	(269,751	)	$	(324,235	)	$	(339,415	)	$	23,374		$	611,826		$	(298,201	)

Statement of Operations for the Year Ended December 31, 2015

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and natural gas liquids (NGL) sales	$	—		$	—		$	446,515		$	—		$	—		$	446,515
Gathering, compression and water services	—			—			—			141,823			(92,644		)	49,179
Other revenue	—			—			6,447			—			—			6,447
Total operating revenues	—			—			452,962			141,823			(92,644		)	502,141

Operating expenses:
Lease operating	—			—			44,356			—			—			44,356
Gathering, compression and transportation	—			—			150,015			—			(65,308		)	84,707
Production taxes and impact fees	—			—			7,609			—			—			7,609
Exploration	—			—			3,137			—			—			3,137
Midstream operation and maintenance	—			—			—			16,988			—			16,988
Incentive unit expense	—			—			33,873			2,224			—			36,097
Impairment of gas properties	—			—			18,250			—			—			18,250
Impairment of goodwill	—			—			294,908			—			—			294,908
General and administrative	—			—			78,592			24,446			—			103,038
Depreciation, depletion and amortization	—			—			304,703			19,185			(1,104		)	322,784
Acquisition expense	—			—			107			1,128			—			1,235
Amortization of intangible assets	—			—			—			1,632			—			1,632
Other expense	—			—			5,075			492			—			5,567
Total operating expenses	—			—			940,625			66,095			(66,412		)	940,308

Operating (loss) income	—			—			(487,663		)	75,728			(26,232		)	(438,167		)
Interest expense	—			(82,664		)	(166		)	(4,616		)	—			(87,446		)
Other income	—			615			441			52			—			1,108
Gain on derivative instruments	—			68,248			205,500			—			—			273,748
Amortization of deferred financing costs	—			(4,072		)	—			(1,052		)	—			(5,124		)
Equity in income (loss) of joint ventures and subsidiaries	(291,336		)	(287,044		)	—			—			578,380			—
(Loss) income before income taxes	(291,336		)	(304,917		)	(281,888		)	70,112			552,148			(255,881		)
Income tax benefit (expense)	—			13,581			(16,404		)	(9,295		)	—			(12,118		)
Net (loss) income	(291,336		)	(291,336		)	(298,292		)	60,817			552,148			(267,999		)
Less: net income attributable to noncontrolling interests	—			—			—			(23,337		)	—			(23,337		)
Net (loss) income attributable to Rice Energy	$	(291,336	)	$	(291,336	)	$	(298,292	)	$	37,480		$	552,148		$	(291,336	)

Statement of Operations for the Year Ended December 31, 2014

(in thousands)	Rice Energy Inc.		Rice Energy Operating LLC			Guarantors			Non-Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and natural gas liquids (NGL) sales	$	—	$	—		$	359,201		$	—		$	—		$	359,201
Gathering, compression and water services	—		—			—			7,300			(1,796		)	5,504
Other revenue	—		—			26,237			—			—			26,237
Total operating revenues	—		—			385,438			7,300			(1,796		)	390,942

Operating expenses:
Lease operating	—		—			24,971			—			—			24,971
Gathering, compression and transportation	—		—			37,180						(1,562		)	35,618
Production taxes and impact fees	—		—			4,647			—			—			4,647
Exploration	—		—			4,018						—			4,018
Midstream operation and maintenance	—		—			—			4,607			—			4,607
Incentive unit expense	—		—			86,020			19,941			—			105,961
General and administrative	—		—			45,268			16,303			—			61,570
Depreciation, depletion and amortization	—		—			153,282			2,988			—			156,270
Acquisition expense	—		—			820			1,519			—			2,339
Amortization of intangible assets	—		—			—			1,156			—			1,156
Other expenses	—		—			—			207			—			207
Total operating expenses	—		—			356,206			46,721			(1,562		)	401,364

Operating income (loss)	—		—			29,232			(39,421		)	(234		)	(10,422		)
Interest expense	—		(27,177		)	(10,130		)	(12,884		)	—			(50,191		)
Gain on purchase of Marcellus joint venture	—		—			203,579			—			—			203,579
Other income (loss)	—		247			754			(108		)	—			893
Gain on derivative instruments	—		55,580			130,897			—			—			186,477
Amortization of deferred financing costs	—		(2,006		)	(489		)	—			—			(2,495		)
Loss on extinguishment of debt	—		—			(7,654		)	—			—			(7,654		)
Write-off of deferred financing costs	—		—			(6,896		)	—			—			(6,896		)
Equity in income (loss) of joint ventures and subsidiaries	218,454		184,679			(2,656		)	—			(403,132		)	(2,656		)
Income (loss) before income taxes	218,454		211,323			336,637			(52,413		)	(403,366		)	310,635
Income tax expense	—		7,131			(107,171		)	8,440			—			(91,600		)

Net income (loss)	218,454		218,454			229,466			(43,973		)	(403,366		)	219,035
Less: net income attributable to noncontrolling interests	—		—			—			(581		)	—			(581		)
Net income (loss) attributable to Rice Energy	$	218,454	$	218,454		$	229,466		$	(44,554	)	$	(403,366	)	$	218,454

Condensed Statement of Cash Flows for the Year Ended December 31, 2016

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non-Guarantors			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	44,594		$	(94,101	)	$	396,899		$	189,958		$	(51,465	)	$	485,885

Capital expenditures for property and equipment	(2,982		)	—			(688,998		)	(234,285		)	45,751			(880,514		)
Capital expenditures for acquisitions	—			(381,080		)	(44,266		)	(611,700		)	—			(1,037,046		)
Investment in subsidiaries	(1,572,040		)	(139,499		)	(5,714		)	—			1,717,253			—
Net cash used in investing activities	(1,575,022		)	(520,579		)	(738,978		)	(845,985		)	1,763,004			(1,917,560		)

Proceeds from borrowings	—			—			—			338,000			—			338,000
Repayments of debt obligations	(1,189		)	(706,911		)	—			(255,001		)	—			(963,101		)
Debt issuance costs	—			(19,507		)	—			(12,464		)	—			(31,971		)
Distributions to the Partnership’s public unitholders	—			—			—			(47,875		)	—			(47,875		)
Proceeds from the issuance of common stock, net of offering costs	1,465,671			—			—			—			—			1,465,671
Proceeds from issuance of common units sold by RMP, net of offering costs	—			—			—			620,330			—			620,330
Proceeds from conversion of warrants	89			—			—			—			—			89
Proceeds from issuance of non-controlling redeemable interest	—			—			—			368,747			—			368,747
Contribution to Strike Force Midstream by Gulfport Midstream	—			—			—			11,030			—			11,030
Preferred dividends to redeemable noncontrolling interest holders	—			—			—			(6,900		)	—			(6,900		)
Employee tax withholding for settlement of stock compensation award vestings	(9,861		)	—			—			5,658			—			(4,203		)
Contributions from parent	—			1,572,040			448,803			(309,304		)	(1,711,539		)	—
Net cash provided by financing activities	1,454,710			845,622			448,803			712,221			(1,711,539		)	1,749,817

Increase (decrease) in cash	(75,718		)	230,942			106,724			56,194			—			318,142
Cash, beginning of year	78,474			2			57,798			15,627			—			151,901
Cash, end of year	$	2,756		$	230,944		$	164,522		$	71,821		$	—		$	470,043

Condensed Statement of Cash Flows for the Year Ended December 31, 2015

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non-Guarantors			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(41,029	)	$	(18,178	)	$	413,984		$	85,546		$	(27,336	)	$	412,987

Capital expenditures for property and equipment	(9,775		)	—			(859,359		)	(404,476		)	27,336			(1,246,274		)
Investment in subsidiaries	(52,558		)	(421,068		)	—			—			473,626			—
Acquisition of Greene County assets	—			—			19,054			—			—			19,054
Proceeds from sale of interest in gas properties	—			—			10,201			—			—			10,201
Net cash used in investing activities	(62,333		)	(421,068		)	(830,104		)	(404,476		)	500,962			(1,217,019		)

Proceeds from borrowings	—			411,932			—			502,000			—			913,932
Repayments of debt obligations	—			(15,922		)	(697		)	(342,000		)	—			(358,619		)
Distributions to the Partnership’s public unitholders	—			—			—			(17,017		)	—			(17,017		)
Debt issuance costs	—			(9,320		)	—			(946		)	—			(10,266		)
Proceeds from issuance of common stock sold in our IPO, net of offering costs	—			—			—			(129		)	—			(129		)
Proceeds from issuance of common units sold by RMP, net of offering costs	—			—			—			171,902			—			171,902
Contributions from parent, net	—			52,558			432,682			(11,614		)	(473,626		)	—
Net cash provided by financing activities	—			439,248			431,985			302,196			(473,626		)	699,803

Increase (decrease) in cash	(103,362		)	2			15,865			(16,734		)	—			(104,229		)
Cash, beginning of year	181,836			—			41,933			32,361			—			256,130
Cash, end of year	$	78,474		$	2		$	57,798		$	15,627		$	—		$	151,901

Condensed Statement of Cash Flows for the Year Ended December 31, 2014

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non-Guarantors			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	15,894		$	246		$	95,372		$	(26,437	)	$	—		$	85,075

Investment in subsidiaries	(1,033,221		)	(1,913,945		)	—			—			2,947,166			—
Capital expenditures for property and equipment	(8,588		)	—			(684,541		)	(277,145		)	—			(970,274		)
Capital expenditures for acquisitions	—			—			(357,635		)	(166,447		)	—			(524,082		)
Proceeds from sale of interest in gas properties	—			—			12,891			—			—			12,891
Net cash used in investing activities	(1,041,809		)	(1,913,945		)	(1,029,285		)	(443,592		)	2,947,166			(1,481,465		)

Proceeds from borrowings	—			900,000			190,000			—			—			1,090,000
Repayments of debt obligations	—			—			(689,873		)	—			—			(689,873		)
Restricted cash for convertible debt	—			—			8,268			—			—			8,268
Debt issuance costs	—			(19,521		)	—			(5,022		)	—			(24,543		)
Proceeds from conversion of warrants	1,975			—			—			—			—			1,975
Proceeds from issuance of common stock, net of offering costs	793,342			—			—			—			—			793,342
Proceeds from issuance of common units sold in RMP IPO, net of offering costs	—			—			—			441,739			—			441,739
Distributions to parent	412,434			—			—			(412,434		)	—			—
Contributions from parent	—			1,033,220			1,436,043			477,903			(2,947,166		)	—
Net cash provided by financing activities	1,207,751			1,913,699			944,438			502,186			(2,947,166		)	1,620,908
Increase (decrease) in cash	181,836			—			10,525			32,157			—			224,518
Cash, beginning of year	—			—			31,408			204			—			31,612
Cash, end of year	$	181,836		$	—		$	41,933		$	32,361		$	—		$	256,130

22. Quarterly Financial Information (Unaudited)

The Company’s quarterly financial information for the years ended December 31, 2016 and 2015 is as follows (in thousands):

Year ended December 31, 2016:(1)	First quarter			Second quarter			Third quarter		Fourth quarter(2)
Total operating revenues	$	139,942		$	155,998		$	198,920	$	284,046
Total operating expenses	187,332			189,777			183,047		283,780
Operating (loss) income	(47,390		)	(33,779		)	15,873		266
Net income (loss)	$	3,305		$	(138,709	)	$	91,078	$	(204,493	)
Net (loss) income attributable to Rice Energy	$	(17,588	)	$	(156,686	)	$	74,413	$	(169,889	)
Net (loss) income attributable to Rice Energy common stockholders	$	(21,046	)	$	(164,630	)	$	65,832	$	(178,356	)
(Loss) income per share attributable to Rice Energy - basic	$	(0.15	)	$	(1.07	)	$	0.42	$	(0.88	)
(Loss) income per share attributable to Rice Energy - diluted	$	(0.15	)	$	(1.07	)	$	0.41	$	(0.88	)

Year ended December 31, 2015:(1)	First quarter			Second quarter			Third quarter			Fourth quarter
Total operating revenues	$	109,539		$	112,894		$	143,621		$	136,088
Total operating expenses	140,619			159,065			160,295			480,329
Operating loss	(31,080		)	(46,171		)	(16,674		)	(344,241		)
Net income (loss)	$	4,687		$	(63,519	)	$	65,084		$	(274,251	)
Net income (loss) attributable to Rice Energy	$	152		$	(69,683	)	$	58,950		$	(280,755	)
Income (loss) per share attributable to Rice Energy - basic	$	—		$	(0.51	)	$	0.43		$	(2.06	)
Income (loss) per share attributable to Rice Energy - diluted	$	—		$	(0.51	)	$	0.43		$	(2.06	)

(1) The sum of quarterly data in some cases may not equal the yearly total due to rounding.

(2) Includes the results of the Vantage Acquisition for the period from October 19, 2016 to December 31, 2016.

23. Supplemental Information on Gas-Producing Activities (Unaudited)

Capitalized costs relating to gas-producing activities are as follows:

	As of December 31,
(in thousands)	2016			2015
Proved properties	$	3,731,715		$	1,780,918
Unproved properties	2,035,951			1,071,523
	5,767,666			2,852,441
Accumulated depreciation and depletion	(883,055		)	(498,467		)
Net capitalized costs	$	4,884,611		$	2,353,974

Costs incurred for property acquisitions, exploration and development are as follows:

	For the Years Ended December 31,
(in thousands)	2016		2015		2014
Acquisitions:
Proved leaseholds	$	1,245,704	$	—	$	439,284
Unproved leaseholds	1,137,215		100,172		233,185
Development costs	585,342		616,836		734,106
Exploration costs:
Geological and geophysical	1,636		1,276		4,018

Results of operations related to natural gas, oil and NGL production are as follows:

	For the Years Ended December 31,
(in thousands)	2016			2015			2014
Revenues	$	653,441		$	452,962		$	385,438
Production costs	297,052			201,980			67,032
Exploration costs	15,159			3,137			4,018
Depreciation, depletion and amortization	350,187			308,194			151,900
Incentive unit expense	49,426			33,873			86,020
Impairment of gas properties	20,853			18,250			—
Impairment of fixed assets	2,765			—			—
Impairment of goodwill	—			294,908			—
Acquisition costs	5,500			108			820
Gain from sale of interest in gas properties	—			(953		)	—
Other expense	4,856			6,028			—
General and administrative expenses	78,161			78,592			46,229
Income tax expense	13,468			6,039			38,871
Results of operations from producing activities	$	(183,986	)	$	(497,194	)	$	(9,452	)

Reserve quantity information is as follows:

	For the Years Ended December 31,
(in Bcfe)(1)	2016		2015		2014 (2)
Proved developed and undeveloped reserves:
Beginning of year	1,700.0		1,306.6		382.7
Acquisitions	924.7		—		282.4
Extensions and discoveries	1,667.8		869.0		692.2
Revision of previous estimates	17.2		(274.3	)	47.0
Production	(304.4	)	(201.3	)	(97.7	)
End of year	4,005.3		1,700.0		1,306.6

Proved developed reserves:
End of year	2,178.8		1,014.9		644.1
Proved undeveloped reserves:
End of year	1,826.5		685.2		662.4

(1) As our oil and NGLs reserves are immaterial and constitute approximately one percent of our proved reserves at December 31, 2016, the Company presents our reserves on an Mcfe basis calculated at the rate of one barrel per six Mcf based upon the relative energy content of oil to natural gas, which may not be indicative of the relationship of oil and natural gas prices.

(2) Amounts presented in the table exclude amounts attributable to the Marcellus joint venture for periods prior to the completion of the Company’s IPO in January 2014.

Acquisitions

For the year ended December 31, 2016, the Company added 924.7 Bcfe of proved developed and undeveloped reserves primarily as a result of the Vantage Acquisition on October 19, 2016. For the year ended December 31, 2014, the Company added 282.4 Bcfe through its purchase of the remaining 50% interest in the Marcellus joint venture in January 2014 and its Greene County acreage acquisition from Chesapeake Appalachia, L.L.C and its partners in August 2014.

Extensions and Discoveries

For the year ended December 31, 2016, the Company added 1,667.8 Bcfe through its drilling program in the Marcellus Shale and Utica Shale and also as a result of changes in the Company’s operational plans. Extensions of approximately 1,118.0 Bcfe related to proved undeveloped reserves while extensions of approximately 549.8 Bcfe related to proved developed reserves that were not included within our 2015 development plan. The Company added 869.0 Bcfe and 692.2 Bcfe through its drilling program in the Marcellus Shale and Utica Shale in 2015 and 2014, respectively.

Revision of Previous Estimates

In 2016, the Company had net positive revisions of 17.2 Bcfe. Such revisions resulted from favorable well performance, partially offset by approximately 16 proved undeveloped locations that were removed from the Company’s estimate of reserves at December 31, 2015 and were no longer included in the Company’s operational plans.

The reserve quantity information is limited to reserves which had been evaluated as of December 31, 2016. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves are expected to be recovered from new wells after substantial development costs are incurred. Netherland, Sewell & Associates, Inc. reviewed 100% of the total net gas proved reserves attributable to the Company’s interests and the Company’s Marcellus joint venture as of December 31, 2016, 2015 and 2014.

The information presented represents estimates of proved natural gas reserves based on evaluations prepared by the independent petroleum engineering firms of Netherland, Sewell & Associates, Inc. in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. The Company’s independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources. Since 1961, Netherland, Sewell & Associates, Inc. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.

Certain information concerning the assumptions used in computing the standardized measure of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a

proper understanding and assessment of the data presented. Future cash inflows are computed by applying the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through, respectively, to the period-end quantities of those reserves. Natural gas prices are held constant throughout the lives of the properties.

The assumptions used to compute estimated future net revenues do not necessarily reflect the Company’s expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rates also could result directly or indirectly from factors outside of the Company’s control, such as unintentional delays in development, changes in prices or regulatory controls. The standardized measure calculation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, this could affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved natural gas reserves at the end of the year, based on period-end costs and assuming continuation of existing economic conditions.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved natural gas reserves.

Information with respect to the Company’s estimated discounted future net cash flows related to its proved natural gas and oil reserves is as follows:

	As of December 31,
(in thousands)	2016			2015			2014 (1)
Future cash inflows	$	7,174,765		$	4,497,738		$	5,904,380
Future production costs	(3,103,526		)	(2,378,541		)	(2,161,926		)
Future development costs	(1,124,478		)	(545,988		)	(610,179		)
Future income tax expense	(41,135		)	—			(745,022		)
Future net cash flows	2,905,626			1,573,209			2,387,253
10% annual discount for estimated timing of cash flows	(1,357,411		)	(686,936		)	(1,079,499		)
Standardized measure of discounted future net cash flows	$	1,548,215		$	886,273		$	1,307,754

(1) Reflects the balances for Rice Drilling B. Amounts presented in the table exclude amounts attributable to the Company’s Marcellus joint venture for periods prior to the completion of its IPO in January 2014.

For 2016, the reserves for the Company were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016, adjusted for energy content and a regional price differential. For 2016, the adjusted natural gas prices were $1.80 and $1.66, the adjusted oil prices were $32.70 and $37.65, and the adjusted NGL prices were $14.76 and $9.74 for the Appalachian Basin and Fort Worth Basin, respectively.

For 2015, the reserves for the Company were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2015, adjusted for energy content and a regional price differential. For 2015, the adjusted natural gas price was $2.65, the adjusted oil price was $41.72 and the adjusted NGL price was $9.91.

For 2014, the reserves for the Company were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2014, adjusted for energy content and a regional price differential. For 2014, the adjusted natural gas price was $4.52 and the adjusted oil price was $85.70.

The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

	For the Years Ended December 31,
(in thousands)	2016			2015			2014
Balance at beginning of period	$	886,273		$	1,307,754		$	417,164
Net change in prices and production costs	(60,207		)	(949,774		)	81,558
Net change in future development costs	41,551			4,251			(181,813		)
Natural gas and oil net revenues	(510,868		)	(312,269		)	(291,023		)
Extensions	516,370			370,636			930,534
Acquisitions	407,690		(1)	—			375,865		(2)
Revisions of previous quantity estimates	46,894			(274,503		)	37,435
Previously estimated development costs incurred	111,276			122,532			62,653
Net change in taxes	(20,191		)	436,319			(436,319		)
Accretion of discount	88,627			174,407			70,937
Changes in timing and other	40,800			6,920			240,763
Balance at end of period	$	1,548,215		$	886,273		$	1,307,754

(1) Reflects cash flows primarily attributable to the Company’s October 19, 2016 Vantage Acquisition.

(2) Reflects the purchase of the remaining 50% interest in the Marcellus joint venture in January 2014 and the Greene County acreage acquisition in August 2014.

EX-99.2 6 a17-22068_2ex99d2.htm EX-99.2

Exhibit 99.2

Item 1. Financial Statements

Rice Energy Inc.
Condensed Consolidated Balance Sheets
(Unaudited)

(in thousands)	June 30, 2017			December 31, 2016
Assets
Current assets:
Cash	$	161,540		$	470,043
Accounts receivable	339,419			218,625
Prepaid expenses and other	11,347			5,059
Derivative assets	10,624			689
Total current assets	522,930			694,416

Long-term assets:
Gas collateral account	5,332			5,332
Property, plant and equipment, net	6,446,251			6,117,912
Acquisition deposit	18,033			—
Deferred financing costs, net	33,274			36,384
Goodwill	879,011			879,011
Intangible assets, net	43,717			44,525
Derivative assets	45,713			39,328
Other non-current assets	789			614
Total assets	$	7,995,050		$	7,817,522

Liabilities, mezzanine equity and stockholders’ equity
Current liabilities:
Accounts payable	$	24,131		$	18,244
Royalties payable	104,091			87,098
Accrued capital expenditures	176,594			124,700
Accrued interest	14,540			14,440
Leasehold payable	19,538			22,869
Embedded derivative liability	15,417			—
Derivative liabilities	39,061			139,388
Other accrued liabilities	90,194			126,007
Total current liabilities	483,566			532,746

Long-term liabilities:
Long-term debt	1,599,779			1,522,481
Leasehold payable	12,279			9,237
Deferred tax liabilities	362,767			358,626
Derivative liabilities	24,591			26,477
Other long-term liabilities	90,204			81,348
Total liabilities	2,573,186			2,530,915

Mezzanine equity:
Redeemable noncontrolling interest, net (Note 10)	396,711			382,525

Stockholders’ equity:
Common stock, $0.01 par value; authorized - 650,000,000 shares; issued and outstanding - 211,644,987 shares and 202,606,908 shares, respectively	2,117			2,026
Preferred stock, $0.01 par value; authorized - 50,000,000 shares; issued and outstanding - 31,521 and 40,000 shares, respectively	—			—
Additional paid in capital	3,473,266			3,313,917
Accumulated deficit	(350,514		)	(407,741		)
Stockholders’ equity before noncontrolling interest	3,124,869			2,908,202
Noncontrolling interests in consolidated subsidiaries	1,900,284			1,995,880
Total liabilities, mezzanine equity and stockholders’ equity	$	7,995,050		$	7,817,522

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.
Condensed Consolidated Statements of Operations
(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except share data)	2017			2016			2017			2016
Operating revenues:
Natural gas, oil and natural gas liquids sales	$	348,892		$	122,312		$	705,726		$	234,754
Gathering, compression and water services	38,065			23,728			68,408			48,280
Other revenue	11,350			9,958			17,979			12,906
Total operating revenues	398,307			155,998			792,113			295,940

Operating expenses:
Lease operating (1)	17,645			9,038			40,294			20,109
Gathering, compression and transportation	39,131			27,169			78,557			55,301
Production taxes and impact fees	6,679			2,659			12,832			4,310
Exploration	7,106			5,548			11,118			6,538
Midstream operation and maintenance	8,348			4,555			14,998			14,177
Incentive unit expense	4,800			14,840			7,683			38,982
Acquisition expense	2,408			84			2,615			556
Impairment of gas properties	—			—			92,355			—
Impairment of fixed assets	—			—			—			2,595
General and administrative (1)	39,226			29,272			73,050			54,145
Depreciation, depletion and amortization	145,904			84,752			282,782			163,937
Amortization of intangible assets	406			403			808			811
Other expense	13,207			11,457			19,365			15,648
Total operating expenses	284,860			189,777			636,457			377,109

Operating income (loss)	113,447			(33,779		)	155,656			(81,169		)
Interest expense	(27,269		)	(24,802		)	(54,292		)	(49,323		)
Other income	273			2,549			453			2,762
Gain (loss) on derivative instruments	103,558			(201,555		)	88,779			(131,376		)
Loss on embedded derivatives	(15,417		)	—			(15,417		)	—
Amortization of deferred financing costs	(3,426		)	(1,618		)	(6,078		)	(3,169		)
Income (loss) before income taxes	171,166			(259,205		)	169,101			(262,275		)
Income tax (expense) benefit	(33,917		)	120,496			(33,341		)	126,871
Net income (loss)	137,249			(138,709		)	135,760			(135,404		)
Less: Net income attributable to noncontrolling interests	(53,724		)	(17,977		)	(78,533		)	(38,870		)
Net income (loss) attributable to Rice Energy Inc.	83,525			(156,686		)	57,227			(174,274		)
Less: Preferred dividends and accretion of redeemable noncontrolling interests	(20,656		)	(7,944		)	(28,988		)	(11,402		)
Net income (loss) attributable to Rice Energy Inc. common stockholders	$	62,869		$	(164,630	)	$	28,239		$	(185,676	)

Earnings (loss) per share-basic	$	0.31		$	(1.07	)	$	0.14		$	(1.28	)
Earnings (loss) per share-diluted	$	0.30		$	(1.07	)	$	0.14		$	(1.28	)

(1) Stock-based compensation expense of $0.2 million and $6.2 million is included in lease operating and general and administrative expense, respectively, for the three months ended June 30, 2017, and $0.1 million and $6.1 million is included in lease operating and general and administrative expense, respectively, for the three months ended June 30, 2016. Stock-based compensation expense of $0.4 million and $11.3 million was included in lease operating and general and administrative expense, respectively, for the six months ended June 30, 2017, and $0.2 million and $10.8 million was included in lease operating and general and administrative expense, respectively, for the six months ended June 30, 2016. See Note 14 for additional information.

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)

	Six Months Ended June 30,
(in thousands)	2017			2016
Cash flows from operating activities:
Net income (loss)	$	135,760		$	(135,404	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	282,782			163,937
Amortization of deferred financing costs	6,078			3,169
Amortization of intangibles	808			811
Exploration	11,118			6,538
Incentive unit expense	7,683			38,982
Stock compensation expense	11,701			10,789
Impairment of fixed assets	—			2,595
Impairment of gas properties	92,355			—
Derivative instruments fair value (gain) loss	(88,779		)	131,376
Cash (payments) receipts for settled derivatives	(31,502		)	133,205
Deferred income tax benefit (expense)	24,541			(126,871		)
Loss on embedded derivatives	15,417			—
Changes in operating assets and liabilities:
Accounts receivable	(116,958		)	(21,995		)
Prepaid expenses and other assets	(7,342		)	(530		)
Accounts payable	1,345			(4,894		)
Accrued liabilities and other	(35,549		)	572
Royalties payable	16,993			614
Net cash provided by operating activities	326,451			202,894

Cash flows from investing activities:
Capital expenditures for property and equipment	(644,326		)	(484,529		)
Acquisitions	(3,671		)	(7,744		)
Acquisition deposit	(18,033		)	—
Net cash used in investing activities	(666,030		)	(492,273		)

Cash flows from financing activities:
Proceeds from borrowings	75,500			120,000
Repayments of debt obligations	(768		)	(255,690		)
Shares of common stock issued in April 2016 offering, net of offering costs	—			311,764
RMP common units issued in the Partnership’s June 2016 offering, net of offering costs	—			164,150
RMP common units issued in the Partnership’s ATM program, net of offering costs	—			15,782
Net cash contributions to Strike Force Midstream by Gulfport Midstream	21,815			—
Debt issuance costs	(1,399		)	(669		)
Distributions to the Partnership’s public unitholders	(40,202		)	(17,636		)
Proceeds from issuance of redeemable noncontrolling interests, net of offering costs	—			368,767
Preferred dividends on Series B Units	(15,270		)	(3,576		)
Employee tax withholding for settlement of stock compensation award vestings	(8,600		)	—
Proceeds from conversion of warrants	—			100
Net cash provided by financing activities	31,076			702,992

Net (decrease) increase in cash	(308,503		)	413,613

Cash at the beginning of the year	470,043			151,901
Cash at the end of the period	$	161,540		$	565,514

Supplemental disclosure of non-cash investing and financing activities:
Asset contribution to Strike Force Midstream by Gulfport Midstream	$	—		$	22,500
Capital expenditures financed by accounts payable	$	18,899		$	18,658
Capital expenditures financed by accrued capital expenditures	$	176,594		$	79,362
Natural gas properties financed through deferred payment obligations	$	31,817		$	11,097
Conversion of REO Common Units into Rice Energy common stock	$	176,402		$	—

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.
Condensed Consolidated Statements of Equity
(Unaudited)

(in thousands)	Common Stock ($0.01 par)		Additional Paid-In Capital			Accumulated (Deficit) Earnings			Stockholders Equity before Non- Controlling Interest			Non- Controlling Interest			Total
Balance, January 1, 2016	$	1,364	$	1,416,523		$	(137,990	)	$	1,279,897		$	624,571		$	1,904,468
Incentive unit compensation	—		38,982			—			38,982			—			38,982
Stock compensation	—		9,151			—			9,151			2,070			11,221
Issuance of common stock upon vesting of stock compensation awards, net of tax withholdings	2		(1,459		)	—			(1,457		)	—			(1,457		)
Issuance of phantom units upon vesting of equity-based compensation, net of tax withholdings	—		(3,182		)	—			(3,182		)	2,063			(1,119		)
Shares of common stock issued in April 2016 offering, net of offering costs	200		311,564			—			311,764			—			311,764
Conversion of warrants into shares of common stock	—		100			—			100			—			100
Preferred dividends on redeemable noncontrolling interest	—		(10,719		)	—			(10,719		)	—			(10,719		)
Accretion of redeemable noncontrolling interest	—		(683		)	—			(683		)	—			(683		)
RMP common units issued in the Partnership’s June 2016 offering, net of offering costs	—		—			—			—			164,150			164,150
RMP common units issued pursuant to the Partnership’s ATM program, net of offering costs	—		—			—			—			15,782			15,782
Distributions to the Partnership’s public unitholders	—		—			—			—			(17,636		)	(17,636		)
Contribution from noncontrolling interest	—		—			—			—			25,530			25,530
Consolidated net (loss) income	—		—			(174,274		)	(174,274		)	38,870			(135,404		)
Balance, June 30, 2016	$	1,566	$	1,760,277		$	(312,264	)	$	1,449,579		$	855,400		$	2,304,979

Balance, January 1, 2017	$	2,026	$	3,313,917		$	(407,741	)	$	2,908,202		$	1,995,880		$	4,904,082
Incentive unit compensation	—		7,683			—			7,683			—			7,683
Stock compensation	—		13,474			—			13,474			259			13,733
Issuance of common stock upon vesting of stock compensation awards, net of tax withholdings	6		(8,606		)	—			(8,600		)	—			(8,600		)
Preferred dividends on redeemable noncontrolling interest	—		(15,333		)	—			(15,333		)	—			(15,333		)
Accretion of redeemable noncontrolling interest	—		(14,186		)	—			(14,186		)	—			(14,186		)
Contribution from noncontrolling interest	—		—			—			—			21,815			21,815
REO Common Unit conversion into Rice Energy common stock, net of tax	85		176,317			—			176,402			(156,001		)	20,401
Distributions to the Partnership’s public unitholders	—		—			—			—			(40,202		)	(40,202		)
Consolidated net income	—		—			57,227			57,227			78,533			135,760
Balance, June 30, 2017	$	2,117	$	3,473,266		$	(350,514	)	$	3,124,869		$	1,900,284		$	5,025,153

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

Rice Energy Inc.
Notes to Condensed Consolidated Financial Statements
(Unaudited)

1. Basis of Presentation and Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements of Rice Energy Inc. (the “Company”) have been prepared by the Company’s management in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and applicable rules and regulations promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The unaudited condensed consolidated financial statements included herein contain all adjustments which are, in the opinion of management, necessary to present fairly the Company’s financial position as of June 30, 2017 and December 31, 2016, its condensed consolidated statements of operations for the three and six months ended June 30, 2017 and 2016, and its statements of cash flows and equity for the six months ended June 30, 2017 and 2016.

The accompanying condensed consolidated financial statements include the financial results of the Company, its consolidated subsidiaries and certain variable interest entities in which the Company is the primary beneficiary. See Note 13 for additional discussion of variable interest entities.

These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes therein for the year ended December 31, 2016, as filed with the Securities and Exchange Commission (“SEC”) by the Company in its Annual Report on Form 10-K (the “2016 Annual Report”). Certain prior period financial statement amounts have been reclassified to conform to current period presentation. All intercompany transactions have been eliminated in consolidation.

Proposed Merger with EQT Corporation

On June 19, 2017, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with EQT Corporation (“EQT”), pursuant to which, subject to the satisfaction or waiver of certain conditions, an indirect, wholly-owned subsidiary of EQT will merge with and into the Company (the “Merger”), and immediately thereafter the Company will merge with and into another indirect, wholly-owned subsidiary of EQT (“LLC Sub”), with LLC Sub continuing as the surviving entity in such merger as an indirect, wholly-owned subsidiary of EQT.

On the terms and subject to the conditions set forth in the Merger Agreement, which has been unanimously approved by the respective boards of directors of EQT and the Company, at the effective time of the Merger, each share of the Company’s common stock issued and outstanding immediately before that time (other than shares of the Company’s common stock held by EQT or certain of its direct and indirect subsidiaries, shares held by the Company in treasury or shares with respect to which appraisal has been properly demanded pursuant to Delaware law) will automatically be converted into the right to receive 0.37 shares of EQT common stock and $5.30 in cash. The consummation of the Merger is subject to approval by the shareholders of both the Company and EQT and certain customary regulatory and other closing conditions and is expected to occur in the fourth quarter of 2017.

The Merger Agreement provides for certain termination rights for both the Company and EQT, including the right of either party to terminate the Merger Agreement if the Merger is not consummated by February 19, 2018 (which may be extended by either party to May 19, 2018 under certain circumstances). Upon termination of the Merger Agreement under certain specified circumstances, the Company may be required to pay EQT, or EQT may be required to pay the Company, a termination fee of $255.0 million. In addition, if the Merger Agreement is terminated because of a failure of a party’s shareholders to approve the proposals required to complete the Merger, that party may be required to reimburse the other party for its transaction expenses in an amount equal to $67.0 million.

2. Acquisitions

Vantage Acquisition

On October 19, 2016, the Company completed the acquisition of Vantage Energy, LLC and Vantage Energy II, LLC (collectively, “Vantage”) and their subsidiaries (the “Vantage Acquisition”) pursuant to the terms of the Purchase and Sale Agreement (the “Vantage Purchase Agreement”) dated September 26, 2016 between and among the Company, Vantage Energy Investment LLC, Vantage Energy Investment II LLC and Vantage. Pursuant to the terms of the Vantage Purchase Agreement, Rice Energy Operating LLC (“Rice Energy Operating”) acquired Vantage from certain affiliates of Quantum Energy Partners, Riverstone Holdings LLC and Lime Rock Partners (such affiliates, the “Vantage Sellers”) for approximately $2.7 billion, which consisted of approximately $1.0 billion in cash, the assumption of net debt of approximately $707.0 million and the issuance of 40.0 million common units in Rice Energy Operating that were immediately exchangeable into 40.0 million shares of common stock of the Company, valued at approximately $1.0 billion.

On September 26, 2016, the Company entered into a Purchase and Sale Agreement (the “Midstream Purchase Agreement”) by and between the Company and Rice Midstream Partners LP (the “Partnership”). Pursuant to the terms of the Midstream Purchase Agreement, as amended, immediately following the close of the Vantage Acquisition on October 19, 2016, the Partnership acquired from the Company all of the outstanding membership interests of Vantage Energy II Access, LLC and Vista Gathering, LLC (collectively, the “Vantage Midstream Entities,” and such acquisition, the “Vantage Midstream Acquisition”). The Partnership’s acquisition of the Vantage Midstream Entities from the Company is accounted for as a combination of entities under common control at historical cost. The Vantage Midstream Entities, which became wholly-owned subsidiaries of the Partnership upon the completion of the acquisition of the Vantage Midstream Entities, own midstream assets, including approximately 30 miles of dry gas gathering and compression assets. In consideration for the acquisition of the Vantage Midstream Entities, the Partnership paid the Company $600.0 million in aggregate cash consideration, which the Partnership funded through the net proceeds of a private placement of Partnership common units and borrowings under its revolving credit facility.

Allocation of Purchase Price

The following table summarizes the preliminary purchase price and the preliminary estimated values of assets and liabilities assumed based on the fair value as of October 19, 2016, with any excess of the purchase price over the estimated fair value of the identified net assets acquired recorded as goodwill. Approximately $369.0 million and $470.8 million of goodwill has been allocated to the Exploration and Production segment and Rice Midstream Partners segment, respectively. Included within the Rice Midstream Partners segment is goodwill of $15.4 million, attributable to the enhanced cash flow distributions to Rice Midstream GP Holdings LP (“GP Holdings”) expected to result from the Vantage Midstream Acquisition. The amount of goodwill allocated to the Rice Midstream Partners segment includes an acquired 67.5% interest in the Wind Ridge system previously owned by Access Midstream Partners. The Partnership acquired the Wind Ridge system in connection with the Vantage Midstream Acquisition for approximately $14.3 million, of which $10.9 million was ascribed to property and equipment and $3.4 million to goodwill. Goodwill primarily relates to the Company’s ability to control the Vantage acquired assets and recognize synergies related to administrative and capital efficiencies, extended laterals, the creation of additional contiguous leasing opportunities not previously available and additional dedicated acreage.

Certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, title defect analysis. The Company expects to complete the purchase price allocation once it has received all of the necessary information, but no later than one year from the date of completion of the Vantage Acquisition. Prior to the completion of the Company’s purchase price allocation, the value of the assets and liabilities may be revised as appropriate. Goodwill associated with the Vantage Acquisition is fully deductible for tax purposes.

Consideration Given:
Fair value of issued Rice Energy Operating units	$	1,001,200
Cash consideration, net of cash acquired	981,080
Total consideration	$	1,982,280

Estimated Fair Value of Assets Acquired and Liabilities Assumed:
Current assets, net of cash acquired	$	49,532
Natural gas and oil properties	2,178,076
Midstream property, plant and equipment	144,562
Other non-current assets	27,437
Current liabilities	(103,322		)
Fair value of debt assumed	(706,912		)
Other non-current liabilities	(51,052		)
Noncontrolling interest in Rice Energy Operating	(395,910		)
Total estimated fair value of assets acquired and liabilities assumed	$	1,142,411
Goodwill	$	839,869

The valuation of Rice Energy Operating common units issued as consideration was primarily calculated based upon Level 1 inputs. The common unit value was included as an input in determining the fair value of the noncontrolling interests, which were further adjusted using level 3 inputs to reflect the value of ownership retained by the Vantage Sellers.

Post-Acquisition Operating Results

The Vantage Acquisition contributed the following to the Company’s consolidated operating results for the three and six months ended June 30, 2017.

(in thousands)	Three Months Ended June 30, 2017		Six Months Ended June 30, 2017
Revenue attributable to Rice Energy Inc.	$	106,042	$	201,878
Net income (loss) attributable to noncontrolling interests	$	3,000	$	(2,827	)
Net income (loss) attributable to Rice Energy Inc.	$	15,816	$	(15,615	)

Unaudited Pro Forma Information

The following table presents unaudited pro forma combined financial information for the three and six months ended June 30, 2016, which presents the Company’s results as though the Vantage Acquisition had been completed at January 1, 2016. The pro forma combined financial information is not necessarily indicative of the

results that might have actually occurred had the Vantage Acquisition been completed at January 1, 2016; furthermore, the financial information is not intended to be a projection of future results.

	Pro Forma
(in thousands, except per share data)	Three Months Ended June 30, 2016			Six Months Ended June 30, 2016
Operating revenues	$	211,649		$	401,735
Net loss	$	(232,925	)	$	(198,647	)
Less: Net loss (income) attributable to noncontrolling interests	$	17,895		$	(9,574	)
Net loss attributable to Rice Energy	$	(215,030	)	$	(208,221	)
Loss per share (basic)	$	(1.21	)	$	(1.10	)
Loss per share (diluted)	$	(1.21	)	$	(1.10	)

3. Impairment

During the first quarter of 2017, the Company identified significant declines in forward Waha basis differentials, which is the primary sales point for its Fort Worth Basin production. Such expected prolonged declines indicated a potential impairment trigger, and, as a result, the Company performed an asset recoverability test of its Fort Worth Basin properties. Based upon the results of the recoverability assessment, the Company concluded that the carrying value of its Fort Worth Basin properties exceeded its undiscounted cash flows. The fair value of the Fort Worth Basin proved properties was determined using a combination of the market and income approach to determine fair value. Significant inputs to the valuation of the discounted cash flows of natural gas and oil properties included 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 cost of capital rate. These inputs required significant judgments and estimates by management which included Level 3 unobservable inputs to the fair value measurement. The difference between the carrying value and fair value resulted in an asset impairment of $92.4 million within the Exploration and Production segment during the first quarter of 2017.

4. Accounts Receivable

Accounts receivable are primarily from the Company’s joint interest partners and natural gas marketers. The Company extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. An allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. Allowances for uncollectible accounts were not material for the periods presented. Accounts receivable as of June 30, 2017 and December 31, 2016 are detailed below.

(in thousands)	June 30, 2017		December 31, 2016
Joint interest	$	141,910	$	53,577
Natural gas sales	173,745		145,887
Other	23,764		19,161
Total accounts receivable	$	339,419	$	218,625

5. Long-Term Debt

Long-term debt consists of the following as of June 30, 2017 and December 31, 2016:

(in thousands)	June 30, 2017		December 31, 2016
Long-term Debt
Senior Notes Due 2022, net of unamortized deferred financing costs and original discount issuances of $10,896 and $12,023, respectively (a)	$	889,104	$	887,977
Senior Notes Due 2023, net of unamortized deferred financing costs and original discount issuances of $7,825 and $8,496, respectively (b)	392,175		391,504
Senior Secured Revolving Credit Facility (c)	—		—
Midstream Holdings Revolving Credit Facility (d)	112,500		53,000
RMP Revolving Credit Facility (e)	206,000		190,000
Total long-term debt	$	1,599,779	$	1,522,481

Senior Notes

6.25% Senior Notes Due 2022 (a)

The Company has $900.0 million in aggregate principal amount of 6.25% senior notes due 2022 outstanding (the “2022 Notes”). The 2022 Notes will mature on May 1, 2022, and interest is payable on the 2022 Notes on each May 1 and November 1. Upon the occurrence of a change of control, unless the Company has given notice to redeem the 2022 Notes, the holders of the 2022 Notes will have the right to require the Company to repurchase all or a portion of the 2022 Notes at a price equal to 101% of the aggregate principal amount of the 2022 Notes, plus any accrued and unpaid interest. The Company may redeem some or all of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.688% prior to May 1, 2018, 103.125% for the twelve-month period beginning May 1, 2018, 101.563% for the twelve-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020, plus accrued and unpaid interest.

7.25% Senior Notes Due 2023 (b)

The Company has $400.0 million in aggregate principal amount of 7.25% senior notes due 2023 outstanding (the “2023 Notes”). The 2023 Notes will mature on May 1, 2023, and interest is payable on the 2023 Notes on each May 1 and November 1. At any time prior to May 1, 2018, the Company may redeem up to 35% of the 2023 Notes at a redemption price of 107.250% of the principal amount, plus accrued and unpaid interest, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2023 Notes remains outstanding after such redemption. Prior to May 1, 2018, the Company may redeem some or all of the notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest. Upon the occurrence of a change of control, unless the Company has given notice to redeem the 2023 Notes, the holders of the 2023 Notes will have the right to require the Company to repurchase all or a portion of the 2023 Notes at a price equal to 101% of the aggregate principal amount of the 2023 Notes, plus any accrued and unpaid interest. On or after May 1, 2018, the Company may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438% for the twelve-month period beginning on May 1, 2018, 103.625% for the twelve-month period beginning May 1, 2019, 101.813% for the twelve-month period beginning on May 1, 2020 and 100.000% beginning on May 1, 2021, plus accrued and unpaid interest.

securing such indebtedness. The Notes are jointly and severally, fully and unconditionally, guaranteed by the Company’s Guarantors.

Senior Secured Revolving Credit Facility (c)

In April 2013, the Company entered into a Senior Secured Revolving Credit Facility (the “Senior Secured Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders. In April 2014, the Company, as borrower, and Rice Drilling B LLC (“Rice Drilling B”), as predecessor borrower, amended and restated the credit agreement governing the Senior Secured Revolving Credit Facility to, among other things, assign all of the rights and obligations of Rice Drilling B as borrower under the Senior Secured Revolving Credit Facility to the Company.

In connection with the closing of the Vantage Acquisition, in October 2016, the Company entered into a Fourth Amended and Restated Credit Agreement (the “A&R Credit Agreement”), among the Company, Rice Energy Operating, Wells Fargo Bank, N.A., as administrative agent, and the lenders and other parties thereto. The A&R Credit Agreement provides, among other things, for the assignment of the Company’s rights and obligations as borrower under the Senior Secured Revolving Credit Facility to Rice Energy Operating and the addition of the Company as a guarantor of those obligations.

On June 15, 2017, Rice Energy Operating, as borrower, and the Company, as parent guarantor, entered into the Third Amendment to the A&R Credit Agreement, pursuant to which the lenders under the A&R Credit Agreement completed their semi-annual redetermination of the borrowing base. Following the redetermination, the Company’s borrowing base and aggregate elected commitment amounts each increased from $1.45 billion to $1.6 billion.

As of June 30, 2017, the borrowing base was $1.6 billion and the sublimit for letters of credit was $400.0 million. The Company had zero borrowings outstanding and $211.0 million in letters of credit outstanding under the A&R Credit Agreement as of June 30, 2017, resulting in availability of $1.4 billion. The maturity date of the Senior Secured Revolving Credit Facility is October 19, 2021. The next redetermination of the borrowing base is expected to occur in October 2017.

Eurodollar loans under the Senior Secured Revolving Credit Facility bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of borrowing base utilized, and base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 125 to 225 basis points, depending on the percentage of borrowing base utilized.

The A&R Credit Agreement also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Senior Secured Revolving Credit Facility to be immediately due and payable.

The Company was in compliance with such covenants and ratios effective as of June 30, 2017.

Midstream Holdings Revolving Credit Facility (d)

On December 22, 2014, Rice Midstream Holdings LLC (“Midstream Holdings”) entered into a credit agreement (the “Midstream Holdings Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders establishing a revolving credit facility (the “Midstream Holdings Revolving Credit Facility”) with a maximum credit amount of $300.0 million and a sublimit for letters of credit of $25.0 million.

June 30, 2017. The Midstream Holdings Revolving Credit Facility is available to fund working capital requirements and capital expenditures and to purchase assets. The maturity date of the Midstream Holdings Revolving Credit Facility is December 22, 2019.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Midstream Holdings may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 225 to 300 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 125 to 200 basis points, depending on the leverage ratio then in effect. Midstream Holdings also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The Midstream Holdings Credit Agreement also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Midstream Holdings Revolving Credit Facility to be immediately due and payable. Midstream Holdings was in compliance with such covenants and ratios effective as of June 30, 2017.

RMP Revolving Credit Facility (e)

On December 22, 2014, Rice Midstream OpCo LLC (“Rice Midstream OpCo”), a wholly-owned subsidiary of the Partnership, entered into a credit agreement (the “RMP Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders establishing a revolving credit facility (the “RMP Revolving Credit Facility”).

As of June 30, 2017, the RMP Revolving Credit Facility provided for lender commitments of $850.0 million, with an additional $200.0 million of commitments available under an accordion feature subject to lender approval. Rice Midstream OpCo had $206.0 million of borrowings outstanding and no letters of credit outstanding under the RMP Revolving Credit Facility as of June 30, 2017, resulting in availability of $644.0 million. The year-to-date average daily outstanding balance of the RMP Revolving Credit Facility was approximately $194.0 million, and interest was incurred at a weighted average annual interest rate of 2.9% through June 30, 2017. The RMP Revolving Credit Facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes and matures on December 22, 2019. The Partnership and its restricted subsidiaries are the guarantors of the obligations under the RMP Revolving Credit Facility.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 200 to 300 basis points, depending on the leverage ratio then in effect, and base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the leverage ratio then in effect. Rice Midstream OpCo also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

The RMP Credit Agreement also contains certain financial covenants and customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the RMP Revolving Credit Facility to be immediately due and payable. The Partnership was in compliance with such covenants and ratios effective as of June 30, 2017.

Expected Aggregate Maturities

Expected aggregate maturities of long-term debt as of June 30, 2017 are as follows (in thousands):

Remainder of Year Ending December 31, 2017	$	—
Year Ending December 31, 2018	—
Year Ending December 31, 2019	318,500
Year Ending December 31, 2020	—
Year Ending December 31, 2021 and Beyond	1,281,279
Total	$	1,599,779

Interest paid in cash was approximately $49.1 million and $55.1 million for the three and six months ended June 30, 2017, respectively, and $46.6 million and $49.1 million for the three and six months ended June 30, 2016, respectively.

6. Derivative Instruments

As of June 30, 2017, the Company has entered into derivative instruments with various financial institutions, fixing the price it receives for a portion of its future sales of produced natural gas. The Company’s fixed price derivatives primarily include swap and collar contracts that are tied to the commodity prices on NYMEX. As of June 30, 2017, the Company has entered into NYMEX hedging contracts through December 31, 2021, hedging a total of approximately 1,234 Bcfe of its projected natural gas production at a weighted average price of $2.99 per MMBtu. Additionally, the Company has entered into basis swap contracts to hedge the difference between the NYMEX index price and various local index prices. The fixed price and basis hedging contracts the Company has entered into through December 31, 2021 at other various sales points cover a total of approximately 1,165 Bcfe.

As a result of the entry into the Merger Agreement (as discussed in Note 1), the Company reassessed the probability of a Change in Control under the LLC Agreement and the GP Holdings A&R LPA and determined that the Change in Control was probable (all terms as defined in Note 10). As such, we assessed certain embedded derivatives requiring bifurcation in the LLC Agreement and GP Holdings A&R LPA and determined that the value of the Investor Put Right (as defined in Note 10) has increased as a result of the increased probability of the Change in Control. As of June 30, 2017, the fair value of the Investor Put Right embedded derivative was approximately $15.4 million and is included as an embedded derivative liability in the accompanying condensed consolidated balance sheet. Refer to Note 10 for further information.

The Company recognizes all derivative instruments as either assets or liabilities at fair value per Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) “Derivatives and Hedging (Topic 815).” The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized currently in earnings. The following tables present the gross amounts of the Company’s recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value:

	As of June 30, 2017
(in thousands)	Derivative instruments, gross		Derivative instruments subject to master netting arrangements			Derivative Instruments, net
Derivative assets	$	131,000	$	(74,663	)	$	56,337
Derivative liabilities	$	157,612	$	(93,960	)	$	63,652
Embedded derivative liability	$	15,417	$	—		$	15,417

	As of December 31, 2016
(in thousands)	Derivative instruments, gross		Derivative instruments subject to master netting arrangements			Derivative Instruments, net
Derivative assets	$	103,507	$	(63,490	)	$	40,017
Derivative liabilities	$	286,019	$	(120,154	)	$	165,865

7. Fair Value of Financial Instruments

The Company determines the fair value of its financial instruments, which are comprised primarily of derivative instruments, on a recurring basis as these instruments are required to be recorded at fair value for each reporting amount. Certain amounts in the Company’s financial statements were measured at fair value on a nonrecurring basis, including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities and nonperformance risk.

The following assets and liabilities were measured at fair value on a recurring basis during the period (refer to Note 6 for details relating to derivative instruments):

	As of June 30, 2017
			Fair Value Measurements at Reporting Date Using
(in thousands)	Carrying Value		Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value	$	56,337	$	56,337	$	—	$	56,337	$	—
Total assets	$	56,337	$	56,337	$	—	$	56,337	$	—

Liabilities:
Derivative instruments, at fair value	$	63,652	$	63,652	$	—	$	63,652	$	—
Embedded derivatives, at fair value	15,417		15,417		—		—		15,417
Total liabilities	$	79,069	$	79,069	$	—	$	63,652	$	15,417

	As of December 31, 2016
			Fair Value Measurements at Reporting Date Using
(in thousands)	Carrying Value		Total Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value	$	40,017	$	40,017	$	—	$	40,017	$	—
Total assets	$	40,017	$	40,017	$	—	$	40,017	$	—

Liabilities:
Derivative instruments, at fair value	$	165,865	$	165,865	$	—	$	165,865	$	—
Total liabilities	$	165,865	$	165,865	$	—	$	165,865	$	—

The carrying value of cash and cash equivalents approximates fair value due to the short maturity of the instruments. The Company’s non-financial assets, such as property, plant and equipment, goodwill and intangible assets are recorded at fair value upon business combination and are remeasured at fair value only if an impairment charge is recognized. To the extent necessary, the Company applies unobservable inputs and management judgment due to the absence of quoted market prices (Level 3) to the valuation methodologies for these non-financial assets.

The estimated fair value and gross carrying amount of long-term debt as reported on the condensed consolidated balance sheets as of June 30, 2017 and December 31, 2016 is shown in the table below (refer to Note 5 for details relating to the debt instruments). The fair value was estimated using Level 2 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position. The gross carrying value of the revolving credit facilities approximates fair value for the periods presented below.

	As of June 30, 2017				As of December 31, 2016
Long-Term Debt (in thousands)	Carrying Value		Fair Value		Carrying Value		Fair Value
Senior Notes Due 2022	$	900,000	$	942,750	$	900,000	$	929,250
Senior Notes Due 2023	397,791		433,000		397,601		428,000
Midstream Holdings Revolving Credit Facility	112,500		112,500		53,000		53,000
RMP Revolving Credit Facility	206,000		206,000		190,000		190,000
Total	$	1,616,291	$	1,694,250	$	1,540,601	$	1,600,250

8. Financial Information by Business Segment

The Company is organized and operates in three different operating segments: the Exploration and Production segment, the Rice Midstream Holdings segment and the Rice Midstream Partners segment. The segments represent components of the Company that engage in activities (a) from which revenue is generated and expenses are incurred; (b) whose operating results are regularly reviewed by the Chief Operating Decision Maker, who makes decisions about resources to be allocated to the segment and (c) for which discrete financial information is available. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Other income and expenses, interest and income taxes are managed on a consolidated basis. The

segment accounting policies are the same as those described in Note 1 to the Company’s Consolidated Financial Statements for the year ended December 31, 2016 contained in its 2016 Annual Report.

The operating results of the Company’s reportable segments were as follows for the three months ended June 30, 2017:

(in thousands)	Exploration and Production		Rice Midstream Holdings		Rice Midstream Partners		Elimination of Intersegment Transactions			Consolidated Total
Total operating revenues	$	360,242	$	31,947	$	72,377	$	(66,259	)	$	398,307
Total operating expenses	301,801		11,847		25,364		(54,152		)	284,860
Operating income (loss)	$	58,441	$	20,100	$	47,013	$	(12,107	)	$	113,447

Capital expenditures for segment assets	$	268,254	$	61,351	$	29,530	$	(12,772	)	$	346,363
Depreciation, depletion and amortization	$	141,478	$	1,790	$	7,543	$	(4,907	)	$	145,904

The operating results of the Company’s reportable segments were as follows for the three months ended June 30, 2016:

(in thousands)	Exploration and Production			Rice Midstream Holdings		Rice Midstream Partners		Elimination of Intersegment Transactions			Consolidated Total
Total operating revenues	$	132,270		$	11,873	$	46,547	$	(34,692	)	$	155,998
Total operating expenses	191,718			7,872		17,547		(27,360		)	189,777
Operating (loss) income	$	(59,448	)	$	4,001	$	29,000	$	(7,332	)	$	(33,779	)

Capital expenditures for segment assets	$	150,646		$	15,894	$	38,776	$	(10,506	)	$	194,810
Depreciation, depletion and amortization	$	79,515		$	1,556	$	6,855	$	(3,174	)	$	84,752

The operating results and assets of the Company’s reportable segments were as follows for the six months ended June 30, 2017:

(in thousands)	Exploration and Production		Rice Midstream Holdings		Rice Midstream Partners		Elimination of Intersegment Transactions			Consolidated Total
Total operating revenues	$	723,705	$	58,791	$	135,127	$	(125,510	)	$	792,113
Total operating expenses	672,971		18,858		47,518		(102,890		)	636,457
Operating income (loss)	$	50,734	$	39,933	$	87,609	$	(22,620	)	$	155,656

Capital expenditures for segment assets	$	494,014	$	123,782	$	58,036	$	(31,506	)	$	644,326
Depreciation, depletion and amortization	$	273,317	$	3,187	$	15,164	$	(8,886	)	$	282,782
Segment assets	$	6,019,255	$	589,584	$	1,471,348	$	(85,137	)	$	7,995,050
Goodwill	$	368,992	$	—	$	510,019	$	—		$	879,011

The operating results of the Company’s reportable segments were as follows for the six months ended June 30, 2016:

(in thousands)	Exploration and Production			Rice Midstream Holdings		Rice Midstream Partners		Elimination of Intersegment Transactions			Consolidated Total
Total operating revenues	$	247,660		$	22,524	$	101,090	$	(75,334	)	$	295,940
Total operating expenses	374,898			15,397		36,473		(49,659		)	377,109
Operating (loss) income	$	(127,238	)	$	7,127	$	64,617	$	(25,675	)	$	(81,169	)

Capital expenditures for segment assets	$	386,320		$	54,267	$	75,019	$	(31,077	)	$	484,529
Depreciation, depletion and amortization	$	154,471		$	2,645	$	12,225	$	(5,404	)	$	163,937

The assets of the Company’s reportable segments were as follows as of December 31, 2016:

(in thousands)	Exploration and Production		Rice Midstream Holdings		Rice Midstream Partners		Elimination of Intersegment Transactions			Consolidated Total
Segment assets	$	6,120,530	$	360,292	$	1,399,217	$	(62,517	)	$	7,817,522
Goodwill	$	384,431	$	—	$	494,580	$	—		$	879,011

9. Commitments and Contingencies

to the applicable joint operating agreement and the Company and Gulfport shall remain operators of drilling units located in the Northern and Southern Contract Areas, respectively, following such termination.

Firm Transportation

The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments under these contracts as of June 30, 2017 totaled $4.9 billion (remainder of 2017 - $95.1 million, 2018 - $242.2 million, 2019 - $235.5 million, 2020 - $235.2 million, 2021 - $234.8 million, 2022 - $234.4 million and thereafter - $3.6 billion).

Drilling Rig Service Commitments

As of June 30, 2017, the Company had five horizontal rigs under contract, of which three expire in 2017, one expires in 2018 and one expires in 2019. The Company also had four tophole drilling rigs under contract, of which one expires in 2017, one expires in 2018 and two expire in 2019. Future payments under these contracts as of June 30, 2017 totaled $62.7 million (remainder of 2017 - $23.3 million, 2018 - $31.3 million and 2019 - $8.1 million). Any other rig performing work for the Company is performed on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well, the costs of which have not been included in the amounts above. The values above represent the gross amounts that the Company is committed to pay without regard to its proportionate share based on its working interest.

Frac Sand Commitments

Commencing in January 2017, the Company has commitments for frac sand to be used as a proppant in its hydraulic fracturing operations. Future commitments under these contracts as of June 30, 2017 totaled $38.2 million (remainder of 2017 - $7.6 million, 2018 - $15.2 million and 2019 - $15.4 million).

Litigation

10. Mezzanine Equity

On February 17, 2016, Midstream Holdings and GP Holdings, entered into a securities purchase agreement (the “Securities Purchase Agreement”) with EIG Energy Fund XVI, L.P., EIG Energy Fund XVI-E, L.P., and EIG Holdings (RICE) Partners, LP (collectively, the “Investors”) pursuant to which (i) Midstream Holdings agreed to issue and sell 375,000 Series B Units (“Series B Units”) with an aggregate liquidation preference of $375.0 million and (ii) GP Holdings agreed to issue and sell common units representing an 8.25% limited partner interest in GP Holdings (“GP Holdings Common Units”) for aggregate consideration of $375.0 million in a private placement (the “Midstream Holdings Investment”) exempt from the registration requirements under the Securities Act. In conjunction with the Securities Purchase Agreement, Midstream Holdings issued 1,000 Series A Units to Rice Energy Operating. The Midstream Holdings Investment closed on February 22, 2016 (the “Closing Date”).

In connection with the Closing Date, (i) Rice Energy Operating and the Investors entered into the Amended and Restated Limited Liability Company Agreement of Midstream Holdings (the “LLC Agreement”), which defines the preferences, rights, powers and duties of holders of the Series B Units and (ii) Rice Midstream GP Management LLC (“GP Management”), as general partner of GP Holdings, and Midstream Holdings and the Investors, as limited partners, entered into the Amended and Restated Agreement of Limited Partnership of GP Holdings, which defines

the preferences, rights, powers and duties of holders of the GP Holdings Common Units (the “GP Holdings A&R LPA”).

In connection with the Midstream Holdings Investment, Midstream Holdings received gross proceeds of $375.0 million less transaction fees and expenses of approximately $6.2 million. Midstream Holdings used approximately $69.0 million of the proceeds to reduce outstanding borrowings under the Midstream Holdings Revolving Credit Facility and $300.0 million was distributed to the Company.

Series B Units

Distributions are payable on January 1, April 1, July 1 and October 1 of each year that the Series B Units remain outstanding. For purposes of the second quarter 2017 distribution, the Company paid $7.7 million in cash in July 2017.

The Investors holding Series B Units have the option to require Midstream Holdings to redeem the Series B Units on or after the tenth anniversary of the Closing Date at an amount equal to $1,000 per Series B Unit plus any accrued and unpaid distributions (the “Liquidation Preference”). The Series B Units are subject to an optional cash redemption by Midstream Holdings after the third anniversary of the Closing Date, at an amount equal to the Liquidation Preference. If any of the Company, the Partnership or Midstream Holdings undergoes a Change in Control (as defined in the LLC Agreement), the Investors have the right to require Midstream Holdings to repurchase any or all of the Series B Units for cash (the “Investor Put Right”), and Midstream Holdings has the right to repurchase any or all of the Series B Units for cash. The redemption price pursuant to the Investor Put Right for a Change of Control prior to February 2019 is equal to the sum of (a) $1,000 per Series B Unit plus (b) any distributions that have accrued but have not been paid on such Series B Units as of the date of determination of a Change in Control plus (c) all distributions that would accrue following the date of determination of a Change in Control through the third anniversary of the Closing Date (“Accelerated Distributions,” and together with (a) and (b), the “Early Redemption Price”). The holders of the Series B units do not have the power to vote or dispose of the equity interest in the Partnership held by GP Holdings.

In relation to the Series B Units, the occurrence of certain events or violations of certain financial and non-financial restrictions will constitute “Triggering Events” (as defined in the Securities Purchase Agreement) that may result in various consequences, including additional restrictions on the activities of Midstream Holdings, including the termination of the Investor’s additional commitment, increases in the distribution rate, additional governance rights for the Investors and other measures depending on the applicable Triggering Event. As of June 30, 2017, none of the Triggering Events had occurred.

GP Holdings Common Units

Pursuant to the GP Holdings A&R LPA, the holders of the GP Holdings Common Units are entitled to distributions of GP Holdings in proportion to their pro rata share of the outstanding GP Holdings Common Units.

Distributions will occur upon GP Holdings receipt of any distributions of cash in respect of the equity interests in the Partnership held by GP Holdings.

The Investors holding GP Holdings Common Units have tag-along rights in connection with a sale of the common equity interests in GP Holdings to a third-party. The holders of GP Holdings Common Units will have drag-along rights in connection with a sale of the majority of the common equity interests in GP Holdings to a third-party, subject to the achievement of an agreed-upon minimum return. If a qualifying initial public offering of GP Holdings is not consummated prior to the fifth anniversary of the Closing Date, the holders of the GP Holdings Common Units shall have the right to require GP Holdings to repurchase all of their GP Holdings Common Units for cash in an aggregate purchase price of $125.0 million. In the event of a Change in Control or a GP Change in Control (as each term is defined in the GP Holdings A&R LPA) of the Company, Midstream Holdings or GP Holdings, the Purchasers shall have the right to require GP Holdings to repurchase all of their GP Holdings Common Units for an aggregate purchase price of $125.0 million (“Minimum Investor Return”). The holders of the GP Holdings Common Units do not have the power to vote or dispose of the Partnership’s units held by GP Holdings.

After September 30, 2016 and prior to the eighteen-month anniversary of the closing of the Midstream Holdings Investment, upon the satisfaction of certain financial and operational metrics, Midstream Holdings has the right to require the Investors to purchase additional Series B Units and GP Holdings Common Units. Midstream Holdings may require the Investors to purchase at least $25.0 million of additional units on up to three occasions, up to a total aggregate amount of $125.0 million. Pursuant to the Securities Purchase Agreement, Midstream Holdings is required to pay the Investors a quarterly cash commitment fee of 2% per annum on any undrawn amounts of the additional $125.0 million commitment. The commitment fee paid in cash was approximately $0.6 million and $1.2 million for the three and six months ended June 30, 2017. No additional units have been purchased by the Investors since the closing of the Midstream Holdings Investment.

As the Investors have an option to redeem the Series B Units and GP Holdings Common Units for cash at a future date, the proceeds from such securities (net of accretion and issuances costs and fees) are not considered to be a component of stockholders’ equity on the condensed consolidated balance sheet, and such Series B Units and GP Holdings Common Units are reported as mezzanine equity on the condensed consolidated balance sheet. The following table represents the value allocated to the Series B Units and GP Holdings Common Units at inception.

(in thousands)
At Inception
Series B Units	$	341,661
GP Holdings Common Units	33,339
Less: issuance costs and fees	(6,242		)
Carrying amount of redeemable noncontrolling interest at inception	$	368,758

Effects of the Proposed Merger

As a result of the entry into the Merger Agreement (as discussed in Note 1), the Company reassessed the probability of a Change in Control under the LLC Agreement and the GP Holdings A&R LPA and determined that a Change in Control was probable. As such, we assessed certain embedded derivatives requiring bifurcation in the LLC Agreement and GP Holdings A&R LPA and determined that the value of the Investor Put Right has increased as a result of the increased probability of the Change in Control. The fair value of the Investor Put Right, a Level 3 financial instrument (refer to Notes 6 and 7), was calculated under a Black-Derman-Toy model and the with-and-without method as a form of the income approach. This method compared the value of the Series B Units with and without the Investor Put Right in determining the fair value of the Investor Put Right as of June 30, 2017.

Significant assumptions in the Black-Derman-Toy model included the treasury yield curve, interest rate volatility curve, market yield spread, probability of the closing of the Merger and the estimated closing date of the Merger. As of June 30, 2017, the fair value of the Investor Put Right embedded derivative was approximately $15.4 million and is included as an embedded derivative liability in the accompanying condensed consolidated balance sheet.

Additionally, as a result of the entry into the Merger Agreement, the Company concluded that while the Series B Units and GP Holdings Common Units were not currently redeemable as of June 30, 2017, it was probable that they would become redeemable by the Investors prior to the respective earliest redemption dates as stipulated in the LLC Agreement and the GP Holdings A&R LPA, respectively. As the Series B Units would become redeemable at the Early Redemption Price, the Company accelerated accretion of the un-accreted discount to the face amount of the Series B Units and began accreting Accelerated Distributions under the assumption that the Merger would close in the fourth quarter of 2017. Similarly, as the GP Holdings Common Units would become redeemable to the effect of the Minimum Investor Return, the Company began accreting the GP Holdings Common Units from their fair value at inception to the Minimum Investor Return under the assumption that the Merger would close in the fourth quarter of 2017. Lastly, the Company accelerated amortization of unamortized issuance costs and fees under the assumption that the Merger would close in the fourth quarter of 2017.

The following table represents detail of the balance of redeemable noncontrolling interest, net on the condensed consolidated balance sheet as of June 30, 2017 after the effects of the Merger as discussed above.

(in thousands)
As of June 30, 2017
Face amount of Series B Units	$	375,000
Plus: Accelerated Distributions	50,997
Plus: distributions paid in kind	11,504
Less: un-accreted discount of face amount of Series B Units	(28,349		)
Less: un-accreted Accelerated Distributions	(47,331		)
Carrying amount of Series B Units	361,821
GP Holdings Common Units	33,339
Plus: additional value to Minimum Investor Return	91,661
Less: un-accreted additional value to Minimum Investor Return	(85,071		)
Carrying amount of GP Holdings Common Units	39,929
Less: unamortized issuance costs and fees	(5,039		)
Redeemable noncontrolling interest, net	$	396,711

The Investors holding GP Common Units are subject to an allocation of income and losses associated with their respective ownership percentages in GP Holdings. Income attributable to the Investors was $1.1 million and $0.9 million for the three months ended June 30, 2017 and 2016, respectively. Income attributable to the Investors for the six months ended June 30, 2017 and for the period from February 22, 2016 through June 30, 2016 was $2.1 million and $1.4 million, respectively.

11. Stockholders’ Equity

The Company’s Board of Directors did not declare or pay a dividend for the six months ended June 30, 2017. On May 18, 2017, a cash distribution of $0.2608 per common and subordinated unit was paid by the Partnership to the Partnership’s unitholders related to the first quarter of 2017. On July 20, 2017, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders for the second quarter of 2017 of $0.2711 per common and subordinated unit. The cash distribution will be paid on August 17, 2017 to unitholders of record at the close of business on August 8, 2017. Also on August 17, 2017, a cash distribution of $1.6 million will be made to GP Holdings related to its incentive distribution rights in the Partnership in accordance with the partnership agreement.

Balance, January 1, 2016		136,387,194
April 2016 Equity Offering		20,000,000
September 2016 Equity Offering		46,000,000
Conversion of warrants into shares of common stock		30,242
Common stock awards vested, net		189,472
Balance as of December 31, 2016		202,606,908
Conversion of REO Common Units (as defined in Note 15) into shares of common stock		8,479,336
Common stock awards vested, net		558,743
Balance, June 30, 2017		211,644,987

12. Incentive Units

In connection with the Company’s initial public offering (“IPO”) and the related corporate reorganization, the Rice Energy Operating incentive unit holders contributed their Rice Energy Operating incentive units to NGP Holdings and Rice Energy Holdings LLC (“Rice Holdings”) in return for (i) incentive units in such entities that, in the aggregate, were substantially similar to the Rice Energy Operating incentive units they previously held and (ii) shares of common stock in the amount of $3.4 million related to the extinguishment of the incentive burden attributable to Mr. Daniel J. Rice III. No payments were made in respect of incentive units prior to the completion of the Company’s IPO. As a result of the IPO, the payment likelihood related to the NGP Holdings and Rice Holdings incentive units was deemed probable, requiring the Company to recognize compensation expense. The compensation expense related to these interests is treated as additional paid in capital from NGP Holdings and Rice Holdings in the Company’s financial statements and is not deductible for federal or state income tax purposes. The compensation expense recognized is a non-cash charge, with the settlement obligation resting on NGP Holdings and Rice Holdings, and as such, the incentive units are not dilutive to Rice Energy Inc.

NGP Holdings

The NGP Holdings incentive units were considered a liability-based award and were adjusted to fair market value on a quarterly basis until all payments were made. During 2016, NGP Holdings sold its remaining shares of the Company’s common stock in connection with the Company’s public offering on April 15, 2016. No future expense will be recognized related to the NGP Holdings incentive units as a result of the April 2016 settlement of the remaining NGP Holdings incentive unit obligation. The Company recognized $9.0 million and $27.3 million of non-cash compensation expense for the three and six months ended June 30, 2016, respectively.

Rice Holdings

The Rice Holdings incentive units are considered an equity-based award with the fair value of the award determined at the grant date and amortized over the service period of the award using the straight-line method. Compensation expense relative to the Rice Holdings incentive units was $4.8 million and $7.7 million for the three and six months ended June 30, 2017, respectively, and $5.8 million and $11.7 million for the three and six months ended June 30, 2016, respectively. The Company will recognize approximately $3.3 million of additional compensation expense over the remaining expected service period related to the Rice Holdings incentive units.

In August 2014, the triggering event for the Rice Holdings incentive units was achieved. As a result, in September 2014, 2015 and 2016, Rice Holdings distributed one quarter, one third and one half, respectively, of its then-remaining assets (consisting solely of shares of the Company’s common stock) to its members pursuant to the terms of its limited liability company agreement. In addition, in September 2017, Rice Holdings will distribute all of its then-remaining assets (consisting solely of shares of the Company’s common stock) to its members pursuant to the terms of its limited liability company agreement. As a result, over time, the shares of the Company’s common stock held by Rice Holdings will be transferred in their entirety to the members of Rice Holdings.

Combined

Total combined compensation expense attributable to the incentive units was $4.8 million and $7.7 million for the three and six months ended June 30, 2017, respectively, and $14.8 million and $39.0 million for the three and six months ended June 30, 2016, respectively.

The three tranches of the incentive units having a time vesting feature and were fully vested as of December 31, 2016.

Two tranches of the incentive units do not have a time vesting feature, and their payouts are triggered upon a future payment condition. As such, none of these awards have vested as of June 30, 2017.

13. Variable Interest Entities

Rice Midstream Partners LP

The Company evaluated the Partnership for consolidation and determined the Partnership to be a VIE. The Company determined that the primary beneficiary of the Partnership is GP Holdings. As of June 30, 2017, Midstream Holdings held a significant indirect interest in the Partnership through (i) its ownership of a 91.75% limited liability partnership interest in GP Holdings, which owned an approximate 28% limited partner interest in the Partnership, and (ii) through ownership of its wholly-owned subsidiary Rice Midstream Management LLC, which holds all of the substantive voting and participating rights in the Partnership. As a result, through this ownership, the Company holds the power to direct the activities of the Partnership that most significantly impact the Partnership’s economic performance and the obligation to absorb losses or the right to receive benefits from the Partnership that could potentially be significant to the Partnership.

As of June 30, 2017, the Company consolidated the Partnership, recording noncontrolling interest related to the net income of the Partnership attributable to its public unitholders. The following table presents summary information of assets and liabilities of the Partnership that is included in the Company’s condensed consolidated balance sheets that are for the use or obligation of the Partnership.

(in thousands)	June 30, 2017			December 31, 2016
Assets (liabilities):
Cash	$	12,196		$	21,834
Accounts receivable	9,058			8,758
Other current assets	129			64
Property and equipment, net	860,011			805,027
Goodwill and intangible assets, net	538,297			539,105
Deferred financing costs, net	10,493			12,591
Accounts payable	(9,376		)	(4,172		)
Accrued capital expenditures	(16,288		)	(9,074		)
Other current liabilities	(7,313		)	(8,376		)
Long-term debt	(206,000		)	(190,000		)
Other long-term liabilities	(6,283		)	(5,189		)

The following table presents summary information of the Partnership’s financial performance included in the condensed consolidated statements of operations for the three and six months ended June 30, 2017 and 2016 and cash flows for the six months ended June 30, 2017 and 2016, inclusive of affiliate amounts.

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2017		2016		2017			2016
Operating revenues	$	72,377	$	46,547	$	135,127		$	101,090
Operating expenses	$	25,365	$	17,547	$	47,519		$	36,473
Net income	$	44,059	$	27,936	$	81,674		$	62,362

Net cash provided by operating activities					$	86,857		$	74,664
Net cash used in investing activities					$	(58,036	)	$	(75,019	)
Net cash (used in) provided by financing activities					$	(38,460	)	$	8,081

The following table presents the Company’s limited partner ownership of the Partnership for the periods ended June 30, 2017 and December 31, 2016.

	Partnership units owned by GP Holdings (Common and Subordinated)	Total Partnership Units Outstanding	GP Holdings % Ownership in the Partnership		% Ownership in the Partnership Retained by the Company
As of:
December 31, 2015	28,757,246	70,917,372	41	%	41	%
Equity offering in June 2016	—	9,200,000
Equity offering in October 2016	—	20,930,233
Common units issued under ATM program	—	944,700
Vested phantom units, net	—	280,451
December 31, 2016	28,757,246	102,272,756	28	%	26	%

Vested phantom units, net	—	30,352
June 30, 2017	28,757,246	102,303,108	28	%	26	%

Rice Midstream GP Holdings LP

As of June 30, 2017, the Company consolidates GP Holdings, recording noncontrolling interest related to the ownership interests of GP Holdings attributable to the Investors. GP Holdings maintains goodwill of $15.4 million and has no other significant assets, liabilities or operations other than consolidation of the Partnership.

Strike Force Midstream Holdings LLC

On February 1, 2016, Strike Force Midstream Holdings LLC (“Strike Force Holdings”), a wholly-owned subsidiary of Midstream Holdings, and Gulfport Midstream, entered into an Amended and Restated Limited Liability Company Agreement (the “Strike Force LLC Agreement”) of Strike Force Midstream to engage in the natural gas midstream business in approximately 319,000 acres in Belmont and Monroe Counties, Ohio. Under the terms of the Strike Force LLC Agreement, Strike Force Holdings made an initial contribution to Strike Force Midstream of certain pipelines, facilities and rights of way and cash in the amount of $41.0 million in exchange for a

75% membership interest in Strike Force Midstream. Gulfport Midstream made an initial contribution of a gathering system and related assets in exchange for a 25% membership interest in Strike Force Midstream. The assets contributed by Gulfport Midstream had a fair value of $22.5 million which was determined using Level 3 valuation inputs included in the discounted cash flow method within the income approach. The income approach includes estimates and assumptions related to future throughput volumes, operating costs, capital spending and changes in working capital. Estimating the fair value of these assets required judgment and determining the fair value is sensitive to changes in assumptions. Additionally, on February 1, 2016, Strike Force Midstream and Strike Force Holdings entered into a services agreement whereby Strike Force Holdings will provide all of the services necessary to operate, manage and maintain Strike Force Midstream.

As of June 30, 2017, the Company consolidates Strike Force Midstream, recording noncontrolling interest related to the ownership interests of Strike Force Midstream attributable to Gulfport Midstream. The following table presents summary information of assets and liabilities of Strike Force Midstream that is included in the Company’s condensed consolidated balance sheet that are for the use or obligation of Strike Force Midstream.

(in thousands)	June 30, 2017			December 31, 2016
Assets (liabilities):
Cash	$	38,142		$	36,572
Accounts receivable	7,160			2,529
Property and equipment, net	203,925			100,232
Accounts payable	(1,987		)	(3,863		)
Accrued capital expenditures	(32,261		)	(18,962		)
Other current liabilities	(83		)	(44		)

The following table presents summary information for Strike Force Midstream’s financial performance included in the condensed consolidated statement of operations for the three and six months ended June 30, 2017 and 2016 and cash flows for the six months ended June 30, 2017 and 2016, inclusive of affiliate amounts.

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2017		2016		2017			2016
Operating revenues	$	11,646	$	2,264	$	16,985		$	2,883
Operating expenses	$	2,837	$	1,527	$	5,245		$	2,415
Net income	$	8,850	$	737	$	11,812		$	468

Net provided by (used in) operating activities					$	7,599		$	(791	)
Net cash used in investing activities					$	(93,291	)	$	(18,076	)
Net cash provided by financing activities					$	87,261		$	53,000

Rice Energy Operating LLC

making of Rice Energy Operating without approval of any other member, unless otherwise stated in the Third A&R LLC Agreement. As such, the Company, through its officers and directors, is responsible for all operational and administrative decisions of Rice Energy Operating and the day-to-day management of Rice Energy Operating’s business. Pursuant to the terms of the Third A&R LLC Agreement, the Company cannot, under any circumstances, be removed or replaced as the sole manager of Rice Energy Operating, except by its own election so long as it remains a member of Rice Energy Operating.

The Company evaluated Rice Energy Operating for consolidation and determined it to be a VIE. The Company determined that it is the primary beneficiary of Rice Energy Operating as it had both (i) the power, through control of all day-to-day business affairs and decision making of Rice Energy Operating that most significantly impact its economic performance and (ii) obligation to absorb losses or the right to receive benefits through its 87.04% membership interest in Rice Energy Operating. The 12.96% ownership held by the Vantage Sellers as of June 30, 2017 is presented as noncontrolling interest in the consolidated financial statements.

As of June 30, 2017, the Company consolidates Rice Energy Operating, recording noncontrolling interest related to the ownership interests of Rice Energy Operating attributable to the Vantage Sellers. The financial position, results of operations and cash flows of Rice Energy Operating do not materially differ from the Company’s second quarter 2017 condensed consolidated financial statements.

The following tables present the outstanding common units owned by Rice Energy and the Vantage Sellers along with their respective ownership percentages in the Company as of June 30, 2017 and December 31, 2016.

As of June 30, 2017:

Unitholders	Common Units	Preferred Stock	Unitholders’ Ownership (%)
Rice Energy	211,644,987	—	87.04	%
Vantage Sellers(1)	31,520,664	31,521	12.96	%
Total	243,165,651	31,521	100.00	%

(1) During the six months ended June 30, 2017, the Vantage Sellers elected to have the Company redeem 8,479,336 REO Common Units for newly-issued shares of Rice Energy common stock. Upon exercise of the redemptions, the Vantage Sellers surrendered to the Company a corresponding 8,479 shares of preferred stock.

As of December 31, 2016:

Unitholders	Common Units	Preferred Stock	Unitholders’ Ownership (%)
Rice Energy	202,606,908	—	83.51	%
Vantage Sellers	40,000,000	40,000	16.49	%
Total	242,606,908	40,000	100.00	%

14. Stock-Based Compensation

From time to time, the Company grants stock-based compensation awards to certain non-employee directors and employees under its long-term incentive plan (the “LTIP”). Pursuant to the LTIP, the aggregate maximum number of shares of common stock issued under the LTIP will not exceed 17,500,000 shares. The Company has granted both restricted stock units and performance stock units, which vest upon the passage of time. The performance stock units’ ultimate payout is based upon the attainment of specified performance criteria over a performance period. During the three and six months ended June 30, 2017, the Company granted approximately 0.1 million and 0.9 million restricted stock units, respectively, which are expected to vest ratably over approximately one to three years. During the three and six months ended June 30, 2017, the Company granted approximately zero and 0.7 million performance stock units, respectively, which are expected to cliff vest in approximately three years. Stock-based compensation cost related to awards under the LTIP was $6.5 million and $11.9 million for the three and six months ended June 30, 2017, respectively, and $5.2 million and $9.2 million for the three and six months ended June 30, 2016, respectively. The Company has unrecognized compensation cost related to LTIP awards of $43.0 million which will be recognized over a period of one to three years.

Further information on stock-based compensation recorded in the condensed consolidated financial statements is detailed below.

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2017		2016		2017		2016
General and administrative expense	$	6,229	$	6,149	$	11,315	$	10,789
Lease operating and midstream operation and maintenance expense	182		83		386		253
Property, plant and equipment, net	239		63		436		263
Total cost of stock-based compensation plans	$	6,650	$	6,295	$	12,137	$	11,305

15. Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with redemptions of Rice Energy Operating common units (“REO Common Units”) and stock awards that have been granted to directors and employees. The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for three and six months ended June 30, 2017 and 2016.

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except share data)	2017			2016			2017			2016
Income (loss) (numerator):
Net income (loss) attributable to Rice Energy Inc.	$	83,525		$	(156,686	)	$	57,227		$	(174,274	)
Less: Preferred dividends on redeemable noncontrolling interest	(7,709		)	(7,587		)	(15,333		)	(10,719		)
Less: Accretion of redeemable noncontrolling interest	(12,947		)	(357		)	(13,655		)	(683		)
Net income (loss) available to Rice Energy Inc. common stockholders	62,869			(164,630		)	28,239			(185,676		)

Weighted-average number of shares of common stock (denominator):
Basic	205,791,010			153,203,901			204,619,590			144,811,902
Diluted	207,713,584			153,203,901			206,508,591			144,811,902

Earnings (loss) per share:
Basic	$	0.31		$	(1.07	)	$	0.14		$	(1.28	)
Diluted	$	0.30		$	(1.07	)	$	0.14		$	(1.28	)

For the three and six months ended June 30, 2017, shares in the amount of 36,779,485 and 38,301,930, respectively, attributable to equity awards and units in REO were not included in the diluted earnings per share calculation because to do so would have been anti-dilutive. For the three and six months ended June 30, 2016, shares in the amount of 1,528,234 and 807,511, respectively, attributable to equity awards were not included in the diluted earnings per share calculation because to do so would have been anti-dilutive.

As part of the consideration associated with the Vantage Acquisition, the Vantage Sellers were issued 40,000,000 REO Common Units. The holders of the REO Common Units, other than the Company, are entitled to redeem, from time to time, all or a portion of their REO Common Units. Each REO Common Unit will be redeemed for, at Rice Energy Operating’s option, a newly-issued share of common stock of the Company or a cash

payment equal to the volume-weighted average closing price of a share of the Company’s common stock for the five trading days prior to and including the last full trading day immediately prior to the date that the member delivers a notice of redemption (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). Upon the exercise of the redemption right, the redeeming member surrenders its REO Common Units to Rice Energy Operating and the corresponding number of 1/1000ths of shares of preferred stock in respect of each redeemed REO Common Unit to Rice Energy Operating for cancellation. As of June 30, 2017, the Vantage Sellers redeemed 8,479,336 of Rice Energy Operating common units for newly-issued shares of Rice Energy common stock. Upon exercise of those redemptions, the Vantage Sellers surrendered to the Company a corresponding 8,479 shares of Preferred Stock. As of June 30, 2017, the Vantage Sellers held a membership interest of approximately 12.96% in REO.

16. Income Taxes

The Company is a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings and, as such, its future income taxes will be dependent upon its future taxable income. The Company estimates an annual effective income tax rate based on projected results for the year and applies this rate to income before taxes to calculate income tax expense, subject to certain loss limitation provisions. All of the Partnership’s earnings are included in the Company’s net income; however, the Company is not required to record income tax expense with respect to the portion of the Partnership’s earnings allocated to the Partnership’s noncontrolling public limited partners, which reduces the Company’s effective tax rate. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period.

Tax expense for the three and six months ended June 30, 2017 was $33.9 million and $33.3 million, respectively, resulting in effective tax rates of approximately 20% during each period. The tax benefit for the three and six months ended June 30, 2016 was $120.5 million and $126.9 million, respectively, resulting in an effective tax rate of approximately 46% and 48%, respectively. The effective tax rate for the three and six months ended June 30, 2017 and 2016 differs from the statutory rate due principally to nondeductible incentive unit expense and the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners, and the application of loss limitation provisions.

Based on management’s analysis, the Company did not have any uncertain tax positions as of June 30, 2017.

The assignment of the common and subordinated units in the Midstream Holdings Investment resulted in the sale or exchange of more than 50 percent of its capital and profits interests of the Partnership within 12 months. Accordingly, the Partnership is considered to have “technically terminated” as a partnership for U.S. federal income tax purposes. The technical termination will not affect the Partnership’s consolidated financial statements, nor will it affect the Partnership’s classification as a partnership or the nature or extent of its “qualifying income” for U.S. federal income tax purposes. The taxable year for all unitholders ended on February 22, 2016 and will result in a deferral of depreciation deductions that were otherwise allowable in computing the taxable income of the Partnership’s unitholders for the period from January 1, 2016 through February 22, 2016.

The Company’s change in tax status concurrent with the Vantage Acquisition on October 19, 2016 resulted in a second technical termination of the Partnership. The taxable year for all unitholders ended on October 19, 2016 and will result in a deferral of depreciation deductions that were otherwise allowable in computing the taxable income of the Partnership’s unitholders for the period February 23, 2016 through October 19, 2016.

The members of Rice Energy Operating, including the Company, incur U.S. federal, state and local income taxes on their share of any taxable income of Rice Energy Operating, if any. Under the Third A&R LLC Agreement, Rice Energy Operating is required to make cash tax distributions to its members, subsequent to the end of a given calendar year, based upon income allocated to each member and subject to the availability of distributable cash (as defined in the Third A&R LLC Agreement).

17. New Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606).” The FASB created Topic 606 which supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance throughout the Industry Topics of the Codification. The FASB and International Accounting Standards Board initiated this joint project to clarify the principles for recognizing revenue and to develop a common revenue standard for both U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 will enhance comparability of revenue recognition practices across entities, industries and capital markets compared to existing guidance. Additionally, ASU 2014-09 will reduce the number of requirements which an entity must consider in recognizing revenue, as this update will replace multiple locations for guidance. In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers (Topic 606) - Identifying Performance Obligations and Licensing.” In May 2016, the FASB issued ASU 2016-11, “Revenue from Contracts with Customers (Topic 606) and Derivatives and Hedging (Topic 815) - Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting” and ASU 2016-12, “Revenue from Contracts with Customers (Topic 606) - Narrow Scope Improvements and Practical Expedients.” These updates do not change the core principle of the guidance in Topic 606 (as amended by ASU 2014-09), but rather provide further guidance with respect to the implementation of ASU 2014-09. The effective date for ASU 2016-10, 2016-11, 2016-12 and ASU 2014-09, as amended by ASU 2015-14, is for annual reporting periods beginning after December 15, 2017, including interim periods within those years. In preparation for the adoption of the new standard in the fiscal year beginning January 2018, the Company continues to evaluate contract terms and potential impacts of the five-step model specified by the new guidance. That five-step model includes: (1) determination of whether a contract-an agreement between two or more parties that creates legally enforceable rights and obligations-exists; (2) identification of the performance obligations in the contract; (3) determination of the transaction price; (4) allocation of the transaction price to the performance obligations in the contract; and (5) recognition of revenue when (or as) the performance obligation is satisfied. The Company anticipates adopting the standard using the modified retrospective approach at adoption. The Company is currently evaluating individual customer contracts within each of our business segments and documenting changes to our accounting policies and controls as we continue to evaluate the impact of the adoption of this standard.

In February 2016, the FASB issued ASU, 2016-02, “Leases (Topic 842)” ASU 2016-02 which requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new guidance is effective for annual and interim reporting periods beginning after December 15, 2018. The amendments should be applied at the beginning of the earliest period presented using a modified retrospective approach with earlier application permitted as of the beginning of an interim or annual reporting period. The Company continues to evaluate a representative sample of agreements, including existing leases, to assess the impact of the new guidance on its financial statements.

In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016-09 affects entities that issue share-based payment awards to their employees. ASU 2016-09 is designed to simplify several aspects of accounting for share-based payment award transactions, including: (a) income tax consequences, (b) classification of awards as either equity or liabilities, (c) classification on the statement of cash flows and (d) forfeiture rate calculations. The Company adopted ASU 2016-09 on January 1, 2017 and determined that the standard did not have a material impact on the condensed consolidated financial statements.

In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The standard introduces a screen for determining when assets acquired are not a business and clarifies that a business must include, at a minimum, an input and a substantive process that contribute to an output to be considered a business. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The Company adopted this ASU on January 1, 2017, and has determined that the new standard could potentially have a material impact on future consolidated financial statements for acquisitions that are not considered to be businesses.

In January 2017, the FASB issued ASU 2017-04, “Simplifying the Test of Goodwill Impairment.” ASU 2017-04 simplifies the quantitative goodwill impairment test requirements by eliminating the requirement to calculate the implied fair value of goodwill (Step 2 of the current goodwill impairment test). Instead, a company would record an impairment charge based on the excess of a reporting unit’s carrying value over its fair value (measured in Step 1 of the current goodwill impairment test). This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. Entities will apply the standard’s provisions prospectively. The Company adopted ASU 2017-04 on January 1, 2017 and determined that this standard will not have a material quantitative effect on the financial statements, unless an impairment charge was necessary.

In May 2017, the FASB issued ASU 2017-09, “Stock Compensation (Topic 718): Scope of Modification Accounting”. ASU 2017-09 clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017 with early adoption permitted. The Company is currently evaluating the impact that this guidance will have on its consolidated financial statements.

18. Subsequent Events

The Company has evaluated subsequent events through the date these financial statements were issued. The Company has determined there were no events, other than as described below, that required disclosure or recognition in these financial statements.

On July 7, 2017, the Company completed an asset acquisition pursuant to a purchase and sale agreement with an undisclosed seller to acquire approximately 16,400 Marcellus Shale acres, the majority of which are located in Greene County, Pennsylvania, for a purchase price of $180.3 million in cash. The Company funded the consideration for the acquisition with cash on hand and borrowings under the Company’s A&R Credit Agreement. In conjunction with the execution of the purchase agreement, the Company deposited $18.0 million into an escrow account, which is included in the acquisition deposit line on the Company’s condensed consolidated balance sheet as of June 30, 2017 and as an investing outflow on the condensed consolidated statement of cash flows for the six months ended June 30, 2017.

On July 11, 2017, the Company entered into a purchase and sale agreement (the “Barnett Purchase and Sale Agreement”) by and among Vantage Fort Worth Energy LLC, a subsidiary of the Company, and an undisclosed buyer. Pursuant to the Barnett Purchase and Sale Agreement, the buyer will acquire substantially all of the Company’s oil and gas properties in the Fort Worth Basin and assume the related obligations for an aggregate purchase price of $175.0 million, subject to purchase price adjustments and customary closing conditions. The net carrying value of the Company’s Fort Worth Basin oil and gas properties was approximately $175.0 million as of June 30, 2017. The transaction has an effective date of January 1, 2017 and is expected to close in the third quarter of 2017. Although the Company is unable to estimate the final net proceeds from the divestiture, we anticipate that a loss will occur as a result of the disposition and such loss could be material.

In July 2017, the Vantage Sellers elected to have the Company redeem 2,152,152 REO Common Units for newly-issued shares of Rice Energy common stock. Upon exercise of the redemption, the Vantage Sellers surrendered to the Company a corresponding 2,152 shares of Preferred Stock.

19. Guarantor Financial Information

On April 25, 2014, the Company issued $900.0 million in aggregate principal amount of the 2022 Notes and on March 26, 2015, the Company issued $400.0 million in aggregate principal amount of the 2023 Notes. The obligations under the Notes are fully and unconditionally guaranteed by the guarantors, subject to release provisions described in Note 5. In connection with the closing of the Vantage Acquisition, the Company and Rice Energy Operating entered into a Debt Assumption Agreement dated as of October 19, 2016 pursuant to which Rice Energy Operating agreed to become a co-obligor of the Notes and certain entities acquired in the Vantage Acquisition became wholly-owned subsidiaries of Rice Energy Operating and guarantors of the Notes. Each of the guarantors is 100% owned by Rice Energy Operating.

The Company is a holding company whose sole material asset is an equity interest in Rice Energy Operating. The Company is a member and the sole manager of Rice Energy Operating. Rice Energy owns an approximate 87.04% membership in Rice Energy Operating as of June 30, 2017. Rice Energy is responsible for all operational, management and administrative decisions related to Rice Energy Operating’s business. In accordance with the Third A&R LLC Agreement, the Company may not be removed as the sole manager of Rice Energy Operating so long as it continues to be a member of Rice Energy Operating.

As of June 30, 2017, the Company held approximately 87.04% of the economic interest in Rice Energy Operating, with the remaining 12.96% membership interest collectively held by the Vantage Sellers. The Vantage Sellers have no voting rights with respect to their membership interest in Rice Energy Operating. In connection with the closing of the Vantage Acquisition, the Company issued shares of preferred stock to the Vantage Sellers in an amount equal to 1/1000 of the number of REO Common Units they received at the closing of the Vantage Acquisition. Pursuant to the certificate of designation setting forth the terms, rights and obligations and preferences of the preferred stock, each 1/1000 share of preferred stock entitles the holder to one vote on all matters submitted to a vote of the holders of common stock. Accordingly, the Vantage Sellers collectively have a number of votes in the Company equal to the aggregate number of REO Common Units that they hold.

The Vantage Sellers have a redemption right to cause Rice Energy Operating to redeem, from time to time, all or a portion of their REO Common Units. Each REO Common Unit will be redeemed for, at Rice Energy Operating’s option, a newly-issued share of common stock of the Company or a cash payment equal to the volume-weighted average closing price of a share of the Company’s common stock for the five trading days prior to and including the last full trading day immediately prior to the date that the member delivers a notice of redemption (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). Upon the exercise of the redemption right, the redeeming member surrenders its REO Common Units to Rice Energy Operating and the corresponding number of 1/1000ths of shares of preferred stock in respect of each redeemed Common Unit to Rice Energy Operating for cancellation. The Third A&R LLC Agreement requires that the Company contribute cash or shares of its common stock to Rice Energy Operating in exchange for a number of REO Common Units equal to the number of REO Common Units to be redeemed from the member. Rice Energy Operating will then distribute such cash or shares of the Company’s common stock to such Vantage Seller to complete the redemption. Upon the exercise of the redemption right, the Company may, at its option, effect a direct exchange of the REO Common Units (and the corresponding shares of preferred stock (or fractions thereof) from the redeeming Vantage Seller.

As a result, the Company expects that over time it will have an increasing economic interest in Rice Energy Operating as the Vantage Sellers elect to exercise their redemption right. Moreover, any transfers of REO Common Units by the Vantage Sellers (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over Rice Energy Operating.

The Company’s subsidiaries that comprise its Rice Midstream Holdings segment and Rice Midstream Partners segment are unrestricted subsidiaries under the indentures governing the Notes and consequently are not guarantors. In accordance with positions established by the SEC, the following shows separate financial information with respect to the Company, Rice Energy Operating and the guarantors and the non-guarantor subsidiaries. Separate financial statements for Rice Energy Operating will be provided in Rice Energy Operating’s Quarterly Report on Form 10-Q for the three months ended June 30, 2017. The principal elimination entries below eliminate investment in subsidiaries and certain intercompany balances and transactions.

Condensed Consolidated Balance Sheet as of June 30, 2017

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC		Guarantors			Non- Guarantors			Eliminations			Consolidated
Assets
Current assets:
Cash	$	19,770		$	108,731	$	(19,154	)	$	52,193		$	—		$	161,540
Accounts receivable	120			1,804		315,469			22,026			—			339,419
Receivable from affiliates	18,089			1,301		(46,051		)	26,661			—			—
Prepaid expenses, deposits and other assets	6,847			21		4,221			258			—			11,347
Derivative assets	—			2,294		8,330			—			—			10,624
Total current assets	44,826			114,151		262,815			101,138			—			522,930

Investments in (advances from) subsidiaries	3,492,232			4,882,206		724			—			(8,375,162		)	—
Gas collateral account	—			—		5,220			112			—			5,332
Property, plant and equipment, net	25,657			—		5,114,594			1,391,137			(85,137		)	6,446,251
Acquisition deposit	—			—		18,033			—			—			18,033
Deferred financing costs, net	—			20,766		—			12,508			—			33,274
Goodwill	—			384,431		—			494,580			—			879,011
Intangible assets, net	—			—		—			43,717			—			43,717
Other non-current assets	744			—		45			—			—			789
Derivative assets	—			23,972		21,741			—			—			45,713
Total assets	$	3,563,459		$	5,425,526	$	5,423,172		$	2,043,192		$	(8,460,299	)	$	7,995,050

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	674		$	200	$	11,043		$	12,214		$	—		$	24,131
Royalties payable	—			—		104,091			—			—			104,091
Accrued capital expenditures	—			—		120,163			56,431			—			176,594
Accrued interest	—			14,208		—			332			—			14,540
Leasehold payables	—			—		19,538			—			—			19,538
Derivative liabilities	—			34,458		4,603			—			—			39,061
Embedded derivative liability	—			—		—			15,417			—			15,417
Other accrued liabilities	17,748			2,375		53,446			16,625			—			90,194
Total current liabilities	18,422			51,241		312,884			101,019			—			483,566

Long-term liabilities:
Long-term debt	—			1,281,279		—			318,500			—			1,599,779
Leasehold payable	—			—		12,279			—			—			12,279
Deferred tax liabilities	362,767			—		—			—			—			362,767
Derivative liabilities	—			22,091		2,500			—			—			24,591
Other long-term liabilities	9,183			—		74,738			6,283			—			90,204
Total liabilities	390,372			1,354,611		402,401			425,802			—			2,573,186
Mezzanine equity:
Redeemable noncontrolling interest	—			—		—			396,711			—			396,711
Stockholders’ equity before noncontrolling interest	3,210,729			3,492,232		5,020,771			(138,564		)	(8,460,299		)	3,124,869
Noncontrolling interest	(37,642		)	578,683		—			1,359,243			—			1,900,284
Total liabilities and stockholders’ equity	$	3,563,459		$	5,425,526	$	5,423,172		$	2,043,192		$	(8,460,299	)	$	7,995,050

Condensed Consolidated Balance Sheet as of December 31, 2016

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC		Guarantors		Non- Guarantors			Eliminations			Consolidated
Assets
Current assets:
Cash	$	2,756		$	230,944	$	164,522	$	71,821		$	—		$	470,043
Accounts receivable	22,525			—		201,122		28,990			(34,012		)	218,625
Prepaid expenses, deposits and other	2,651			—		2,214		194			—			5,059
Derivative assets	—			689		—		—			—			689
Total current assets	27,932			231,633		367,858		101,005			(34,012		)	694,416

Gas collateral account	—			—		5,220		112			—			5,332
Investments in subsidiaries	2,928,250			4,406,023		6,101		—			(7,340,374		)	—
Property, plant and equipment, net	25,622			—		4,947,518		1,203,047			(58,275		)	6,117,912
Deferred financing costs, net	—			21,372		—		15,012			—			36,384
Goodwill	—			384,430		—		494,581			—			879,011
Intangible assets, net	—			—		—		44,525			—			44,525
Derivative assets	138			27,894		11,296		—			—			39,328
Other non-current assets	—			—		614		—			—			614
Total assets	$	2,981,942		$	5,071,352	$	5,338,607	$	1,858,282		$	(7,432,661	)	$	7,817,522

Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	926		$	—	$	8,724	$	8,594		$	—		$	18,244
Royalties payable	—			—		87,098		—			—			87,098
Accrued capital expenditures	—			—		89,403		35,297			—			124,700
Accrued interest	—			14,208		—		232			—			14,440
Leasehold payables	—			—		22,869		—			—			22,869
Derivative liabilities	—			72,391		66,997		—			—			139,388
Other accrued liabilities	54,064			4,786		84,950		16,219			(34,012		)	126,007
Total current liabilities	54,990			91,385		360,041		60,342			(34,012		)	532,746

Long-term liabilities:
Long-term debt	—			1,279,481		—		243,000			—			1,522,481
Leasehold payable	—			—		9,237		—			—			9,237
Deferred tax liabilities	—			26,561		209,276		122,789			—			358,626
Derivative liabilities	—			9,766		16,711		—			—			26,477
Other long-term liabilities	8,858			—		66,949		5,541			—			81,348
Total liabilities	63,848			1,407,193		662,214		431,672			(34,012		)	2,530,915
Mezzanine equity:
Redeemable noncontrolling interest	—			—		—		382,525			—			382,525
Stockholders’ equity before noncontrolling interest	2,972,578			2,928,250		4,676,393		(270,370		)	(7,398,649		)	2,908,202
Noncontrolling interests in consolidated subsidiaries	(54,484		)	735,909		—		1,314,455			—			1,995,880
Total liabilities and stockholders’ equity	$	2,981,942		$	5,071,352	$	5,338,607	$	1,858,282		$	(7,432,661	)	$	7,817,522

Condensed Consolidated Statement of Operations for the Three Months Ended June 30, 2017

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non- Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	—		$	348,892		$	—		$	—		$	348,892
Gathering, compression and water services	—			—			—			104,324			(66,259		)	38,065
Other revenue	—			—			11,350			—			—			11,350
Total operating revenues	—			—			360,242			104,324			(66,259		)	398,307

Operating expenses:
Lease operating	—			—			17,740			—			(95		)	17,645
Gathering, compression and transportation	—			—			85,915			—			(46,784		)	39,131
Production taxes and impact fees	—			—			6,679			—			—			6,679
Exploration	—			—			7,106			—			—			7,106
Midstream operation and maintenance	—			—			—			10,714			(2,366		)	8,348
Incentive unit expense	—			—			4,663			137			—			4,800
Acquisition expense	—			—			1,356			1,052			—			2,408
General and administrative	—			—			25,652			13,574			—			39,226
Depreciation, depletion and amortization	—			—			141,479			9,332			(4,907		)	145,904
Amortization of intangible assets	—			—			—			406			—			406
Other expense	—			—			11,211			1,996			—			13,207
Total operating expenses	—			—			301,801			37,211			(54,152		)	284,860

Operating income (loss)	—			—			58,441			67,113			(12,107		)	113,447
Interest expense	—			(23,898		)	4			(3,375		)	—			(27,269		)
Other income (loss)	—			201			(20		)	92			—			273
Gain on derivative instruments	—			56,228			47,330			—			—			103,558
Loss on embedded derivatives	—			—			—			(15,417		)	—			(15,417		)
Amortization of deferred financing costs	—			(2,175		)	—			(1,251		)	—			(3,426		)
Equity income (loss) in affiliate	137,214			106,858			—			—			(244,072		)	—
Income before income taxes	137,214			137,214			105,755			47,162			(256,179		)	171,166
Income tax expense	(33,917		)	—			—			—			—			(33,917		)
Net income (loss)	103,297			137,214			105,755			47,162			(256,179		)	137,249
Less: Net income attributable to the noncontrolling interests	(19,866		)	—			—			(33,858		)	—			(53,724		)
Net income (loss) attributable to Rice Energy	83,431			137,214			105,755			13,304			(256,179		)	83,525
Less: Preferred dividends and accretion of redeemable noncontrolling interests	—			—			—			(20,656		)	—			(20,656		)
Net income (loss) attributable to Rice Energy Inc. common stockholders	$	83,431		$	137,214		$	105,755		$	(7,352	)	$	(256,179	)	$	62,869

Condensed Consolidated Statement of Operations for the Three Months Ended June 30, 2016

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non- Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	—		$	122,312		$	—		$	—		$	122,312
Gathering, compression and water services	—			—			—			58,420			(34,692		)	23,728
Other revenue	—			—			9,958			—			—			9,958
Total operating revenues	—			—			132,270			58,420			(34,692		)	155,998

Operating expenses:
Lease operating	—			—			9,038			—			—			9,038
Gathering, compression and transportation	—			—			51,307			—			(24,138		)	27,169
Production taxes and impact fees	—			—			2,659			—			—			2,659
Exploration	—			—			5,548			—			—			5,548
Midstream operation and maintenance	—			—			—			4,602			(47		)	4,555
Incentive unit expense	—			—			14,141			699			—			14,840
Acquisition expense	—			—			—			84			—			84
General and administrative	—			—			18,351			10,921			—			29,272
Depreciation, depletion and amortization	—			—			79,516			8,412			(3,176		)	84,752
Amortization of intangible assets	—			—			—			403			—			403
Other expense	—			—			11,096			361			—			11,457
Total operating expenses	—			—			191,656			25,482			(27,361		)	189,777

Operating (loss) income	—			—			(59,386		)	32,938			(7,331		)	(33,779		)
Interest expense	—			(22,853		)	(24		)	(1,925		)	—			(24,802		)
Other income	—			558			1,991			—			—			2,549
Loss on derivative instruments	—			(75,167		)	(126,388		)	—			—			(201,555		)
Amortization of deferred financing costs	—			(1,122		)	—			(496		)	—			(1,618		)
Equity (loss) income in affiliate	(155,200		)	(144,423		)	(61		)	—			299,684			—
Income before income taxes	(155,200		)	(243,007		)	(183,868		)	30,517			292,353			(259,205		)
Income tax (expense) benefit	—			87,807			84,985			(52,296		)	—			120,496
Net (loss) income	(155,200		)	(155,200		)	(98,883		)	(21,779		)	292,353			(138,709		)
Less: Net income attributable to the noncontrolling interests	—			—			—			(17,977		)	—			(17,977		)
Net (loss) income attributable to Rice Energy	(155,200		)	(155,200		)	(98,883		)	(39,756		)	292,353			(156,686		)
Less: Preferred dividends and accretion of redeemable noncontrolling interests	—			—			—			(7,944		)	—			(7,944		)
Net (loss) income attributable to Rice Energy Inc. common stockholders	$	(155,200	)	$	(155,200	)	$	(98,883	)	$	(47,700	)	$	292,353		$	(164,630	)

Condensed Consolidated Statement of Operations for the Six Months Ended June 30, 2017

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors		Non- Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	—		$	705,726	$	—		$	—		$	705,726
Gathering, compression and water services	—			—			—		193,918			(125,510		)	68,408
Other revenue	—			—			17,979		—			—			17,979
Total operating revenues	—			—			723,705		193,918			(125,510		)	792,113

Operating expenses:
Lease operating	—			—			40,389		—			(95		)	40,294
Gathering, compression and transportation	—			—			167,810		—			(89,253		)	78,557
Production taxes and impact fees	—			—			12,832		—			—			12,832
Impairment of proved/unproved properties	—			—			92,355		—			—			92,355
Exploration	—			—			11,118		—			—			11,118
Midstream operation and maintenance	—			—			—		19,654			(4,656		)	14,998
Incentive unit expense	—			—			7,464		219			—			7,683
Acquisition expense	—			—			1,563		1,052			—			2,615
General and administrative	—			—			48,867		24,183			—			73,050
Depreciation, depletion and amortization	—			—			273,317		18,351			(8,886		)	282,782
Amortization of intangible assets	—			—			—		808			—			808
Other expense	—			—			17,256		2,109			—			19,365
Total operating expenses	—			—			672,971		66,376			(102,890		)	636,457

Operating income (loss)	—			—			50,734		127,542			(22,620		)	155,656
Interest expense	—			(47,790		)	3		(6,505		)	—			(54,292		)
Other income	—			97			219		137			—			453
Gain on derivative instruments	—			1,404			87,375		—			—			88,779
Loss on embedded derivatives	—			—			—		(15,417		)	—			(15,417		)
Amortization of deferred financing costs	—			(3,576		)	—		(2,502		)	—			(6,078		)
Equity income (loss) in affiliate	107,314			157,179			2		—			(264,495		)	—
Income before income taxes	107,314			107,314			138,333		103,255			(287,115		)	169,101
Income tax expense	(33,341		)	—			—		—			—			(33,341		)
Net income	73,973			107,314			138,333		103,255			(287,115		)	135,760
Less: Net income attributable to the noncontrolling interests	(16,841		)	—			—		(61,692		)	—			(78,533		)
Net income (loss) attributable to Rice Energy	57,132			107,314			138,333		41,563			(287,115		)	57,227
Less: Preferred dividends and accretion of redeemable noncontrolling interests	—			—			—		(28,988		)	—			(28,988		)
Net income (loss) attributable to Rice Energy Inc. common stockholders	$	57,132		$	107,314		$	138,333	$	12,575		$	(287,115	)	$	28,239

Condensed Consolidated Statement of Operations for the Six Months Ended June 30, 2016

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non- Guarantors			Eliminations			Consolidated
Operating revenues:
Natural gas, oil and NGL sales	$	—		$	—		$	234,754		$	—		$	—		$	234,754
Gathering, compression and water services	—			—			—			123,614			(75,334		)	48,280
Other revenue	—			—			12,906			—			—			12,906
Total operating revenues	—			—			247,660			123,614			(75,334		)	295,940

Operating expenses:
Lease operating	—			—			20,109			—			—			20,109
Gathering, compression and transportation	—			—			99,510			—			(44,209		)	55,301
Production taxes and impact fees	—			—			4,310			—			—			4,310
Impairment of fixed assets	—			—			—			2,595			—			2,595
Exploration	—			—			6,538			—			—			6,538
Midstream operation and maintenance	—			—			—			14,224			(47		)	14,177
Incentive unit expense	—			—			37,012			1,970			—			38,982
Acquisition expense	—			—			—			556			—			556
General and administrative	—			—			34,786			19,359			—			54,145
Depreciation, depletion and amortization	—			—			154,105			15,238			(5,406		)	163,937
Amortization of intangible assets	—			—			—			811			—			811
Other expense	—			—			15,499			149			—			15,648
Total operating expenses	—			—			371,869			54,902			(49,662		)	377,109

Operating (loss) income	—			—			(124,209		)	68,712			(25,672		)	(81,169		)
Interest expense	—			(45,616		)	(34		)	(3,673		)	—			(49,323		)
Other income	—			748			2,013			1			—			2,762
Gain on derivative instruments	—			(59,040		)	(72,336		)	—			—			(131,376		)
Amortization of deferred financing costs	—			(2,287		)	—			(882		)	—			(3,169		)
Equity (loss) income in affiliate	(174,761		)	(146,077		)	(3,029		)	—			323,867			—
(Loss) income before income taxes	(174,761		)	(252,272		)	(197,595		)	64,158			298,195			(262,275		)
Income tax benefit (expense)	—			77,511			89,278			(39,918		)	—			126,871
Net (loss) income	(174,761		)	(174,761		)	(108,317		)	24,240			298,195			(135,404		)
Less: Net income attributable to the noncontrolling interests	—			—			—			(38,870		)	—			(38,870		)
Net (loss) income attributable to Rice Energy	(174,761		)	(174,761		)	(108,317		)	(14,630		)	298,195			(174,274		)
Less: Preferred dividends and accretion of redeemable noncontrolling interests	—			—			—			(11,402		)	—			(11,402		)
Net (loss) income attributable to Rice Energy Inc. common stockholders	$	(174,761	)	$	(174,761	)	$	(108,317	)	$	(26,032	)	$	298,195		$	(185,676	)

Condensed Statement of Cash Flows for the Six Months Ended June 30, 2017

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non- Guarantors			Eliminations			Consolidated
Net cash (used in) provided by operating activities	$	(32,462	)	$	(48,401	)	$	315,987		$	122,833		$	(31,506	)	$	326,451

Capital expenditures for property and equipment	(2,246		)	—			(491,768		)	(181,818		)	31,506			(644,326		)
Acquisitions	—			—			—			(3,671		)	—			(3,671		)
Acquisition deposit	—			—			(18,033		)	—			—			(18,033		)
Investment in subsidiaries	26,862			(10,138		)	—			—			(16,724		)	—
Net cash provided by (used in) investing activities	24,616			(10,138		)	(509,801		)	(185,489		)	14,782			(666,030		)

Proceeds from borrowings	—			—			—			75,500			—			75,500
Repayments of debt obligations	(768		)	—			—			—			—			(768		)
Debt issuance costs	—			(1,359		)	—			(40		)	—			(1,399		)
Distributions to the Partnership’s public unitholders	—			(1,225		)	—			(38,977		)	—			(40,202		)
Tax distribution to Vantage Sellers	34,228			(34,228		)	—			—			—			—
Net cash contributions to Strike Force Midstream by Gulfport Midstream	—			—			—			21,815			—			21,815
Preferred dividends on Series B Units	—			—			—			(15,270		)	—			(15,270		)
Employee tax withholding for settlement of stock compensation award vestings	(8,600		)	—			—			—			—			(8,600		)
Contributions from parent	—			(26,862		)	10,138			—			16,724			—
Net cash provided by (used in) financing activities	24,860			(63,674		)	10,138			43,028			16,724			31,076

Increase (decrease) in cash	17,014			(122,213		)	(183,676		)	(19,628		)	—			(308,503		)
Cash, beginning of year	2,756			230,944			164,522			71,821			—			470,043
Cash, end of period	$	19,770		$	108,731		$	(19,154	)	$	52,193		$	—		$	161,540

Condensed Statement of Cash Flows for the Six Months Ended June 30, 2016

(in thousands)	Rice Energy Inc.			Rice Energy Operating LLC			Guarantors			Non- Guarantors			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	10,046		$	(14,481	)	$	158,472		$	79,934		$	(31,077	)	$	202,894

Capital expenditures for property and equipment	(15,254		)	—			(371,066		)	(129,286		)	31,077			(484,529		)
Capital expenditures for acquisitions	—			—			—			(7,744		)	—			(7,744		)
Investment in subsidiaries	55,566			70,047			—			—			(125,613		)	—
Net cash provided by (used in) investing activities	40,312			70,047			(371,066		)	(137,030		)	(94,536		)	(492,273		)

Proceeds from borrowings	—			—			—			120,000			—			120,000
Repayments of debt obligations	(690		)	—			—			(255,000		)	—			(255,690		)
Debt issuance costs	32			—			—			(701		)	—			(669		)
Distributions to the Partnership’s public unitholders	—			—			—			(17,636		)	—			(17,636		)
Shares of common stock issued in April 2016 offering, net of offering costs	311,764			—			—			—			—			311,764
RMP common units issued in the Partnership’s June 2016 offering, net of offering costs	—			—			—			164,150			—			164,150
Proceeds from conversion of warrants	100			—			—			—			—			100
Proceeds from issuance of redeemable noncontrolling interests, net of offering costs	—			—			—			368,767			—			368,767
RMP common units issued in the Partnership’s ATM program, net of offering costs	—			—			—			15,782			—			15,782
Preferred dividends on Series B Units	—			—			—			(3,576		)	—			(3,576		)
Contributions from parent	—			(55,566		)	224,627			(294,674		)	125,613			—
Net cash provided by financing activities	311,206			(55,566		)	224,627			97,112			125,613			702,992

Increase (decrease) in cash	361,564			—			12,033			40,016			—			413,613
Cash, beginning of year	78,474			2			57,798			15,627			—			151,901
Cash, end of period	$	440,038		$	2		$	69,831		$	55,643		$	—		$	565,514

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our 2016 Annual Report, as well as the condensed consolidated financial statements and related notes appearing elsewhere in this Quarterly Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included elsewhere in this Quarterly Report. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

Rice Energy is an independent natural gas and oil company focused on the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. We operate in three business segments, which are managed separately due to their distinct operational differences - the Exploration and Production segment, the Rice Midstream Holdings segment and the Rice Midstream Partners segment. The Exploration and Production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGLs. The Rice Midstream Holdings segment is engaged in the gathering and compression of natural gas, oil and NGL production for us and third parties in Belmont and Monroe Counties, Ohio. The Rice Midstream Partners segment is engaged in the gathering and compression of natural gas, oil and NGL production in Washington and Greene Counties, Pennsylvania, and in the provision of water services to support the well completion services of us and third parties in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio.

Proposed Merger with EQT Corporation

On June 19, 2017, we and EQT entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, subject to the satisfaction or waiver of certain conditions, an indirect, wholly-owned subsidiary of EQT will merge with and into us (the “Merger”), and immediately thereafter we will merge with and into another indirect, wholly-owned subsidiary of EQT (“LLC Sub”), with LLC Sub continuing as the surviving entity in such merger as an indirect, wholly-owned subsidiary of EQT.

On the terms and subject to the conditions set forth in the Merger Agreement, which has been unanimously approved by the respective boards of directors of us and EQT, at the effective time of the Merger, each share of our common stock issued and outstanding immediately before that time (other than shares of our common stock held by

EQT or certain of its direct and indirect subsidiaries, shares held by us in treasury or shares with respect to which appraisal has been properly demanded pursuant to Delaware law) will automatically be converted into the right to receive 0.37 shares of EQT common stock and $5.30 in cash. The consummation of the Merger is subject to approval by the shareholders of both us and EQT and certain customary regulatory and other closing conditions and is expected to close in the fourth quarter of 2017.

The Merger Agreement provides for certain termination rights for both us and EQT, including the right of either party to terminate the Merger Agreement if the Merger is not consummated by February 19, 2018 (which may be extended by either party to May 19, 2018 under certain circumstances). Upon termination of the Merger Agreement under certain specified circumstances, we may be required to pay EQT, or EQT may be required to pay us, a termination fee of $255.0 million. In addition, if the Merger Agreement is terminated because of a failure of a party’s shareholders to approve the proposals required to complete the Merger, that party may be required to reimburse the other party for its transaction expenses in an amount equal to $67.0 million.

Vantage Acquisition

Following completion of the Vantage Acquisition, we operate Vantage through Rice Energy Operating. As part of the consideration for the Vantage Acquisition, certain affiliates of Quantum Energy Partners, Riverstone Holdings LLC and Lime Rock Partners (such affiliates, the “Vantage Sellers”) were issued 1/1000th of a share of our preferred stock for each unit held in Rice Energy Operating. In connection with the issuance of such membership interests to the Vantage Sellers, we and the Vantage Sellers entered into Rice Energy Operating’s Third Amended and Restated Limited Liability Company Agreement (the “Third A&R LLC Agreement”). Under the Third A&R LLC Agreement, as the sole manager, we control all of the day-to-day business affairs and decision-making of Rice Energy Operating without approval of any other member, unless otherwise stated in the Third A&R LLC Agreement. As such, we, through our officers and directors, are responsible for all operational and administrative decisions of Rice Energy Operating and the day-to-day management of Rice Energy Operating’s business. Pursuant to the terms of the Third A&R LLC Agreement, we cannot, under any circumstances, be removed or replaced as the sole manager of Rice Energy Operating, except by our own election, so long as we remain a member of Rice Energy Operating. Provisions regarding the operations of Rice Energy Operating and the rights and obligations of the holders of Rice Energy Operating common units are set forth in the Third A&R LLC Agreement. As of June 30, 2017, we owned an 87.04% membership interest in Rice Energy Operating. The remaining 12.96% membership interest in Rice Energy Operating is owned by the Vantage Sellers and is reflected as noncontrolling interest in the consolidated financial statements.

Sources of Revenues

The following table provides detail of our operating revenues from the condensed consolidated statements of operations for the three and six months ended June 30, 2017 and 2016.

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2017		2016		2017		2016
Natural gas sales	$	345,085	$	121,312	$	697,047	$	232,866
Oil and NGL sales	3,807		1,000		8,679		1,888
Gathering, compression and water services	38,065		23,728		68,408		48,280
Other revenue	11,350		9,958		17,979		12,906
Total operating revenues	$	398,307	$	155,998	$	792,113	$	295,940

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
NYMEX Henry Hub High ($/MMBtu)	$	3.27		$	2.93		$	3.65		$	2.93
NYMEX Henry Hub Low ($/MMBtu)	$	2.83		$	1.71		$	2.44		$	1.64

NYMEX Henry Hub Price ($/MMBtu)	$	3.18		$	1.95		$	3.25		$	2.02
Less: Average Basis Impact ($/MMBtu)	(0.49		)	(0.27		)	(0.43		)	(0.31		)
Plus: Btu Uplift (MMBtu/Mcf)	0.14			0.09			0.14			0.08
Pre-Hedge Realized Price ($/Mcf)	$	2.83		$	1.77		$	2.96		$	1.79

Consolidated Results of Operations

Below are some highlights of our financial and operating results for the three and six months ended June 30, 2017 and 2016:

· Our natural gas, oil and NGL sales were $348.9 million and $122.3 million in the three months ended June 30, 2017 and 2016, respectively, and $705.7 million and $234.8 million in the six months ended June 30, 2017 and 2016, respectively.

· Our production volumes were 123.2 Bcfe and 68.9 Bcfe in the three months ended June 30, 2017 and 2016, respectively, and 237.7 Bcfe and 130.3 Bcfe in the six months ended June 30, 2017 and 2016, respectively.

· Our gathering, compression and water services revenues were $38.1 million and $23.7 million in the three months ended June 30, 2017 and 2016, respectively, and $68.4 million and $48.3 million in the six months ended June 30, 2017 and 2016, respectively.

· Our per unit cash production costs were $0.51 per Mcfe and $0.56 per Mcfe in the three months ended June 30, 2017 and 2016, respectively, and $0.55 per Mcfe and $0.60 per Mcfe in the six months ended June 30, 2017 and 2016, respectively.

The following tables set forth selected operating and financial data for the three and six months ended June 30, 2017 and 2016:

	Three Months Ended June 30,							Six Months Ended June 30,
	2017		2016		Change			2017		2016		Change
Natural gas sales (in thousands)	$	345,085	$	121,312	$	223,773		$	697,047	$	232,866	$	464,181
Oil and NGL sales (in thousands)	3,807		1,000		2,807			8,679		1,888		6,791
Natural gas, oil and NGL sales (in thousands)	$	348,892	$	122,312	$	226,580		$	705,726	$	234,754	$	470,972

Natural gas production (Bcf)	121.9		68.7		53.2			235.1		129.7		105.4
Oil and NGL production (MBbls)	207.9		40.7		167.2			430.9		96.8		334.1
Total production (Bcfe)	123.2		68.9		54.3			237.7		130.3		107.4

Average natural gas prices before effects of hedges per Mcf	$	2.83	$	1.77	$	1.06		$	2.96	$	1.79	$	1.17
Average realized natural gas prices after effects of hedges per Mcf (1)	2.68		2.75		(0.07		)	2.83		2.81		0.02
Average oil and NGL prices per Bbl:	18.31		24.56		(6.25		)	20.14		19.50		0.64

Average costs per Mcfe
Lease operating	$	0.14	$	0.13	$	0.01		$	0.17	$	0.15	$	0.02
Gathering, compression and transportation	0.32		0.39		(0.07		)	0.33		0.42		(0.09		)
Production taxes and impact fees	0.05		0.04		0.01			0.05		0.03		0.02
General and administrative	0.32		0.42		(0.10		)	0.31		0.42		(0.11		)
Depreciation, depletion and amortization	1.18		1.23		(0.05		)	1.19		1.26		(0.07		)

Total gathering, compression and water services revenues (in thousands):	$	38,065	$	23,728	$	14,337		$	68,408	$	48,280	$	20,128

Gathering volumes (MDth/d)	2,535		1,592		943			2,371		1,441		930
Compression volumes (MDth/d)	1,338		1,025		313			1,361		770		591
Water distribution volumes (MMgal)	424		335		89			789		797		(8		)

(1) The effect of hedges includes realized gains and losses on commodity derivative transactions.

(in thousands, except per	Three Months Ended June 30,									Six Months Ended June 30,
share data)	2017			2016			Change			2017			2016			Change
Operating revenues:
Natural gas, oil and NGL sales	$	348,892		$	122,312		$	226,580		$	705,726		$	234,754		$	470,972
Gathering, compression and water services	38,065			23,728			14,337			68,408			48,280			20,128
Other revenue	11,350			9,958			1,392			17,979			12,906			5,073
Total operating revenues	398,307			155,998			242,309			792,113			295,940			496,173

Operating expenses:
Lease operating	17,645			9,038			8,607			40,294			20,109			20,185
Gathering, compression and transportation	39,131			27,169			11,962			78,557			55,301			23,256
Production taxes and impact fees	6,679			2,659			4,020			12,832			4,310			8,522
Exploration	7,106			5,548			1,558			11,118			6,538			4,580
Midstream operation and maintenance	8,348			4,555			3,793			14,998			14,177			821
Incentive unit expense	4,800			14,840			(10,040		)	7,683			38,982			(31,299		)
Acquisition expense	2,408			84			2,324			2,615			556			2,059
Impairment of gas properties	—			—			—			92,355			—			92,355
Impairment of fixed assets	—			—			—			—			2,595			(2,595		)
General and administrative	39,226			29,272			9,954			73,050			54,145			18,905
Depreciation, depletion and amortization	145,904			84,752			61,152			282,782			163,937			118,845
Amortization of intangible assets	406			403			3			808			811			(3		)
Other expense	13,207			11,457			1,750			19,365			15,648			3,717
Total operating expenses	284,860			189,777			95,083			636,457			377,109			259,348

Operating income (loss)	113,447			(33,779		)	147,226			155,656			(81,169		)	236,825
Interest expense	(27,269		)	(24,802		)	(2,467		)	(54,292		)	(49,323		)	(4,969		)
Other income	273			2,549			(2,276		)	453			2,762			(2,309		)
Gain (loss) on derivative instruments	103,558			(201,555		)	305,113			88,779			(131,376		)	220,155
Loss on embedded derivatives	(15,417		)	—			(15,417		)	(15,417		)	—			(15,417		)
Amortization of deferred financing costs	(3,426		)	(1,618		)	(1,808		)	(6,078		)	(3,169		)	(2,909		)
Income (loss) before income taxes	171,166			(259,205		)	430,371			169,101			(262,275		)	431,376
Income tax (expense) benefit	(33,917		)	120,496			(154,413		)	(33,341		)	126,871			(160,212		)
Net income (loss)	137,249			(138,709		)	275,958			135,760			(135,404		)	271,164
Less: Net income attributable to noncontrolling interests	(53,724		)	(17,977		)	(35,747		)	(78,533		)	(38,870		)	(39,663		)
Net income (loss) attributable to Rice Energy Inc.	83,525			(156,686		)	240,211			57,227			(174,274		)	231,501
Less: Preferred dividends and accretion of redeemable noncontrolling interests	(20,656		)	(7,944		)	(12,712		)	(28,988		)	(11,402		)	(17,586		)
Net income (loss) attributable to Rice Energy Inc. common stockholders	$	62,869		$	(164,630	)	$	227,499		$	28,239		$	(185,676	)	$	213,915

Loss per share - basic	$	0.31		$	(1.07	)	1.38			$	0.14		$	(1.28	)	$	1.42
Loss per share - diluted	$	0.30		$	(1.07	)	1.37			$	0.14		$	(1.28	)	$	1.42

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016

Total operating revenues. The increase in total operating revenues was the result of a 77% increase in natural gas production from 68.7 Bcfe in the second quarter of 2016 compared to 121.9 Bcfe in the second quarter of 2017. During the three months ended June 30, 2017, we turned 30 gross (26 net) wells into sales, bringing our total producing well count to 431 gross (329 net). Also contributing to the increase in operating revenues was an increase in our period-over-period realized price. Our realized price for the three months ended June 30, 2017 was $2.83 per Mcf compared to $1.77 for the three months ended June 30, 2016, in each case before the effect of hedges. Operating revenues were also positively impacted by a 60% increase in gathering, compression and water services revenues period-over-period. In addition, post-acquisition revenue associated with the Vantage Acquisition was $106.0 million for the three months ended June 30, 2017.

Lease operating. The increase in lease operating expense from $9.0 million for the three months ended June 30, 2016 to $17.6 million for the three months ended June 30, 2017, or 95%, was primarily attributable to an increase in our production base period-over-period. In addition, lease operating expense per unit of production increased period-over-period from $0.13 for the three months ended June 30, 2016 to $0.14 for the three months ended June 30, 2017. The increase on a per unit basis was primarily attributable to the addition of producing wells in the Fort Worth Basin acquired from Vantage in the fourth quarter of 2016.

Gathering, compression and transportation. Gathering, compression and transportation expense for the second quarter of 2017 of $39.1 million was comprised of $30.0 million of transportation contracts with third parties and $9.1 million of gathering and compression charges from third parties. The 44% increase was primarily attributable to a 79% increase in production volumes for the three months ended June 30, 2017 compared to the three months ended June 30, 2016, which favorably impacted the gathering, compression and transportation rate.

Production taxes and impact fees. Production taxes are directly related to natural gas, oil and NGLs sales. The increase from $2.7 million for the three months ended June 30, 2016 to $6.7 million for the three months ended June 30, 2017, or 151%, was primarily due to a severance tax on gas produced by our Fort Worth Basin assets.

Midstream operation and maintenance. The increase in midstream operation and maintenance expense from $4.6 million for the three months ended June 30, 2016 to $8.3 million for the three months ended June 30, 2017, or 83%, primarily relates to additional operation and maintenance expense associated with midstream and water assets acquired in connection with the Vantage Acquisition that were not present in the prior year. In addition, the increase in operation and maintenance expense was due to an increase in variable water costs associated with the need for supplemental water systems to support combination hydraulic fracturing during the three months ended June 30, 2017, as well as an increase in pipeline maintenance expenses.

Incentive unit expense. Incentive unit expense decreased 68% period-over-period. In the second quarter of 2016, the $14.8 million expense consisted of $5.8 million of non-cash compensation expense related to the Rice Energy Holdings LLC (“Rice Holdings”) incentive units and $9.0 million of non-cash compensation expense related to the quarterly fair market value adjustment for the NGP Holdings incentive units. In the second quarter of 2017, the $4.8 million expense consisted of non-cash compensation expense related to the Rice Holdings incentive units. No future expense will be recognized related to the NGP Holdings incentive units as a result of the April 2016 settlement of the remaining NGP Holdings incentive unit obligation. See “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-12. Incentive Units” for additional information.

General and administrative. For the three months ended June 30, 2017, general and administrative expense increased approximately 34%, which was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. On a per unit basis, general and administrative expense decreased by 24%, from $0.42 per Mcfe during the three months ended June 30, 2016 to $0.32 per Mcfe during the

three months ended June 30, 2017, primarily due to a 79% increase in production. Included in general and administrative expense is stock compensation expense of $6.2 million and $6.1 million for the three months ended June 30, 2017 and 2016, respectively.

Depreciation, depletion and amortization expense (“DD&A”). The increase from $84.8 million for the three months ended June 30, 2016 to $145.9 million for the three months ended June 30, 2017, or 72%, was a result of a greater number of producing wells in the second quarter of 2017 compared to the second quarter of 2016. As of June 30, 2017, we had 431 gross (329 net) producing wells, a 39% increase when compared to the number of producing wells as of June 30, 2016. On a per unit basis, DD&A expense decreased $0.05 per Mcfe, or 4%, from $1.23 for the three months ended June 30, 2016 to $1.18 per Mcfe for the three months ended June 30, 2017 due primarily to well cost reductions and drilling and completion efficiencies that we have achieved during the period.

Interest expense. The increase from $24.8 million for the three months ended June 30, 2016 to $27.3 million for the three months ended June 30, 2017, or 10%, was a result of higher levels of average borrowings outstanding during the second quarter of 2017 as compared to the second quarter of 2016 in order to fund our capital programs.

Gain (loss) on derivative instruments. The $103.6 million gain on derivative contracts in the second quarter of 2017 is comprised of cash payments of $18.7 million on the settlement of maturing contracts and a $122.2 million unrealized gain in the second quarter of 2017. The $201.6 million loss on derivative contracts in the second quarter of 2016 was comprised of $67.4 million of cash receipts on the settlement of maturing contracts and a $268.9 million unrealized loss.

Loss on embedded derivatives. The $15.4 million loss on embedded derivatives in the second quarter of 2017 was related to our reassessment of the probability of a Change in Control under the LLC Agreement and the GP Holdings A&R LPA following our entry into the Merger Agreement and determination that the occurrence of a Change in Control was probable. As a result, we assessed certain embedded derivatives requiring bifurcation in the LLC Agreement and GP Holdings A&R LPA and determined that the value of the Investor Put Right increased as a result of the change in probability. As of June 30, 2017, the embedded derivative fair value of the Investor Put Right was approximately $15.4 million and is included as an embedded derivative liability in the accompanying condensed consolidated balance sheet. Please see “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-10. Mezzanine Equity” for further information.

Income tax (expense) benefit. The increase in income tax expense from an income tax benefit of $120.5 million for the three months ended June 30, 2016 to an income tax expense of $33.9 million for the three months ended June 30, 2017, or 128%, was primarily the result of an increase in net income before income taxes.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Total operating revenues. The $496.2 million, or 168% increase in total operating revenues period-over-period was mainly a result of an increase in natural gas production from 129.7 Bcfe for the six months ended June 30, 2016 to 235.1 Bcfe for the six months ended June 30, 2017. Also contributing to the increase in operating revenues was an increase in our period-over-period realized price. Our realized price for the six months ended June 30, 2017 was $2.96 per Mcf compared to $1.79 per Mcf for the six months ended June 30, 2016, in each case before the effect of hedges. Operating revenues were also positively impacted by a 42% increase in gathering, compression and water service revenues period-over-period. In addition, post-acquisition revenue associated with the Vantage Acquisition was $201.9 million for the six months ended June 30, 2017.

Lease operating. The $20.2 million, or 100% increase in lease operating expenses period-over-period was primarily attributable to an increase in our production base period-over-period. In addition, lease operating expense per unit of production increased period-over-period from $0.15 for the six months ended June 30, 2016 to $0.17 for the six months ended June 30, 2017. The increase on a per unit basis was primarily attributable to the addition of producing wells in the Fort Worth Basin acquired from Vantage in the fourth quarter of 2016.

Gathering, compression and transportation. Gathering, compression and transportation expense for the six months ended June 30, 2017 of $78.6 million is mainly comprised of $62.8 million of transportation contracts with

third parties and $15.8 million of gathering charges from third parties. The $23.3 million, or 42% increase was primarily attributable to an 82% increase in production volumes for the six months ended June 30, 2017 compared to the six months ended June 30, 2016, which favorably impacted the gathering, compression and transportation rate.

Production taxes and impact fees. Production taxes are directly related to natural gas, oil and NGLs sales. The $8.5 million, or 198%, increase in production taxes for the six months ended June 30, 2017 compared to the six months ended June 30, 2016 is primarily due to a severance tax on gas produced by our Fort Worth Basin assets.

Incentive unit expense. Incentive unit expense decreased 80% period-over-period. In the six months ended June 30, 2016, the $39.0 million expense consisted of $11.7 million of non-cash compensation expense related to the Rice Holdings incentive units and $27.3 million of compensation expense related to the final fair market value adjustment for the NGP Holdings incentive units. In the six months ended June 30, 2017, the $7.7 million expense consisted of of non-cash compensation expense related to the Rice Holdings incentive units. No future expense will be recognized related to the NGP Holdings incentive units as a result of the April 2016 settlement of the remaining NGP Holdings incentive unit obligation. See “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-12. Incentive Units” for additional information.

Impairment of gas properties. For the six months ended June 30, 2017, we recorded a $92.4 million impairment related to certain proved gas properties located in the Fort Worth Basin. As a result of significant declines in forward Waha basis differentials, which is the primary sales point for our Fort Worth Basin production, we performed an asset recoverability test and determined that the carrying value of our Fort Worth Basin proved properties exceeded its fair value. See “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-3. Impairment” for additional information.

General and administrative. For the six months ended June 30, 2017, general and administrative expense increased approximately 35%, which was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. On a per unit basis, general and administrative expense decreased by 26%, from $0.42 per Mcfe during the six months ended June 30, 2016 to $0.31 per Mcfe during the six months ended June 30, 2017, primarily due to a 82% increase in production. Included in general and administrative expense is stock compensation expense of $11.3 million and $10.8 million for the six months ended June 30, 2017 and 2016, respectively.

DD&A. The increase from $163.9 million for the six months ended June 30, 2016 to $282.8 million for the six months ended June 30, 2017, or 72%, was a result of a greater number of producing wells in the six months ended June 30, 2017 compared to the six months ended June 30, 2016. As of June 30, 2017, we had 431 gross (329 net) producing wells, a 39% increase when compared to the number of producing wells as of June 30, 2016. On a per unit basis, DD&A expense decreased 0.07 per Mcfe, or 6%, from $1.26 for the six months ended June 30, 2016 to 1.19 per Mcfe for the six months ended June 30, 2017 due primarily to well cost reductions and drilling and completion efficiencies that we have achieved during the period.

Interest expense. The increase from $49.3 million for the six months ended June 30, 2016 to $54.3 million for the six months ended June 30, 2017, or 10%, was a result of higher levels of average borrowings outstanding during the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 in order to fund our capital programs.

Gain (loss) on derivative instruments. The $88.8 million gain on derivative contracts in the six months ended June 30, 2017 is comprised of cash payments of $32.3 million on the settlement of maturing contracts and a $121.1 million unrealized gain in the six months ended June 30, 2017. The $131.4 million loss on derivative contracts in the six months ended June 30, 2016 was comprised of $131.5 million of cash receipts on the settlement of maturing contracts and a $262.8 million unrealized loss.

result of the change in probability. As of June 30, 2017, the embedded derivative fair value of the Investor Put Right was approximately $15.4 million and is included as an embedded derivative liability in the accompanying condensed consolidated balance sheet. Please see “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-10. Mezzanine Equity” for further information.

Income tax (expense) benefit. The increase in income tax expense from an income tax benefit of $126.9 million for the six months ended June 30, 2016 to an income tax expense of $33.3 million for the six months ended June 30, 2017, or 126%, was primarily the result of an increase in net income before income taxes.

Business Segment Results of Operations

We operate in three business segments: Exploration and Production, Rice Midstream Holdings and Rice Midstream Partners. We evaluate our business segments based on their contribution to our consolidated results based on operating income. Please see “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-8. Financial Information by Business Segment” for a reconciliation of the operating results and assets of our business segments.

The following tables set forth selected operating and financial data for each business segment during the three and six months ended June 30, 2017 compared to the three and six months ended June 30, 2016:

Exploration and Production Segment

(in thousands, except	Three Months Ended June 30,								Six Months Ended June 30,
volumes)	2017		2016			Change			2017		2016			Change
Operating revenues:
Natural gas, oil and NGL sales	$	348,892	$	122,312		$	226,580		$	705,726	$	234,754		$	470,972
Other revenue	11,350		9,958			1,392			17,979		12,906			5,073
Total operating revenues	360,242		132,270			227,972			723,705		247,660			476,045

Operating expenses:
Lease operating	17,740		9,038			8,702			40,389		20,108			20,281
Gathering, compression and transportation	85,915		51,307			34,608			167,810		99,510			68,300
Production taxes and impact fees	6,679		2,659			4,020			12,832		4,310			8,522
Exploration	7,106		5,548			1,558			11,118		6,538			4,580
Incentive unit expense	4,664		14,141			(9,477		)	7,464		37,012			(29,548		)
Acquisition costs	1,356		—			1,356			1,563		—			1,563
Impairment of gas properties	—		—			—			92,355		—			92,355
Impairment of fixed assets	—		—			—			—		2,595			(2,595		)
General and administrative	25,653		18,413			7,240			48,868		34,854			14,014
Depreciation, depletion and amortization	141,478		79,515			61,963			273,317		154,471			118,846
Other expense	11,210		11,097			113			17,255		15,500			1,755
Total operating expenses	301,801		191,718			110,083			672,971		374,898			298,073

Operating income (loss)	$	58,441	$	(59,448	)	$	117,889		$	50,734	$	(127,238	)	$	177,972

Operating volumes:
Natural gas production (Bcf):	121.9		68.7			53.2			235.1		129.7			105.4
Oil and NGL production (MBbls):	207.9		40.7			167.2			430.9		96.8			334.1
Total production (Bcfe)	123.2		68.9			54.3			237.7		130.3			107.4

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016

Natural gas, oil and NGL sales. The 185% increase in natural gas sales was the result of an increase in production in the second quarter of 2017 compared to the second quarter of 2016, as discussed above. During the three months ended June 30, 2017, we turned 30 gross (26 net) wells into sales, bringing our total producing well count to 431 gross (329 net). In addition to the impact of increased production volumes on operating revenues, our realized price increased from $1.77 per Mcf in the second quarter of 2016 to $2.83 per Mcf in the second quarter of 2017, in each case before the effect of hedges. In addition, post-acquisition revenue and production volumes associated with the Vantage Acquisition was $90.3 million and 32.5 Bcfe for the three months ended June 30, 2017, respectively.

Lease operating. The 95% increase in lease operating expense was primarily attributable to an increase in our production base period-over-period. In addition, lease operating expense per unit of production increased period-over-period from $0.13 for the three months ended June 30, 2016 to $0.14 for the three months ended June 30, 2017. The increase on a per unit basis was primarily attributable to the addition of producing wells in the Fort Worth Basin acquired from Vantage in the fourth quarter of 2016.

Gathering, compression and transportation. Gathering, compression and transportation expense of $85.9 million for the second quarter of 2017 includes approximately $53.9 million of affiliate and third-party gathering fees and $32.1 million of transportation contracts with third parties. The 67% increase in gathering, compression and transportation expenses was mainly due to increased volumes associated with the Rice Midstream Partners segment and the Rice Midstream Holdings segment in the second quarter of 2017 compared to the second quarter of 2016.

General and administrative. General and administrative expense increased from $18.4 million for the three months ended June 30, 2016 to $25.7 million for the three months ended June 30, 2017, an increase of 39%. The increase period-over-period was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. Included in general and administrative expense is stock compensation expense of $4.9 million and $3.2 million for the three months ended June 30, 2017 and 2016, respectively.

DD&A. DD&A expense increased from $79.5 million for the three months ended June 30, 2016 to $141.5 million for the three months ended June 30, 2017, an increase of 78%. The increase in segment DD&A was a result of an increase in production and greater number of producing wells in the second quarter of 2017 compared to the second quarter of 2016. As of June 30, 2017, we had 431 gross (329 net) producing Appalachian wells, a 39% increase when compared to the number of producing wells as of June 30, 2016.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Natural gas, oil and NGL sales. The 201% increase in natural gas sales was the result of an increase in production in the six months ended June 30, 2017 compared to the six months ended June 30, 2016, as discussed above. During the six months ended June 30, 2017, we turned 61 gross (55 net) wells into sales, bringing our total producing well count to 431 gross (329 net). In addition to the impact of increased production volumes on operating revenues, our realized price increased from $1.79 per Mcf in the six months ended June 30, 2016 to $2.96 per Mcf in the six months ended June 30, 2016, in each case before the effect of hedges. In addition, post-acquisition revenue and production volumes associated with the Vantage Acquisition was $174.1 million and 60.4 Bcfe for the three months ended June 30, 2017, respectively.

Lease operating. The 100% increase in lease operating expenses period-over-period was primarily attributable to an increase in our production base period-over-period. In addition, lease operating expense per unit of production increased period-over-period from $0.15 for the six months ended June 30, 2016 to $0.17 for the six months ended June 30, 2017. The increase on a per unit basis was primarily attributable to the addition of producing wells in the Fort Worth Basin acquired from Vantage in the fourth quarter of 2016.

Gathering, compression and transportation. Gathering, compression and transportation expense of $167.8 million for the six months ended June 30, 2017 includes approximately $100.6 million of affiliate and third-party gathering fees and $67.2 million of transportation contracts with third parties. The 69% increase in gathering, compression and transportation expenses was mainly due to increased volumes associated with the Rice Midstream Partners segment and the Rice Midstream Holdings segment in the six months ended June 30, 2017 compared to the six months ended June 30, 2016.

General and administrative. General and administrative expense increased from $34.9 million for the six months ended June 30, 2016 to $48.9 million for the six months ended June 30, 2017, an increase of 40%. The increase period-over-period was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. Included in general and administrative expense is stock compensation expense of $8.9 million and $5.8 million for the six months ended June 30, 2017 and 2016, respectively.

DD&A. DD&A expense increased from $154.5 million for the six months ended June 30, 2016 to $273.3 million for the six months ended June 30, 2017, an increase of 77%. The increase in segment DD&A was a result of

an increase in production and greater number of producing wells in the six months ended June 30, 2017 compared to the six months ended June 30, 2016. As of June 30, 2017, we had 431 gross (329 net) producing Appalachian wells, a 39% increase when compared to the number of producing wells as of June 30, 2016.

Rice Midstream Holdings Segment

(in thousands,	Three Months Ended June 30,							Six Months Ended June 30,
except volumes)	2017		2016		Change			2017		2016		Change
Operating revenues:
Gathering revenues	$	29,334	$	9,240	$	20,094		$	52,874	$	17,776	$	35,098
Compression revenues	2,613		2,633		(20		)	5,918		4,748		1,170
Total operating revenues	31,947		11,873		20,074			58,792		22,524		36,268

Operating expenses:
Midstream operation and maintenance	1,013		462		551			1,774		1,471		303
Incentive unit expense	136		699		(563		)	219		1,970		(1,751		)
General and administrative	6,375		5,071		1,304			11,145		8,827		2,318
Acquisition costs	556		84		472			556		484		72
Depreciation, depletion and amortization	1,790		1,556		234			3,187		2,645		542
Other expense	1,977		—		1,977			1,977		—		1,977
Total operating expenses	11,847		7,872		3,975			18,858		15,397		3,461

Operating income	$	20,100	$	4,001	$	16,099		$	39,934	$	7,127	$	32,807

Operating volumes:
Gathering volumes (MDth/d):	1,175		658		517			1,073		556		517
Compression volumes (MDth/d):	446		461		(15		)	502		412		90

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016

Total operating revenues. Operating revenues increased from $11.9 million for the three months ended June 30, 2016 to $31.9 million for the three months ended June 30, 2017, an increase of 169%. The increase in total operating revenues was mainly the result of an increase in affiliate gathering and compression volumes between the Exploration and Production segment and the Rice Midstream Holdings segment, as well as an increase in third-party gathering volumes.

Midstream operation and maintenance. Midstream operation and maintenance expense increased from $0.5 million for the three months ended June 30, 2016 to $1.0 million for the three months ended June 30, 2017, an increase of 119%. The increase in midstream operation and maintenance expense was primarily due to increased preventative maintenance expenses on compressor stations and the timing of other general maintenance during the three months ended June 30, 2017.

General and administrative. General and administrative expense increased from $5.1 million for the three months ended June 30, 2016 to $6.4 million for the three months ended June 30, 2017, an increase of 26%. The increase in general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support the Rice Midstream Holdings segment’s growth activities. Included in general and administrative expense is stock compensation expense of $1.2 million and $1.7 million for the second quarter of 2017 and 2016, respectively.

DD&A. DD&A expense increased from $1.6 million for the three months ended June 30, 2016 to $1.8 million for the three months ended June 30, 2017, an increase of 15%. The increase in DD&A was mainly the result of an increase in midstream assets placed in service subsequent to the second quarter of 2016 and the related depreciation on those assets.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Total operating revenues. Operating revenues increased from $22.5 million for the six months ended June 30, 2016 to $58.8 million for the six months ended June 30, 2017, an increase of 161%. The increase in total operating revenues was mainly the result of an increase in affiliate gathering and compression volumes between the Exploration and Production segment and the Rice Midstream Holdings segment, as well as an increase in third-party gathering volumes.

Midstream operation and maintenance. Midstream operation and maintenance expense increased from $1.5 million for the six months ended June 30, 2016 to $1.8 million for the six months ended June 30, 2017, an increase of 21%. The increase was primarily due to increased preventative maintenance expenses during the six months ended June 30, 2017.

General and administrative. General and administrative expense increased from $8.8 million for the six months ended June 30, 2016 to $11.1 million for the six months ended June 30, 2017, an increase of 26%. The increase in general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support the Rice Midstream Holdings segment’s growth activities. Included in general and administrative expense is stock compensation expense of $2.1 million and $2.9 million for the six months ended June 30, 2017 and 2016, respectively.

DD&A. DD&A expense increased from $2.6 million for the six months ended June 30, 2016 to $3.2 million for the six months ended June 30, 2017, an increase of 20%. The increase in DD&A was mainly the result of an increase in midstream assets placed in service subsequent to the second quarter of 2016 and the related depreciation on those assets.

Rice Midstream Partners Segment

(in thousands,	Three Months Ended June 30,							Six Months Ended June 30,
except volumes)	2017		2016		Change			2017		2016		Change
Operating revenues:
Gathering revenues	$	40,314	$	26,249	$	14,065		$	76,534	$	51,934	$	24,600
Compression revenues	6,270		3,787		2,483			12,052		4,902		7,150
Water services revenues	25,793		16,511		9,282			46,541		44,254		2,287
Total operating revenues	72,377		46,547		25,830			135,127		101,090		34,037

Operating expenses:
Midstream operation and maintenance	9,701		4,141		5,560			17,880		12,752		5,128
General and administrative	7,198		5,787		1,411			13,037		10,463		2,574
Depreciation, depletion and amortization	7,543		6,855		688			15,164		12,225		2,939
Acquisition costs	496		—		496			496		73		423
Amortization of intangible assets	406		403		3			808		811		(3		)
Other expense (income)	20		361		(341		)	133		149		(16		)
Total operating expenses	25,364		17,547		7,817			47,518		36,473		11,045

Operating income	$	47,013	$	29,000	$	18,013		$	87,609	$	64,617	$	22,992

Operating volumes:
Gathering volumes (MDth/d):	1,360		934		426			1,298		885		413
Compression volumes (MDth/d):	892		564		328			859		358		501
Water services volumes (MMgal):	424		335		89			789		797		(8		)

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016

Total operating revenues. Operating revenues increased from $46.5 million for the three months ended June 30, 2016 to $72.4 million for the three months ended June 30, 2017, an increase of 55%. The increase in operating revenues period-over-period primarily relates to increased gathering and compression revenues associated with a 46% and 58% increase in gathering and compression throughput, respectively. The increase in operating revenues also related to the impact of post-acquisition revenues associated with the Vantage Midstream Entities of $15.7 million for the three months ended June 30, 2017, which was comprised of gathering, compression and water distribution volumes of 377 MDth/d, 50 MDth/d and 63 MMgal, respectively. Additionally, the increase is attributable to a $9.3 million increase in water services revenue due to a 27% increase in fresh water distribution volumes of 335 MMgal for the three months ended June 30, 2016 to 424 MMgal for the three months ended June 30, 2017.

Operation and maintenance expense. Total operation and maintenance expense increased from $4.1 million for the three months ended June 30, 2016 to $9.7 million for the three months ended June 30, 2017, an increase of 134%. The increase period-over-period was primarily due to increases in line maintenance expenses, as well as increases in compressor rental charges associated with the addition of compressor stations acquired in connection

with the Vantage Midstream Acquisition. Additionally, the increase relates to an increase in variable water costs associated with supplemental water systems supporting combination fracing in Ohio.

General and administrative expense. General and administrative expense increased from $5.8 million for the three months ended June 30, 2016 to $7.2 million for the three months ended June 30, 2017, an increase of 24%. The increase in general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support our growing midstream operations in Pennsylvania.

DD&A. Depreciation expense increased from $6.9 million for the three months ended June 30, 2016 to $7.5 million for the three months ended June 30, 2017, an increase of 10%. The increase period-over-period was primarily due to additional assets placed into service subsequent to the second quarter of 2016 associated with our gathering, compression and water handling and treatment services. From June 30, 2016 through June 30, 2017, our gathering and water pipeline miles increased by 40% and 22%, respectively.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016

Total operating revenues. Operating revenues increased from $101.1 million for the six months ended June 30, 2016 to $135.1 million for the six months ended June 30, 2017, an increase of 34%. The increase in operating revenues period-over-period primarily relates to increased gathering and compression revenues associated with a 192% and 377% increase in gathering and compression throughput, respectively. The increase in operating revenues also related to the impact of post-acquisition revenues associated with the Vantage Midstream Entities of $27.8 million for the six months ended June 30, 2017, which was comprised of gathering, compression and water distribution volumes of 377 MDth/d, 50 MDth/d and 63 MMgal, respectively.

Operation and maintenance expense. Total operation and maintenance expense increased from $12.8 million for the six months ended June 30, 2016 to $17.9 million for the six months ended June 30, 2017, an increase of 40%. The increase period-over-period was primarily due to increases in line maintenance expenses as well as increases in compressor rental charges associated with the addition of compressor stations acquired in connection with the Vantage Midstream Entities. Additionally, the increase relates to an increase in variable water costs associated with the supplemental water systems supporting combination fracs in Ohio.

General and administrative expense. General and administrative expense increased from $10.5 million for the six months ended June 30, 2016 to $13.0 million for the six months ended June 30, 2017, an increase of 25%. The increase in general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support our growing midstream operations in Pennsylvania.

DD&A. Depreciation expense increased from $12.2 million for the six months ended June 30, 2016 to $15.2 million for the six months ended June 30, 2017, an increase of 24%. The increase period-over-period was primarily due to additional assets placed into service subsequent to the second quarter of 2016 associated with our gathering, compression and water handling and treatment services. From June 30, 2016 through June 30, 2017, our gathering and water pipeline miles increased by 40% and 22%, respectively.

Capital Resources and Liquidity

The members of Rice Energy Operating, including us, incur U.S. federal, state and local income taxes on their share of taxable income of Rice Energy Operating, if any. Under the Third A&R LLC Agreement, Rice Energy Operating is required to make cash tax distributions to its members, subsequent to the end of a given

calendar year, based upon income allocated to each member and subject to the availability of distributable cash (as defined in the Third A&R LLC Agreement).

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $326.5 million for the six months ended June 30, 2017, compared to $202.9 million for the six months ended June 30, 2016. The increase in operating cash flow was primarily due to an increase in production and commodity prices, partially offset by an increase in cash operating expenses.

Cash Flow Used in Investing Activities

During the six months ended June 30, 2017, cash flows used in investing activities was $666.0 million, which primarily consisted of capital expenditures for property and equipment of $644.3 million, as compared to $492.3 million for the six months ended June 30, 2016, of which $484.5 million was associated with capital expenditures for property and equipment.

Capital expenditures for the Exploration and Production segment totaled $494.0 million and $386.3 million for the six months ended June 30, 2017 and 2016, respectively. The increase was primarily attributable to the development of our natural gas properties.

Capital expenditures for the Rice Midstream Holdings segment totaled $123.8 million and $54.3 million for the six months ended June 30, 2017 and 2016, respectively. The increase was attributable to an increase in capital expenditures for Midstream Holding’s infrastructure, including capital expenditures for Strike Force Midstream’s midstream infrastructure.

Capital expenditures for the Rice Midstream Partners segment totaled $58.0 million and $75.0 million for the six months ended June 30, 2017 and 2016, respectively. The decrease was primarily attributable to a decrease in the capital expenditures related to the Rice Midstream Partners segment’s water services assets, offset by increases in capital expenditures for compression assets.

Cash Flow Provided by Financing Activities

Net cash provided by financing activities of $31.1 million during the six months ended June 30, 2017 was primarily the result of borrowings on our revolving credit facilities, partially offset by distributions to the Partnership’s public unitholders and payments of preferred dividends to redeemable noncontrolling interest holders. Net cash provided by financing activities of $703.0 million during the six months ended June 30, 2016 was primarily the result of the proceeds from the Midstream Holdings Investment (See “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-10. Mezzanine Equity” for additional information), proceeds from the April 2016 equity offering, proceeds from the Partnership’s June 2016 equity offering and proceeds from the Partnership’s ATM program, offset by net repayments on our revolving credit facilities and distributions to the Partnership’s public unitholders.

Debt Agreements

Senior Notes

On April 25, 2014, we issued $900.0 million in aggregate principal amount of 6.25% senior notes due 2022 (the “2022 Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds to us of $882.7 million after deducting estimated expenses and underwriting discounts and commissions of approximately $17.3 million.

The 2022 Notes will mature on May 1, 2022, and interest is payable on the 2022 Notes on each May 1 and November 1. Upon the occurrence of a Change of Control (as defined in the indenture governing the 2022 Notes),

unless we have given notice to redeem the 2022 Notes, the holders of the 2022 Notes will have the right to require us to repurchase all or a portion of the 2022 Notes at a price equal to 101% of the aggregate principal amount of the 2022 Notes, plus any accrued and unpaid interest to the date of purchase. We may redeem some or all of the 2022 Notes at redemption prices (expressed as percentages of principal amount) equal to 104.688% prior to May 1, 2018, 103.125% for the twelve-month period beginning May 1, 2018, 101.563% for the twelve-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020, plus accrued and unpaid interest to the redemption date.

On March 26, 2015, we issued $400.0 million in aggregate principal amount of 7.25% senior notes due 2023 (the “2023 Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds to us of $389.3 million after deducting estimated expenses and underwriting discounts and commissions of approximately $10.7 million. We used the net proceeds for general corporate purposes, including capital expenditures. The original issuance discount of $3.1 million related to the 2023 Notes is recorded as a reduction of the principal amount.

The 2023 Notes will mature on May 1, 2023, and interest is payable on the 2023 Notes on each May 1 and November 1. At any time prior to May 1, 2018, we may redeem up to 35% of the 2023 Notes at a redemption price of 107.250% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the 2023 Notes remains outstanding after such redemption. Prior to May 1, 2018, we may redeem some or all of the notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. Upon the occurrence of a change of control (as defined in the indenture governing the 2023 Notes), unless we have given notice to redeem the 2023 Notes, the holders of the 2023 Notes will have the right to require us to repurchase all or a portion of the 2023 Notes at a price equal to 101% of the aggregate principal amount of the 2023 Notes, plus any accrued and unpaid interest to the date of purchase. On or after May 1, 2018, we may redeem some or all of the 2023 Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438% for the twelve-month period beginning on May 1, 2018, 103.625% for the twelve-month period beginning May 1, 2019, 101.813% for the twelve-month period beginning on May 1, 2020 and 100.000% beginning on May 1, 2021, plus accrued and unpaid interest to the redemption date.

On October 19, 2016, we entered into supplemental indentures that provide for, among other things, the addition of Rice Energy Operating as a co-obligor under each indenture. The indentures governing the 2022 Notes and the 2023 Notes (collectively, the “Notes”) restrict our ability and the ability of certain of our subsidiaries to: (i) incur or guarantee additional debt or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated debt; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; (vii) transfer and sell assets; and (viii) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures governing the Notes) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

Senior Secured Revolving Credit Facility

In April 2013, we entered into a Senior Secured Revolving Credit Facility (the “Senior Secured Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders. In April 2014, we, as borrower, and Rice Drilling B, as predecessor borrower, amended and restated the credit agreement governing the Senior Secured Revolving Credit Facility to, among other things, assign all of the rights and obligations of Rice Drilling B as borrower under the Senior Secured Revolving Credit Facility to us.

In connection with the closing of the Vantage Acquisition, in October 2016, we entered into a Fourth Amended and Restated Credit Agreement (the “A&R Credit Agreement”), among us, Rice Energy Operating, Wells Fargo Bank, N.A., as administrative agent, and the lenders and other parties thereto. The A&R Credit Agreement provides, among other things, for the assignment of our rights and obligations as borrower under the Senior Secured Revolving Credit Facility to Rice Energy Operating and the addition of us as a guarantor of those obligations.

On June 15, 2017, Rice Energy Operating, as borrower, and we, as parent guarantor, entered into the Third Amendment to the A&R Credit Agreement. The lenders under the A&R Credit Agreement completed their semi-annual redetermination of the borrowing base. Following the redetermination, our borrowing base and aggregate elected commitment amounts each increased from $1.45 billion to $1.6 billion.

As of June 30, 2017, the borrowing base was $1.6 billion and the sublimit for letters of credit was $400.0 million. We had zero borrowings outstanding and $211.0 million in letters of credit outstanding under the A&R Credit Agreement as of June 30, 2017, resulting in availability of $1.4 billion. The maturity date of the Senior Secured Revolving Credit Facility is October 19, 2021. The next redetermination of the borrowing base is expected to occur in October 2017.

Midstream Holdings Revolving Credit Facility

On December 22, 2014, Midstream Holdings entered into a credit agreement (the “Midstream Holdings Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders establishing a revolving credit facility (the “Midstream Holdings Revolving Credit Facility”) with a maximum credit amount of $300.0 million and a sublimit for letters of credit of $25.0 million.

As of June 30, 2017, Midstream Holdings had $112.5 million of borrowings outstanding and no letters of credit under this facility, resulting in availability of $187.5 million. The year-to-date average daily outstanding balance of the Midstream Holdings Revolving Credit Facility was approximately $74.6 million, and interest was incurred on the facility at a weighted average interest rate of 3.2% through June 30, 2017. The Midstream Holdings Revolving Credit Facility is available to fund working capital requirements and capital expenditures and to purchase assets. The maturity date of the Midstream Holdings Revolving Credit Facility is December 22, 2019.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Midstream Holdings may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 225 to 300 basis points, depending on the leverage ratio then in effect. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 125 to 200 basis points, depending on the leverage ratio then in effect. Midstream Holdings also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

RMP Revolving Credit Facility

On December 22, 2014, Rice Midstream OpCo entered into a credit agreement (the “RMP Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders establishing a revolving credit facility (the “RMP Revolving Credit Facility”).

As of June 30, 2017, the revolving credit facility provided for lender commitments of $850.0 million, with an additional $200.0 million of commitments available under an accordion feature subject to lender approval. Rice Midstream OpCo had $206.0 million of borrowings outstanding and no letters of credit outstanding under the RMP Revolving Credit Facility as of June 30, 2017, resulting in availability of $644.0 million. The average daily outstanding balance of the RMP Revolving Credit Facility was approximately $194.0 million, and interest was incurred at a weighted average annual interest rate of 2.9% through June 30, 2017. The RMP Revolving Credit Facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes and matures on December 22, 2019. The Partnership and its restricted subsidiaries are the guarantors of the obligations under the RMP Revolving Credit Facility.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 200 to 300 basis points, depending on the leverage ratio then in effect, and base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the leverage ratio then in effect. Rice Midstream OpCo also pays a commitment fee based on the undrawn commitment amount ranging from 37.5 to 50 basis points.

Commodity Hedging Activities

To mitigate the potential negative impact on our cash flow caused by changes in oil and natural gas prices, we have entered into financial commodity derivative contracts in the form of swaps, zero cost collars, calls, puts and basis swaps to ensure that we receive minimum prices for a portion of our future oil and natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas. Pursuant to our A&R Credit Agreement, we are now permitted to hedge the greater of (i) the percentage of proved reserve volumes (Column A) or (ii) the percentage of internally forecasted production (Column B).

Months next succeeding the time as of which compliance is measured	Column A		Column B
Months 1 through 18	85	%	90	%
Months 19 through 36	85	%	75	%
Months 37 through 60	85	%	60	%
Months 61 through 72	85	%	40	%

Our hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and zero cost collars that set a floor and ceiling price for the hedged production. For a description of our commodity derivative contracts, please see “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-6. Derivative Instruments and 7. Fair Value of Financial Instruments” included elsewhere in this Quarterly Report. We do not designate our current portfolio of commodity derivative contracts as hedges for accounting purposes, and, as a result, changes in fair value of these derivative instruments are recognized in earnings. Please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of our and Rice Energy Operating’s commodity derivative contracts.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The application of our critical accounting policies may require management to make judgments and estimates about the amounts reflected in the condensed consolidated financial statements. Management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates. Our critical accounting policies are described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Policies and Estimates” in our 2016 Annual Report in addition to the discussion included herein. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to our condensed consolidated financial statements contained in this Quarterly Report.

On a quarterly basis, in accordance with ASC 360, we perform a qualitative assessment of whether events or changes in circumstances exist that could be indicators that the carrying amount of proved properties may not be recoverable. During the first quarter of 2017, we identified significant declines in forward Waha basis differentials, which is the primary sales point for our Fort Worth Basin production. The expected prolonged declines indicated a potential impairment trigger, and, as a result, we performed an asset recoverability test of our Fort Worth Basin properties. Based upon the results of the recoverability assessment, we concluded that the carrying value of the Fort Worth Basin properties exceeded the undiscounted cash flows. The fair value of the Fort Worth Basin proved properties was determined using a combination of the market and income approach to determine fair value. Significant inputs to the valuation of the discounted cash flows of natural gas and oil properties included 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 cost of capital rate. These inputs required significant judgments and estimates by management which included Level 3 unobservable inputs to the fair value measurement. The difference between the carrying value and fair value resulted in an asset impairment of $92.4 million within the Exploration and Production segment in the first quarter of 2017.

Off-Balance Sheet Arrangements

As of June 30, 2017, we did not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See “Item 1. Financial Statements-Notes to Condensed Consolidated Financial Statements-9. Commitments and Contingencies” for a description of our commitments and contingencies.

EX-99.3 7 a17-22068_2ex99d3.htm EX-99.3

Exhibit 99.3

Report of Independent Registered Public Accounting Firm

The Board of Managers and Members
Vantage Energy, LLC:

We have audited the accompanying consolidated balance sheets of Vantage Energy, LLC and subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vantage Energy, LLC and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

	/s/ KPMG LLP

Denver, Colorado
July 26, 2016

VANTAGE ENERGY, LLC

Consolidated Balance Sheets

December 31, 2015 and 2014

(In thousands)

	2015			2014
Assets
Current assets:
Cash and cash equivalents	$	2,191		$	20,479
Accounts receivable	21,989			24,437
Inventory	1,212			1,878
Prepayments and deposits	815			217
Commodity derivative assets	40,944			66,200
Total current assets	67,151			113,211
Property, plant, and equipment:
Oil and gas properties, full-cost method of accounting:
Proved	1,032,782			862,828
Unproved	74,619			58,640
Total oil and gas properties	1,107,401			921,468
Accumulated depletion and ceiling write-down	(634,082		)	(243,978		)
Net oil and gas properties	473,319			677,490
Gathering systems, less accumulated depreciation of $5,299 and $2,323	58,815			52,147
Other property, plant, and equipment, less accumulated depreciation of $1,948 and $1,731	772			428
Net property, plant, and equipment	532,906			730,065
Commodity derivative assets	15,679			5,468
Other assets	4,771			4,518
Water investment, less accumulated amortization of $11 and $0	662			—
Total assets	$	621,169		$	853,262

Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	40,937		$	45,656
Accounts payable—related party	1,100			12,524
Commodity derivative liabilities	—			1,183
Current portion of Second Lien note payable	2,000			2,000
Asset retirement obligations	—			12
Total current liabilities	44,037			61,375
Revolving credit facility	271,000			192,000
Second Lien note payable, net of original issue discount of $1,275 and $1,646	192,725			194,354
Asset retirement obligations	8,466			7,654
Total liabilities	516,228			455,383
Contingently redeemable Founders’ units	5,788			5,788
Commitments and contingencies (note 8)
Members’ equity:
Member contributions, net of issuance costs	428,227			428,227
Accumulated deficit	(329,074		)	(36,136		)
Total members’ equity	99,153			392,091
Total liabilities and members’ equity	$	621,169		$	853,262

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY, LLC

Consolidated Statements of Operations

Years ended December 31, 2015, 2014, and 2013

(In thousands)

	2015			2014		2013
Operating revenues:
Gas revenues	$	73,209		76,693		46,266
Oil revenues	3,053			9,438		5,152
NGLs revenues	8,313			13,833		6,599
Midstream revenues	5,679			1,995		99
Gain on commodity derivatives	69,569			66,615		8,074
Total operating revenues	159,823			168,574		66,190
Operating expenses:
Production and ad valorem tax expense	4,843			6,718		3,941
Marketing and gathering expense	5,352			7,262		2,640
Lease operating and workover expense	18,092			15,636		10,230
Midstream operating expense	1,834			892		325
General and administrative expense	6,019			8,838		3,698
Depreciation, depletion, amortization, and accretion expense	50,162			37,908		22,283
Impairment of oil and gas properties	344,401			—		—
Total operating expenses	430,703			77,254		43,117
Operating income (loss)	(270,880		)	91,320		23,073
Other expense:
Interest expense, net of capitalized interest	(22,058		)	(17,575	)	(417	)
Total other expense	(22,058		)	(17,575	)	(417	)
Net income (loss)	$	(292,938	)	73,745		22,656

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY, LLC

Consolidated Statements of Changes in Members’ Equity

Years ended December 31, 2015, 2014, and 2013

(In thousands)

	Contingently		Members’ Equity
	Redeemable Founders’ Units		Members’ Contributions		Accumulated Earnings (Deficit)			Total
Balance at January 1, 2013	$	5,788	$	428,178	$	(132,537	)	$	295,641
Members’ contributions, net	—		49		—			49
Net income	—		—		22,656			22,656
Balance at December 31, 2013	5,788		428,227		(109,881		)	318,346
Net income	—		—		73,745			73,745
Balance at December 31, 2014	5,788		428,227		(36,136		)	392,091
Net loss	—		—		(292,938		)	(292,938		)
Balance at December 31, 2015	$	5,788	$	428,227	$	(329,074	)	$	99,153

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY, LLC

Consolidated Statements of Cash Flows

Years ended December 31, 2015, 2014, and 2013

(In thousands)

	2015			2014		2013
Cash flows from operating activities:
Net income (loss)	$	(292,938	)	73,745		22,656
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	50,162			37,908		22,283
Accretion of original issue discount	371			354		—
Impairment of oil and gas properties	344,401			—		—
Gain on commodity derivatives	(69,569		)	(66,615	)	(8,074	)
Settlement of commodity derivatives	83,431			(204	)	4,465
Changes in operating assets and liabilities:
Accounts receivable	2,448			(10,911	)	(9,406	)
Accounts payable—related party	(11,424		)	3,231		9,600
Inventory	666			364		(412	)
Prepayments and deposits	(598		)	(67	)	(38	)
Accounts payable and accrued liabilities	3,860			7,758		2,907
Net cash provided by operating activities	110,810			45,563		43,981
Cash flows from investing activities:
Oil and gas property acquisition, exploration, and development	(189,835		)	(259,431	)	(102,128	)
Gathering system additions	(12,867		)	(33,969	)	(8,923	)
Water investment additions, net of surcharges refunded	(1,512		)	—		—
Other assets	—			(1,376	)	—
Proceeds on sale of properties	75			60		—
Other property, plant, and equipment additions	(560		)	(244	)	—
Net cash used in investing activities	(204,699		)	(294,960	)	(111,051	)
Cash flows from financing activities:
Borrowings under revolving credit facility	79,000			192,000		71,439
Principal payments on second lien note payable	(2,000		)	(2,000	)	(121,439	)
Borrowing under Second Lien, net of discount	—			—		198,000
Financing costs	(1,399		)	(335	)	(3,612	)
Member contributions, net	—			—		49
Net cash provided by financing activities	75,601			189,665		144,437
Net change in cash and cash equivalents	(18,288		)	(59,732	)	77,367
Cash and cash equivalents—beginning of year	20,479			80,211		2,844
Cash and cash equivalents—end of year	$	2,191		20,479		80,211
Supplemental disclosure of cash flow information:
Cash paid for interest	$	23,386		19,397		2,639
Supplemental disclosure of selected noncash accounts:
Accrued oil and gas capital additions	$	18,993		27,577		15,258
Capitalized asset retirement obligations, net	942			1,001		445

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY, LLC

Notes to Consolidated Financial Statements

December 31, 2015, 2014, and 2013

(1) Description of Business and Summary of Significant Accounting Policies

(a) Nature of Operations and Principles of Consolidation

Vantage Energy, LLC (the Company) was organized as a limited liability company under the laws of the state of Delaware in 2006. The consolidated financial statements include the accounts of Vantage Energy, LLC and its seven wholly owned subsidiaries. All intercompany balances have been eliminated in consolidation.

The Company is engaged in the exploration and exploitation of petroleum and natural gas, as well as natural gas acquisition, development, and gathering, in various basins in the United States of America, with the primary focus on unconventional natural gas plays.

(b) Use of Estimates

The preparation of these consolidated financial statements, in conformity with generally accepted accounting principles in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. As a result, actual amounts could differ from estimated amounts. By their nature, these estimates are subject to measurement uncertainty, and the effect on the consolidated financial statements of changes in such estimates in future periods could be significant. Significant estimates with regard to the Company’s consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows, the recoverability of unproved oil and gas properties, the calculation of depletion of oil and gas reserves, the estimated cost and timing related to asset retirement obligations, and the estimated fair value of derivative assets and liabilities.

Reserve estimates are, by their nature, inherently imprecise. The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for the various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

(c) Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company continually monitors its positions with, and the credit quality of, the financial institutions with which it invests. As of the balance sheet date, and throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits.

(d) Oil and Gas Properties

The Company follows the full-cost method of accounting for natural gas and crude oil properties. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. During the years ended December 31, 2015, 2014, and 2013, the Company capitalized approximately $5.3 million, $4.0 million, and $1.9 million, respectively, of certain internal costs.

Costs of acquiring unproved oil and gas properties are initially excluded from the depletable base and are assessed at each reporting period to ascertain whether impairment has occurred. When proved reserves are assigned to the property or the property is considered to be impaired, the costs of the property or the amount of impairment is added to the depletable base. Upon complete evaluation of a property, the total remaining excluded cost (net of any impairment) is included in the full cost amortization base.

Capitalized costs, as adjusted for estimated future development costs and estimated asset retirement costs, less estimated salvage values, are depreciated, depleted, and amortized using the units-of-production method based on estimated proved reserves as determined by petroleum engineers. The costs of wells in progress and unevaluated properties, including any related capitalized interest and internal costs, are not amortized. For the purposes of this calculation, crude oil and natural gas liquid reserves and production are converted to equivalent volumes of natural gas based on the relative energy content of one barrel to six thousand cubic feet of gas. Proceeds from the disposal of properties are

normally deducted from the full-cost pool without recognition of gains or losses, except under circumstances where the deduction would significantly alter the relationship between capitalized costs and proved reserves of the cost center, in which case a gain or loss is recorded.

Pursuant to full-cost accounting rules, the Company is required to perform a “ceiling test” calculation to test its oil and gas properties for possible impairment. If the net capitalized cost of the Company’s oil and gas properties subject to the amortization (the carrying value) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects. The present value of estimated future net revenue is computed by applying the average first day of the month oil and gas price for the preceding 12-month period to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves, assuming the continuation of existing economic conditions.

For the year ended December 31, 2015, the carrying value of the Company’s oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation by $344.4 million. As a result, the Company recorded an impairment of $344.4 million. No impairment was recognized in 2014 or 2013. The ceiling test calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over quarter prices in future quarters is a potentially lower ceiling value each quarter. This could result in ongoing impairments each quarter until prices stabilize or improve.

(e) Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2015, by the year in which such costs were incurred. Included in the $74.6 million of costs not subject to amortization are approximately $9.4 million that the Company deems significant related to its acquisition of properties from Tanglewood Exploration, LLC in the Marcellus Shale during 2012. The Company expects to evaluate and develop these Marcellus Shale properties over the next three to five years and to include the relevant costs in the amortization computation as such evaluation activities are completed.

	Costs Incurred
	Prior to 2013		During 2014	During 2015	Total
	(In thousands)
Acquisition Costs	$	7,779	30,860	11,666	50,305
Exploration and development costs	—		—	15,125	15,125
Capitalized Interest	101		3,389	5,699	9,189
Total	$	7,880	34,249	32,490	74,619

(f) Joint Ventures

Certain of the Company’s oil and gas exploration and development activities are conducted jointly with others; accordingly, the consolidated financial statements reflect only the Company’s proportionate interest in such activities.

(g) Inventory

The Company’s inventory primarily comprises tubular goods and well equipment to be used in future drilling operations. Inventory is charged to specific wells and transferred into oil and gas properties when used. There were no material inventory write-downs for the years ended December 31, 2015 and 2014.

(h) Gas Gathering System

The Company owns a 50% operated working interest in the assets of Vista Gathering, LLC (hereinafter referred to as Vantage Midstream). All gas transported in the gas gathering system relates to wells in which the Company and/or Vantage Energy II, LLC (Vantage II), an affiliate under common management, own a working interest and for which the Company or Vantage II serves as operator. Vantage Midstream owns and operates the majority of its gas gathering assets. Vantage Midstream also owns a 38% nonoperated interest in the Appalachia Midstream Services joint venture for its Rogersville gas gathering system.

The Company’s gas gathering assets are being depreciated on the straight-line method over a 20-year useful life. For the years ended December 31, 2015, 2014, and 2013, the Company recognized depreciation expense on its gas gathering system assets of approximately $3.0 million, $1.6 million, and $0.7 million, respectively. Maintenance and repairs are charged to expense as incurred. Expenditures that extend the useful lives of assets are capitalized. When assets are retired or otherwise disposed of, the cost of the assets and the related accumulated depreciation are removed from the accounts. Any gain or loss on retirements is reflected in other income in the year in which the asset is disposed.

The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Company performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived asset and if the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to the asset’s fair value and an impairment loss is recorded against the long-lived asset. There have been no provisions for impairment recorded for the years ended December 31, 2015, 2014 and 2013.

(i) Water Investment

Vantage Midstream entered into a 10-year agreement for Water System Expansion and Supply with Southwestern Pennsylvania Water Authority (SPWA) on July 30, 2015. The purpose of the agreement is to fund and assist SPWA in constructing an expansion to its water supply system; grant the Company preferred rights to water volumes for use in its oil and gas operations; and create a repayment structure for the Company through a surcharge applicable to all oil and gas water users. The proposed water system improvements to be funded by the Company are estimated to be $14.7 million; however, the Company may terminate the agreement without penalty. The surcharge in the amount of $3.50 per 1,000 gallons of water sold to oil and gas users from the system is collected by SPWA and remitted to Vantage Midstream. The costs incurred by us are capitalized and are being amortized on a straight line basis over the life of the agreement. Payments to the Company from SPWA derived from surcharges paid to SPWA by third parties are applied as a recovery of capital investment for funds advanced by Vantage Midstream to expand the system, while payments to Vantage Midstream from SPWA derived from surcharges from the Company are recorded as an offset to Vantage Midstream’s cost of water.

The Company entered into a Water Service and Supply Agreement with Vantage Midstream effective May 1, 2015. Under the agreement Vantage Midstream will provide services required by the Company, including the supply of water for injection and related collection, recycling, purifying, and the disposal of water after use. Vantage Midstream is responsible for the sourcing and transportation of water as requested by the Company. Vantage Midstream will also collect, clean, recycle, transport, and/or dispose of produced water and flowback water resulting from the Company’s operations. The Company’s 50% undivided working interest in the profits of the water business are eliminated against the full cost pool upon consolidation.

(j) Deferred Financing Costs

Costs associated with obtaining debt financing are deferred and amortized over the term of the debt. These costs, net of amortization, are included in other assets.

(k) Asset Retirement Obligations

Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted as part of the full-cost pool or depreciated as part of the gathering system. Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

(l) Commodity Derivatives

The Company periodically uses derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price and interest rate risk. The Company records all derivative instruments at fair value within the accompanying consolidated balance sheets. Changes in fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. Management has decided not to use hedge accounting under the accounting guidance for its derivatives; therefore, the changes in fair value are recognized in earnings. The Company classifies cash payments and receipts on its derivative instruments in operating cash flows in the accompanying consolidated statements of cash flows.

(m) Revenue Recognition

Crude oil, natural gas, and natural gas liquid (NGLs) revenue is recognized when delivery has occurred, title has transferred, and collection is probable.

The Company accounts for oil and natural gas sales using the “entitlements method”. Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. The Company sells the majority of its products soon after production at various locations, including the wellhead, at which time title and risk of loss pass to the purchaser. At December 31, 2015 and 2014, the Company did not have any material gas imbalances.

The Company’s gas gathering revenue is generated from gas gathering and compressing natural gas in Pennsylvania. The Company provides gas gathering services and compression services under fee-based arrangements.

(n) Concentrations of Credit Risk

The Company grants credit in the normal course of business to oil and gas purchasers in the United States of America. Collectability of the Company’s oil and gas sales is dependent upon the financial wherewithal of the Company’s purchasers, as well as general economic conditions of the industry. To date, the Company has not had any bad debts.

Approximately, 27%, 21%, and 9% of the Company’s accounts receivable as of December 31, 2015 were due from Chesapeake Energy, Asset Risk Management (ARM), and South Jersey, respectively. Approximately, 27%, 19%, and 14% of the Company’s accounts receivable as of December 31, 2014 were due from ETC Marketing, Bayshore Energy, and Chesapeake Energy, respectively.

Approximately, 41%, 21%, 20%, and 11%, of the Company’s oil and gas revenue for the year ended December 31, 2015 was generated from ARM, Targa Resources, ETC Marketing, and Chesapeake Energy, respectively. Approximately, 28%, 24%, 16%, and 13% of the Company’s oil and gas revenue for the year ended December 31, 2014 was generated from Sequent Energy, Targa Resources, ETC Marketing, and Chesapeake Energy, respectively. Approximately, 32% and 22% of the Company’s oil and gas revenues for the year ended December 31, 2013 was generated from ETC Marketing and Sequent Energy, respectively.

Although a substantial portion of production is purchased by these major customers, the Company does not believe the loss of any one or several customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.

(o) Marketing and Gathering Costs

In Texas, the Company sells at the wellhead and receives payment net of gathering expenses. In the Lake Arlington area (Tarrant County), the Company’s volumes are gathered by Summit under a long-term agreement and marketed by ETC Marketing, Ltd. The gathering fee is $0.67/mmbtu plus 3.2% for compression and fuel. In the Rosedale area (Tarrant County), volumes are gathered by Crestwood under a long-term agreement and marketed by ARM Energy Management. The current gathering fee is $0.3l/mmbtu with approximately $0.20/mmbtu for compression, and 1.5% for fuel. In the Southcliff area (Tarrant County), volumes are gathered by Access under a long-term agreement and marketed by ARM Energy Management. The current gathering fee is $0.57/mmbtu with a 2.0% fuel charge. The price received from these contracts is Waha index related.

The Company has multiple gathering and processing agreements for volumes produced in Denton County, Texas and Wise County, Texas. These agreements are with Targa, Devon, and EnLink. The average deduct from Waha for residue gas is approximately $0.40/mmbtu. The average deduct from Mt. Belvieu for NGLs is approximately $5.10/barrel. Field condensate is gathered and marketed by Enterprise under short-term agreement and generally receives a price of WTI less $5.00/bbl.

In Pennsylvania, Vantage Midstream gathers all gas, excluding the Appalachia Midstream Services joint venture area. Vantage Midstream gathering fees are $0.26/mmbtu for initial wells and $0.50/mmbtu for subsequent wells, with a sliding scale downward to $0.25/mmbtu based on cumulative system throughput.

(p) Impact Fees

The state of Pennsylvania imposes an impact fee on oil and gas production based on a formula applied to individual wells. The Company classifies the impact fees within production and ad valorem taxes on the accompanying consolidated statements of operations for the years ended December 31, 2015, 2014, and 2013.

(q) Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with projects that are not subject to current depletion. Interest is capitalized for the period that activities are in progress to bring these projects to their intended use. For the years ended December 31, 2015, 2014, and 2013, the Company capitalized interest costs to unproved properties of $1.6 million, $1.5 million, and $2.8 million, respectively.

(r) Income Taxes

The Company is a multi-member limited liability company. Accordingly, no provision for income taxes has been recorded as the income, deductions, expenses, and credits of the Company are reported on the income tax returns of the Company’s Members. The Company is subject to the Texas margin tax, which is generally calculated as 1% of gross margin. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenue and expenses. During the years ended December 31, 2015, 2014, and 2013, the margin tax was immaterial to the consolidated financial statements.

The Company accounts for uncertainty in income taxes in accordance with generally accepted accounting principles, which prescribe a comprehensive model for recognizing, measuring, presenting, and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision on whether or not to file in a particular jurisdiction. Only tax positions that meet a more-likely than-not recognition threshold at the effective date may be recognized or continue to be recognized.

Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. No interest or penalties have been assessed as of December 31, 2015. The Company’s information returns for tax years subject to examination by tax authorities include 2010 through the current year for state and federal tax reporting purposes.

(s) New Accounting Pronouncements

The FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, in May 2014. ASU 2014-09 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. An entity should also disclose sufficient quantitative and qualitative information to enable users of financial statements to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new standard is effective for annual reporting periods beginning after December 15, 2017. The Company will implement the provisions of ASU 2014-09 as of January 1, 2018. The Company has not yet determined the impact of the new standard on its current policies for revenue recognition.

The FASB issued ASU No 2016-02, Leases, in February 2016. ASU 2016-02 will require lessees to present right-of-use assets and lease liabilities on their balance sheets. ASU 2016-02 is effective for annual and interim periods beginning January 1, 2019. Early adoption of ASU 2016-02 is permitted. Upon adoption of ASU 2016-02, we are required to recognize and measure leases at the beginning of the earliest period presented in our consolidated financial statements using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that we may elect to apply. We have not yet decided when we will adopt ASU 2016-02 or which practical expedient options we will elect. We are currently evaluating and assessing the impact ASU 2016-02 will have on us and our financial statements. As of the date of this report, we cannot provide any estimate of the impact of adopting ASU 2016-02.

The FASB issued ASU 2015-03, Interest Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs, in April 2015. The core principle of ASU 2015-03 will require all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of debt, consistent with debt discounts. Upon adoption of ASU 2015-03, the new standard is limited to the presentation of debt issuance costs. The standard does not affect the recognition and measurement of debt issuance costs. In August 2015, the FASB issued ASU 2015-15, Interest—Imputations of Interest, Subtopic 835-30, Interest (ASU 2015-15). The guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. ASU 2015-15 was issued to clarify that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. The amendments in ASU 2015-03 should be applied on a retrospective basis and early adoption is permitted. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. The Company does not believe the impact of the new standard on its presentation of debt issuance costs will have a material effect on the Company’s financial statements and related disclosures.

(2) Balance Sheet Disclosures

Accounts receivable consist of the following:

	December 31
	2015			2014
	(In thousands)
Revenue	$	14,128		20,074
Joint interest billings	5,021			4,663
Derivative receivable	1,056			—
Other receivables	2,284			—
Allowance for doubtful accounts	(500		)	(300	)
	$	21,989		24,437

Joint interest billings represent receivables from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover nonpayment of joint interest billings.

Accounts payable and accrued liabilities consist of the following:

	December 31
	2015		2014
	(In thousands)
Accrued capital expenditures	$	18,993	27,577
Accrued production and ad valorem taxes	3,127		6,359
Accrued revenue payable	6,978		5,750
Accrued production expense payable	2,264		1,969
Accrued marketing, gathering, and transportation	5,646		2,378
Accrued general and administrative expense	1,854		1,060
Cash calls payable to other joint interest owners	437		101
Accrued interest payable	171		274
Accounts payable	1,467		188
	$	40,937	45,656

(3) Long-Term Debt

(a) Revolving Credit Facility

Effective July 19, 2007, the Company secured a credit facility with a group of bank lenders. Wells Fargo Bank, N.A. acts as administrative agent. Effective December 20, 2013, the Company amended and restated its credit facility (the Revolving Credit Facility) to adjust the borrowing base, increase the maximum commitment to $750 million, and allow for the Second Lien note payable (see below). The maturity date of the Revolving Credit Facility is January 1, 2017. As of December 31, 2015 and 2014, the Company had a borrowing base of $276 million and $250 million, respectively. As of December 31, 2015 and 2014, the Company had outstanding borrowings of $271 million and $192 million, respectively. On each borrowing, the Company has the election to pay interest at a Base rate or Eurodollar LIBOR. The margin on Base rate loans ranges from 0.75% to 1.75%. The margin on LIBOR loans ranges from 1.75% to 2.75%. The Company pays quarterly commitment fees ranging from 0.375% to 0.500% of the unused borrowing base. The Company generally elects to pay interest based on LIBOR, plus the applicable margin, which was 3.18% in total as of December 31, 2015.

As of December 31, 2015, the Revolving Credit Facility was collateralized by all of the Company’s assets, including its 50% operated interest in the Vantage Midstream assets.

The Revolving Credit Facility contains certain financial covenants, including maintenance of a minimum current ratio, a minimum interest coverage ratio, and a minimum asset coverage ratio. As of December 31, 2015, the Company was not in compliance with the minimum current ratio covenant under the Revolving Credit Facility. On May 10, 2016, the Company entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement (Fifth Amendment), which included among other things, an equity cure right, applied retroactively to December 31, 2015, applicable to the Company’s covenants under its credit agreement. The Company executed a $20 million capital call from its current equity owners during the first quarter of 2016, and such equity was included in the calculation of the current ratio covenant as of December 31, 2015, and, as a result, the Company was in compliance with all of its financial covenants as of December 31, 2015.

(b) Second Lien Term Loan

In December 2013, the Company entered into a Second Lien note payable (Second Lien note payable) with a face amount of $200 million, maturing on December 20, 2018. The Company has the election to pay interest at a Base rate or Eurodollar LIBOR. The margin on Base rate loans is 6.50%. The margin on LIBOR loans is 7.50%. LIBOR has a floor of 1.00%. As of December 31, 2015, the stated interest rate was 8.50%, and approximately $196 million was outstanding. The Second Lien note payable contains an optional prepayment provision that enables the Company to prepay the Second Lien note payable at par. The Second Lien note payable was issued with an original issue discount of $2.0 million, which has been classified as a reduction to the note balance. The discount is amortized over the term of the note using the effective interest method. The Second Lien note payable requires quarterly principal payments of $500,000, which commenced March 31, 2014.

As of December 31, 2015, the Second Lien note payable was collateralized by a second lien interest in all of the Company’s assets, including its 50% operated interest in the Vantage Midstream assets, and contains certain financial covenants. These covenants include maintenance of a minimum asset coverage ratio. As of December 31, 2015 and 2014, the Company was in compliance with this financial covenant.

The Company recognized gross interest expense of approximately $23.7 million, $19.1 million, and $3.2 million during the years ended December 31, 2015, 2014, and 2013, respectively.

Maturities of long-term debt as of December 31, 2015 (including current maturities, excluding unamortized debt discounts) are as follows (in thousands):

	Revolving Credit Facility		Second Lien
Year ending December 31,
2016	$	—	2,000
2017	271,000		2,000
2018	—		192,000
Total future maturities of long-term debt	$	271,000	196,000

(4) Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations

The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014, by level, within the fair value hierarchy (in thousands):

	December 31, 2015
	Fair value measurements
Description	Level 1		Level 2	Level 3	Total
Assets:
Commodity derivative instruments	$	—	56,623	—	56,623
Liabilities:
Commodity derivative instruments	$	—	—	—	—

	December 31, 2014
	Fair value measurements
Description	Level 1		Level 2	Level 3	Total
Assets:
Commodity derivative instruments	$	—	71,668	—	71,668
Liabilities:
Commodity derivative instruments	$	—	1,183	—	1,183

The Company’s commodity derivative instruments consist of variable-to-fixed price swaps. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires a variety of inputs, including contractual terms, published forward prices, and discount rates as appropriate. The Company’s estimates of fair value of commodity derivative instruments include consideration of the counterparties’ creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparties on the Company’s derivative instruments are the same financial institutions that hold the Revolving Credit Facility. Accordingly, the Company is not required to post collateral on these derivatives since the banks are secured by the Company’s oil and gas assets.

Non-Recurring Fair Value Measurements

The Company uses the income valuation technique using a discounted cash flow model to estimate the initial fair value of asset retirement obligations using estimated gross well costs of reclamation in amounts ranging from $10,000 to $100,000, timing of expected future dismantlement costs ranging from 1 year to 28 years, and a weighted average credit-adjusted risk-free rate. Accordingly, the fair value is based on unobservable pricing inputs and, therefore, is included within the Level 3 fair value hierarchy. During the years ended December 31, 2015 and 2014, the Company recorded liabilities for asset retirement obligations of $0.6 million and $1.7 million, respectively. See note 5 for additional information.

Other Financial Instruments

Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and long-term debt. With the exception of long-term debt, the financial statement carrying amounts of these items approximate their fair values due to their short-term nature.

(5) Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of oil and gas properties and gathering system.

	December 31
	2015			2014
	(In thousands)
Beginning of year	$	7,666		6,156
Liabilities incurred	635			1,719
Accretion expense	105			295
Asset dispositions	(247		)	(417	)
Revisions to estimate	307			(87	)
End of year	8,466			7,666
Less current portion	—			(12	)
Noncurrent portion	$	8,466		7,654

(6) Commodity Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices. The Company is focused on maintaining an active hedging program using commodity derivative financial instruments to achieve a more predictable cash flow by reducing its exposure to commodity price fluctuations and regional basis differential exposure in an effort to protect its capital investment program, as well as expected future cash flows. The Company’s risk management activity is generally accomplished through over-the-counter commodity derivative contracts with large financial institutions. The Company currently uses fixed price natural gas swaps for which it receives a fixed swap price for future production in exchange for a payment of the variable market price received at the time future production is sold.

While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenue from favorable price changes. The Company has adopted fair value accounting for its derivatives; therefore, changes in the fair value of derivative financial instruments are recognized in earnings. Cash payments or receipts on such contracts are included in cash flows from operating activities in our consolidated statements of cash flows.

At December 31, 2015, the terms of outstanding commodity derivative contracts were as follows:

Commodity	Quantity remaining	Prices	Price index	Contract period	Estimated fair value
					(In thousands)
Crude oil swaps (Bbls)	31,116	$44.91 - $47.00	NYMEX WTI	1/16 - 12/16	$	131
Natural gas swaps (MMBtu):
Dominion	39,845,100	$1.64 - $3.13	Dominion South Point	1/16 - 12/19	25,744
WAHA	47,206,700	$2.36 - $3.88	WAHA	1/16 - 12/19	28,760
NYMEX Henry Hub	—	—	NYMEX Henry Hub	—	—
Total	87,051,800				54,504
NGLs Swaps (Gal):
Ethane	18,241,296	$0.18 - $0.20	OPIS MB Ethane	1/16 - 12/17	478
Propane	—	—	OPIS MB Propane	—	—
TetPropane	6,969,564	$0.40 - $0.62	OPIS MB TetPropane	1/16 - 12/17	790
IsoButane	2,197,082	$0.52 - $0.76	OPIS MB IsoButane	1/16 - 12/17	226
Normal butane	997,078	$0.52 - $0.75	OPIS MB NButane	1/16 - 12/17	112
Natural gasoline	2,318,566	$0.83 - $1.22	OPIS MB Nat Gasoline	1/16 - 12/17	382
Total	30,723,586				1,988
			Total commodity derivatives		$	56,623

The Company estimates that 2016 hedged volumes, in aggregate, represent approximately 78% of the Company’s estimated proved production for 2016, based upon the year-end external reserve report.

Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.

The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and by counterparty. The Company enters into derivatives under a master netting arrangement with two counterparties, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparties.

The following tables provide reconciliation between the net assets and liabilities reflected in the accompanying consolidated balance sheets and the potential effects of master netting arrangements on the gross fair value of the derivative contracts:

		December 31, 2015
		Gross amounts
	Consolidated balance sheet classification	Gross recognized		Offset		Net recognized
		(In thousands)
Derivative assets:
Commodity contracts	Current assets	$	41,242	(298	)	40,944
Commodity contracts	Noncurrent assets	15,872		(193	)	15,679
Total derivative assets		$	57,114	(491	)	56,623
Derivative liabilities:
Commodity contracts	Current liabilities	$	298	(298	)	—
Commodity contracts	Noncurrent liabilities	193		(193	)	—
Total derivative liabilities		$	491	(491	)	—

		December 31, 2014
		Gross amounts
	Consolidated balance sheet classification	Gross recognized		Offset		Net recognized
		(In thousands)
Derivative assets:
Commodity contracts	Current assets	$	66,586	(386	)	66,200
Commodity contracts	Noncurrent assets	5,653		(185	)	5,468
Total derivative assets		$	72,239	(571	)	71,668
Derivative liabilities:
Commodity contracts	Current liabilities	$	1,569	(386	)	1,183
Commodity contracts	Noncurrent liabilities	185		(185	)	—
Total derivative liabilities		$	1,754	(571	)	1,183

The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments. These realized and unrealized gains and losses are recorded in the accompanying consolidated statements of operations.

	Location of gain (loss)	Year ended December 31,
	recognized in earnings	2015			2014		2013
		(In thousands)
Commodity derivative instruments:
Realized (loss) gains on derivatives	Operating revenue	$	83,431		(204	)	4,465
Unrealized (loss) gain on commodity derivatives, net	Operating revenue	(13,862		)	66,819		3,609
Total realized and unrealized gains recorded, net		$	69,569		66,615		8,074

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s commodity derivative instruments are subject to large fluctuations from period to period.

(7) Related Party Transactions

(a) Gas Gathering System Operating Agreement

In connection with the Joint Development Agreement between the Company and Vantage II, Vantage Midstream became the operator of the gas gathering assets. Pursuant to a Gas Gathering System Operating Agreement, dated August 2, 2012, between the Company and Vantage Midstream, the Company and Vantage II are to pay their respective 50% shares of the gas gathering system’s operating and development costs, as well as their incurred gas gathering and compression fees. The Company was charged gas gathering and compression fees by Vantage Midstream of $5.4 million, $3.0 million, and $2.0 million for the years ended December 31, 2015, 2014, and 2013, respectively.

(b) Water Investment

Pursuant to the Water Services and Supply Agreement, Vantage Midstream provides water services required in the Company’s drilling operations. The Company paid fees to Vantage Midstream of $4.5 million for the year ended December 31, 2015. No such fees were paid in 2014 or 2013.

(c) Management Services Agreement

In August 2012, the Company and Vantage II entered into a Management Services Agreement (MSA) whereby the Company is to provide certain executive management, administrative, accounting, finance, engineering, land, and information technology assistance to Vantage II. In exchange for receiving these services, Vantage II will pay the Company a fee (the MSA Fee). Through June 2014, the MSA Fee was calculated as 50% of the overall gross general and administrative expenses incurred by the Company. Starting in July 2014, the MSA Fee was allocated based upon the gross general and administrative expenses incurred by the Company multiplied by a ratio of the relative capital expenditures and oil and natural gas production volumes of the Company and Vantage II. Certain adjustments are made to this calculation to reflect the allocation of general and administrative expenses to Vantage Midstream. The Company billed general and administrative expenses under the MSA to Vantage II of approximately $12.0 million, $8.7 million, and $8.3 million for the years ended December 31, 2015, 2014, and 2013, respectively.

(d) MIU Notes Receivable

In December 2014, the Company made loans to certain employees in the form of notes receivable. Interest accrues on the notes at 0.34% per annum, and the notes mature upon the earlier to occur of: 1) December 1, 2017; 2) consummation of Monetization Event (as defined); or 3) fifteen days after the date of voluntary termination of employment by the employee or termination by the Company for cause. As of December 31, 2015, the notes had a balance of $1.4 million and are classified in other assets in the accompanying consolidated balance sheets. The notes are collateralized by a first lien interest in each employees’ Management Incentive Units (MIUs) and all potential dividends and distributions and a second lien on all other personal assets. Interest income was deemed de minimus for the year ended December 31, 2015.

(e) Derivative Novations

In January 2014, the Company entered into an agreement to transfer certain derivative contracts to Vantage II, as approved by Wells Fargo Bank, N.A. The Company determined the total fair value of the derivative contracts on the date of transfer to be approximately $(0.3) million.

In November 2013, the Company entered into an agreement to sell certain derivative contracts to Vantage II, as approved by Wells Fargo Bank, N.A. The Company determined the total fair value of the derivative contracts on the date of transfer to be approximately $1.7 million.

(8) Commitments and Contingencies

The Company leases office spaces in Colorado, Pennsylvania, and Texas under noncancelable operating leases that expire in 2017 and 2016, respectively. Rent expense for the years ended December 31, 2015 and 2014 was $0.4 million and $0.3 million, respectively. Future minimum lease payments under these leases are approximately $0.7 million for the period from November 2015 to June 2017, of which a portion will be allocated between the Company and Vantage II.

On August 22, 2008, the Company secured a letter of credit in the amount of $0.1 million with Wells Fargo Bank, N.A. in connection with the signing of an exploration agreement. Partial draws under this letter of credit are permitted. As of December 31, 2015, no amounts have been drawn under the letter of credit.

As part of a Founder’s employment agreement, the Company will pay $0.5 million to such Founder provided all of the following conditions have been met:

i. The Company’s invested capital equals $250 million or greater

ii. Monetization events aggregating at least $500 million in proceeds have been completed

iii. Distributions to Capital Interest Members are sufficient, in part, to exceed the Second Threshold, as defined in the LLC Agreement.

As of December 31, 2015, none of the $0.5 million has been accrued, as fulfillment of the above criteria has not been deemed probable.

Effective August 1, 2010, and amended in October 2014, the Company entered into a gas gathering agreement related to its Lake Arlington project in Tarrant County, Texas, which committed the Company to transport a minimum quantity of natural gas for seven years starting on the date gas is first delivered. If the Company transports more than the minimum quantity, the Company will receive a credit for excess transported gas, calculated as actual quantity transported, less minimum transportation quantity, multiplied by a stated dollar amount per MMBtu. This credit can be used to offset shortfalls incurred, if any, in the year immediately before or after the excess quantity was incurred. As of December 31, 2015, remaining total minimum revenue commitments due over the term of the agreement aggregate to $14.8 million The portion of the remaining minimum commitment that is due in 2016 totals $0.6 million as of December 31, 2015, subject to a rollover provision in the agreement that permits the Company to roll a portion of any deficit commitment to the subsequent period.

Effective August 1, 2013, the Company entered into a gas gathering agreement related to its Wedgwood project in Tarrant County, Texas, under which the Company is required to make a minimum revenue commitment of $8.8 million over four years starting on the date gas is first delivered. The gas gathering fee on which the minimum revenue commitment is based is $0.55 per MMBtu, and remains at that level under the agreement until the Company sells 20,000,000 MMBtu from its Wedgewood project, at which time the gas gathering fee reduces to $0.34 per MMBtu for all subsequent volumes. As of December 31, 2015, the Company had a remaining total commitment of $4.4 million The portion of the remaining minimum revenue commitment that is due in 2016 totals $0.3 million as of December 31, 2015, subject to a rollover provision in the agreement that permits the Company to roll a portion of any deficit obligations to the subsequent period.

On April 17, 2014, the Company entered into a 20,000 MMBtu/d firm marketing agreement to market a portion of our production associated with volumes produced in the Marcellus Shale. The agreement began in October 2014 and continues through October 2020. Under the contract, the Company is paid based on TETCO M-2 pricing with the ability to share in downstream price upside when market conditions allow.

On May 9, 2014, the Company entered in a 37,500 MMBtu/d firm marketing agreement to market a portion of our production associated with volumes produced in the Marcellus Shale. The agreement began in November 2014 and continues through October 2019. Under the contract, the Company is paid based on TETCO M-2 pricing.

As of December 31, 2015, the Company, as a counterparty along with Vantage II, had contracts with certain rig operators and pipe suppliers totaling approximately $2.3 million of commitments for 2015.

From time to time, the Company is party to litigation. The Company maintains insurance to cover certain actions and believes that resolution of such litigation will not have a material adverse effect on the Company.

(9) Capital Structure

Summarized below are the four classes of interests that have been authorized:

a) Capital Interests (excluding interests acquired under the Leveraged Investment Program)

b) Class A Management Incentive Units

c) Class B Management Incentive Units

d) Class C Management Incentive Units.

Effective July 1, 2010, the Members approved the Fourth Amendment to the Company’s Limited Liability Company Agreement (the Fourth Amendment) creating the Class C Management Incentive Units. The Company offered each holder of Class A Management Incentive Units and Class B Management Incentive Units, who was employed by the Company on July 1, 2010, the opportunity to exchange all of such Units held by such holders for new Class C Management Incentive Units. In addition, the Fourth Amendment provided for the return of $1.4 million of capital contributions to certain Members to maintain consistent capital commitment contribution percentages among all Members. Effective August 1, 2012, the Members entered into a Second Amended and Restated Limited Liability Company Agreement (the Agreement).

(a) Capital Interests

Capital Interests are issued to Members from time to time, in exchange for a Member’s capital commitment to make cash contributions when called by the Company pursuant to the terms as described in the Agreement.

Total capital contributions and deemed commitments associated with outstanding Capital Interests are as follows:

	December 31
	2015		2014
	(In thousands)
Institutional investors (deemed commitment—$470,559)	$	420,940	420,940
Founders (deemed commitment—$6,281)	5,788		5,788
Other employees (deemed commitment—$2,169)	2,055		2,055
Friends and family (deemed commitment—$6,225)	5,568		5,568
Total (total deemed commitment—$485,234)	$	434,351	434,351

As of December 31, 2015 and 2014, the Company had undrawn commitments of $50.9 million Member contributions on the consolidated balance sheets are net of equity issuance costs of approximately $0.4 million and $0.3 million as of December 31, 2015 and 2014, respectively.

Members are entitled to preferred distributions in an amount equal to 8% per annum. As it relates to Class C Management Incentive Units, preferred distributions are compounded annually beginning on July 1, 2010 on the sum of $135 million plus any capital contributions made by Members subsequent to July 1, 2010. Preferred distributions are paid only if distributable cash, as defined in the Agreement, is available. As of December 31, 2015 and 2014, accumulated but undeclared and unpaid preferred distributions related to the Class C Management Incentive Units approximated $124.4 million and $94.2 million, respectively.

The amount of accumulated preferred distributions is also used to determine the size of any payments that may be made to holders of Management Incentive Units. With respect to calculating payments, if any, to holders of the Class C Management Incentive Units, the actual amount of accumulated but undeclared preferred distributions with respect to the Capital Interests as described in the preceding paragraph is determinative. For purposes of calculating payments, if any, to holders of the Class A Management Incentive Units who did not exchange their Class A Management Incentive Units for new Class C Management Incentive Units, preferred distributions are accrued from the dates that capital contributions were made to the calculation date and are based on the full amount of all such capital contributions. As of December 31, 2015 and 2014, accumulated but undeclared and unpaid preferred distributions related to the Class A Management Incentive Units approximated $282.6 million and $229.5 million, respectively.

Decisions of the Company are approved by the majority of the Company’s board of managers. As of December 31, 2015, the Company’s board of managers comprised seven managers, including five appointed by the Institutional Investors, and the two Founders. The Founders may elect to appoint an additional independent manager.

The Company has the right, but not the obligation, to repurchase all Capital Interests and vested Management Incentive Units of employee Members, who are terminated for any reason, at the Units’ estimated fair value under the conditions provided for in the Agreement, except that this right does not exist with respect to the death or disability of any Founder. If an employee Member is terminated for cause, his or her Management Incentive Units, whether vested or unvested, will be forfeited, and his or her Capital Interests may be repurchased for the lesser of the aggregate unreturned capital contributions of such Member or fair market value. Upon termination of employment without cause or due to death or disability, the Founders/heirs may put their Capital Interests to the Company at fair market value. The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

Distributions of funds associated with Capital Interests defined above follow a prescribed framework, which is outlined in detail in the Agreement. In general, distributions are first made to those Members who have made capital contributions until such Members receive the sum of $135 million plus any additional capital contributions made subsequent to July 1, 2010 plus an 8% per annum return from July 1, 2010, as described above. Subsequent distributions are then allocated 85% to the holders of Capital Interests in accordance with specified sharing ratios and 15% to the holders of Management Incentive Units. The 15% incentive pool is allocated based on the number of Class C Management Incentive Units, taking into consideration payments made to holders of any remaining Class A Management Incentive Units that have not been exchanged for Class C Management Incentive Units. In addition, depending on amounts due from or to participants in the Leveraged Investment Program, certain distributions may be made to or by such participants upon a monetization event.

The Capital Interests are illiquid and subject to substantial transfer restrictions and have certain drag-along and tag-along rights as provided with the agreement.

Upon termination of employment without cause or due to death or disability, the Founders/heirs may put their Class I Units to the Company at fair market value. Upon the occurrence of death or disability, the exercise of this put right is at the discretion of the Founders/heirs, which is an event outside of the Company’s control. Under the standard codified within ASC 480, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” and Emerging Issues Tax Force (“EITF”) Topic D-98, stock subject to redemption requirements outside the control of the Company are required to be classified outside of permanent equity. Accordingly, the Founders’ equity is classified outside of members’ equity. The occurrence of these events is not deemed probable, and therefore, the Founders equity has been measured at historic cost. The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

(b) Leveraged Investment Program

Between December 18, 2006 and June 19, 2009, and at the time of employment for employees first employed between June 16, 2008 and June 17, 2009, the Company was authorized to issue to employees who are also Capital Interest Members up to $15 million of Leveraged Amounts. The Leveraged Amounts are limited recourse notes, collateralized by both the Capital Interests acquired independently of the Leveraged Investment Program amounts and the Capital Interests acquired through the Leveraged Investment Program amounts, but otherwise nonrecourse to the Capital Interest Members. The participants have significant capital at risk outside the Leveraged Amounts and therefore no compensation is derived from these notes. The notes mature only upon the occurrence of a sale of the Company.

In connection with the Fourth Amendment, participants in the Leveraged Investment Program who were current employees were given the opportunity to surrender and relinquish their right to participate in the remaining undrawn portion of the Leveraged Investment Program, which represented 41.5% of such participants’ allocated Leveraged Amounts under the Leveraged Investment Program. As of December 31, 2010, participants had surrendered the right to participate in $1.6 million aggregate Leveraged Amounts under the Plan.

The terms of the notes issued under the Leveraged Investment Program provide for interest to accrue at 5.0% per annum. As the interest due to the Company on these notes will be withheld out of future distributions, interest income will be recognized at the time such distributions are paid. As of December 31, 2015 and 2014, interest income accumulated, but not recognized, approximated $2.4 million and $2.0 million, respectively. The total Leverage Investment Capital since inception through December 31, 2015 is $5.3 million.

(10) Management Incentive Units

The Company has issued management incentive units to certain employees. The management incentive units participate only in distributions in liquidation events, meeting requisite financial thresholds after Capital Interests have recovered their investment and special allocation amounts. Management incentive units have no voting rights. Compensation expense for these awards will be recognized when all performance, market, and service conditions are probable of being satisfied (in general, upon a liquidating event). Accordingly, no value was assigned to the interests when issued.

Upon termination of employment upon death or disability, the Founders/heirs may put their management incentive units to the Company at fair market value. The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for a cause.

(a) Class A Management Incentive Units

The Management Incentive Plan, as described in the Agreement, authorizes up to 1,000,000 nonvoting, Class A Management Incentive Units. In connection with the Fourth Amendment, holders of Class A Management Incentive Units who were employed by the Company on July 1, 2010 were offered the opportunity to exchange their Class A Management Incentive Units for newly issued Class C Management Incentive Units. No new Class A Management Incentive Units may be issued following the Fourth Amendment. As of December 31, 2015 and 2014, 109,171 and 110,171, Class A Management Incentive Units were outstanding, respectively. For financial reporting purposes, no related compensation expense has been recorded as of and for the years ended December 31, 2015 and 2014.

Prior to the Fourth Amendment, certain Class A Management Incentive Units vest on a schedule of 20% at the end of each of the first four years following the date of grant, with the final 20% vesting only upon the occurrence of a sale of the Company. Other Class A Management Incentive Units vest 100% upon the occurrence of a sale of the Company. As of December 31, 2015 and 2014, 109,171 and 110,171 Class A Management Incentive Units were vested and outstanding, respectively.

(b) Class B Management Incentive Units

The Management Incentive Plan, as described in the Agreement, authorizes up to 45 Class B Management Incentive Units. In connection with the Fourth Amendment, holders of Class B Management Incentive Units were offered the opportunity to exchange their Class B Management Incentive Units for newly issued Class C Management Incentive Units. No new Class B Management Incentive Units may be issued following the Fourth Amendment. All holders of Class B Management Incentive Units accepted such offer; thus, at December 31, 2015 and 2014, there were no Class B Management Incentive Units outstanding.

(c) Class C Management Incentive Units

The 2010 Management Incentive Plan, as described in the Fourth Amendment, authorizes up to 1,818,182 nonvoting, Class C Management Incentive Units. In connection with the Fourth Amendment, holders of Class A Management Incentive Units and Class B Management Incentive Units who were employed by the Company on July 1, 2010 were offered the opportunity to exchange their Class A Management Incentive Units and Class B Management Incentive Units for newly issued Class C Management Incentive Units. Holders of 564,182 Class A Management Incentive Units exchanged such Units for 564,182 Class C Management Incentive Units, and holders of all of the 45 outstanding Class B Units exchanged such Units for 894,195 Class C Management Incentive Units. As of December 31, 2015 and 2014, 1,630,604 and 1,698,479 Class C Management Incentive Units were outstanding, respectively.

The Class C Management Incentive Units vest on a schedule of 15% if the holder has been employed by the Company on a full-time basis for each of three, four, and five years beginning on the date of grant, with the final 55% to vest only upon the occurrence of a sale of the Company, provided that the Company gives employees up to two full years’ credit against the vesting schedule for employment prior to the date of grant. In addition, there is accelerated vesting for each Founder of up to 50% of the Class C Management Units held by such Founder if his employment is terminated by the Company without cause. As of December 31, 2015 and 2014, 715,909 and 675,322 Class C Management Incentive Units, respectively, were vested.

The following table presents the activity for Class C Management Incentive Units outstanding:

	Units
Outstanding—December 31, 2013	1,751,479
Granted	—
Forfeited	(53,000	)
Outstanding—December 31, 2014	1,698,479
Granted	24,500
Forfeited	(92,375	)
Outstanding—December 31, 2015	1,630,604

(11) Employee Retirement Savings Plan

The Company sponsors a qualified tax-deferred savings plan (Retirement Savings Plan) for its employees in accordance with the provisions of Section 401(k) of the Internal Revenue Code. Employees may defer up to 80% of their compensation, subject to certain limitations. Effective May 1, 2007, the Company’s matching percentage is up to 6% of eligible employee compensation. For the years ended December 31, 2015, 2014, and 2013, expenses associated with the Company’s contributions to the Retirement Saving Plan totaled approximately $0.5 million, $0.4 million, and $0.1 million, respectively. The Company matches all employee contributions in cash.

(12) Liquidity

The Revolving Credit Facility matures on January 1, 2017. The Company expects to repay and retire the Revolving Credit Facility and the Second Lien note payable in connection with the net proceeds from the completion of the public offering and cash on hand. Additionally, the Company plans to obtain new financing following the anticipated corporate reorganization, contemporaneous with the offering.

In the event that some deficiency exists between the proceeds of the offering or the terms of the new facility and the Company’s current facility, as of December 31, 2015 the Company has available undrawn capacity under its existing borrowing base of $5 million and available undrawn capacity under its equity commitments of $51 million to address such a deficiency. In addition, the Company expects that it will be able to secure incremental equity commitments and other sources of capital, including debt, if necessary, from its current equity investors, other investors or lenders to address any shortfall.

The Company’s current equity investors continue to be supportive of the Company’s long-term growth and financing strategy.

While we anticipate engaging in active dialogue with our creditors and the potential public offering, at this time we are unable to predict the outcome of such or whether any such efforts to raise additional equity will be successful.

(13) Supplemental Information on Oil and Gas Producing Activities (unaudited)

The following is supplemental information regarding our consolidated oil and gas producing activities. The amounts shown include out net working and royalty interest in all our oil and gas properties.

(a) Capitalized Costs Relating to Oil and Gas Producing Activities

	December 31,
	2015			2014		2013
	(In thousands)
Proved properties	$	1,032,782		862,828		615,993
Unproved properties	74,619			58,640		35,107
	1,107,401			921,468		651,100
Accumulated depreciation and depletion	(634,082		)	(243,978	)	(208,906	)
Net capitalized costs	$	473,319		677,490		442,194

(b) Costs incurred in Certain Oil and Gas Activities

	December 31,
	2015		2014	2013
	(In thousands)
Acquisitions:
Unproved properties	$	770	8,072	26,407
Proved properties	—		129	3,622
Development costs	179,123		257,500	53,534
Exploration costs	—		—	21,232
Oil and gas expenditures	$	179,893	265,701	104,795

(c) Results of Operations for Oil and Gas Producing Activities

	December 31,
	2015			2014	2013
Revenues	$	84,575		99,964	58,017
Production costs	28,287			29,616	16,811
Depletion and accretion	45,808			35,368	21,318
Impairment of proved oil and gas properties	344,401			—	—
Results of operations from producing activities	(333,921		)	34,980	19,888
Depletion and accretion rate per Mcfe	$	0.99		1.25	1.33

(d) Oil and Gas Reserve Information

Proved reserve quantities are based on estimates prepared by the independent petroleum engineering firms of Netherland, Sewell & Associates, Inc. and Wright & Company for the years ended December 31, 2015, 2014, and 2013 in accordance with guidelines established by the Securities and Exchange Commission (the “SEC”).

Reserve definitions comply with definitions of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. The reserve quantity information is limited to reserves which had been evaluated as of December 31, 2015, 2014, and 2013. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves (“PUD”) are expected to be recovered from new wells after substantial development costs are incurred. All of the Company’s proved reserves are located in the Unites States.

Proved reserves are those quantities of oil, NGLs and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that the renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonable certain that it will commence the project within a reasonable time.

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process.

The following table provides a rollforward of the total proved reserves for the years ended December 31, 2015, 2014, and 2013, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

	Natural Gas (MMcf)		NGL (MBbl)		Oil (MBbl)		Total (MMcfe)
*Proved developed and undeveloped reserves as of:*
January 1, 2013	457,156		14,581		818		549,550
Revisions	18,922		(1,362	)	349		12,844
Extensions and discoveries	135,664		1,356		143		144,658
Divestitures	(1,125	)	(140	)	(13	)	(2,043	)
Acquisitions	16,317		1,281		111		24,669
Production	(14,246	)	(240	)	(54	)	(16,010	)
December 31, 2013	612,688		15,476		1,354		713,668
Revisions of previous estimates	(4,600	)	(616	)	(575	)	(11,746	)
Extensions and discoveries	166,158		4,033		204		191,580
Divestitures	(43	)	(5	)	—		(73	)
Acquisitions	39,839		4,560		275		68,849
Production	(24,242	)	(563	)	(108	)	(28,268	)
December 31, 2014	789,800		22,885		1,150		934,010
Revisions of previous estimates	(16,585	)	1,704		134		(5,557	)
Extensions and discoveries	136,658		—		—		136,658
Divestitures	(9	)	(1	)	—		(15	)
Acquisitions	33,429		—		—		33,429
Production	(41,175	)	(796	)	(74	)	(46,395	)
December 31, 2015	902,118		23,792		1,210		1,052,130
*Proved developed reserves as of:*
January 1, 2013	77,796		2,757		121		95,064
December 31, 2013	106,779		3,029		175		126,003
December 31, 2014	228,613		6,476		240		268,909
December 31, 2015	398,378		8,185		323		449,426
*Proved undeveloped reserves as of:*
January 1, 2013	379,359		11,824		697		454,485
December 31, 2013	505,909		12,447		1,179		587,665
December 31, 2014	561,187		16,409		910		665,101
December 31, 2015	503,740		15,607		887		602,704

Total proved reserves increased 118,120 MMcfe in 2015 primarily due to the following:

Revisions of previous estimates. Reserves were revised upward primarily attributable to technical revisions associated with PUD inventory performance after conversion to PDP as well as the base PDP reserves being revised.

Extensions and discoveries. Reserves increased primarily attributable to increased technical certainty in areas of existing leasehold ownership, tied to internal and external development activity, additional extensions tied to successful regulatory efforts in urban leasehold areas of Tarrant County, Texas and an improved regulatory environment in Denton County, Texas.

Acquisitions. Proved reserves increased due to new leasehold acquisition from third parties allowing for higher certainty in inventory development.

Total proved reserves increased 220,342 MMCFe in 2014 primarily due to the following:

Extensions and discoveries. Reserves increased primarily attributable to increased technical certainty in areas of existing leasehold ownership, tied to internal and external development activity, additional extension tied to development and conversion from non-proven inventory to PDP reserves in the year ended December 31, 2014, successful regulatory efforts in urban leasehold areas of Tarrant County, Texas and successful efforts in joint venture activities.

Acquisitions. Proved reserves increased due to new leasehold acquisition from third parties allowing for higher certainty in inventory development and successful acreage earning agreement with third party operators.

Total proved reserves increased 164,118 MMCFe in 2013 primarily due to the following:

Extensions and discoveries. Reserves were revised upward primarily attributable to increased technical certainty in areas of leasehold ownership, tied to internal and external development activity in the Fort Worth and Appalachian Basins.

Acquisitions. Proved reserves increased due to new leasehold acquisition from third parties allowing for higher certainty in inventory development.

(e) Standardized Measure of Discounted Future Net Cash Flows

The “Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves” (“Standardized Measure”) is calculated in accordance with guidance provided by FASB. The Standardized Measure does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates.

Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end reserves. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax flow. Tax credits and permanent differences are also considered in the future income tax calculation. Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The following summary sets forth the Standardized Measure (in thousands):

	December 31,
	2015			2014			2013
Future cash inflows	$	1,691,862		$	3,527,953		2,321,707
Future production costs	(471,148		)	(603,201		)	(389,753	)
Future development costs	(321,563		)	(545,352		)	(533,225	)
Future income tax expense(1)	(6,480		)	(12,526		)	—
Future net cash flows	892,671			2,366,874			1,398,729
10% annual discount for estimated timing of cash flows	(497,151		)	(1,372,282		)	(860,720	)
Standardized measure of Discounted Future Net Cash Flows	$	395,520		$	994,592		538,009

Future net cash flows do not include the effects of income taxes on future revenues because Vantage I was a limited liability company to subject to entity-level income taxation as of December 31, 2015, 2014, and 2013. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s members, with the exception of the provision made for the Texas Margin Tax. If the Company had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2015, 2014, and 2013 would have been $172.2 million, $411.7 million, and $183.6 million, respectively, net of the discount. The unaudited Standardized Measure at December 31, 2015, 2014, and 2013 would have been $226.7 million, $588.6 million, and $354.5 million, respectively.

(f) Changes in the Standardized Measure

A summary of the changes in the Standardized Measure are contained in the table below (in thousands):

	December 31,
	2015			2014			2013
Beginning of the period	$	994,592		$	532,354		244,925
Net changes in prices and production costs	(907,840		)	92,051			109,539
Net change in future development costs	135,489			(11,617		)	13,364
Sales, net of production costs	(61,640		)	(77,610		)	(41,206	)
Extensions	28,501			185,556			98,335
Acquisitions	2,755			74,849			14,341
Divestitures of reserves	(4		)	(63		)	(2,378	)
Revisions of previous quantity estimates	(21,794		)	(8,854		)	9,683
Previously estimated development costs incurred	139,064			115,384			25,221
Net change in taxes	2,614			(138		)	—
Accretion of discount	100,038			53,801			24,492
Changes in timing and other	(16,255		)	38,879			41,693
End of period	395,520			994,592			538,009

(g) Impact of Pricing

The estimates of cash flows and reserve quantities shown about are based upon the upon the unweighted average first-day-of-the month prices. If future gas sales are covered by contracts at specified prices, the contract prices would be used. Fluctuations in prices are due to supply and demand and are beyond our control.

The following average index prices were used in determining the Standardized Measure of:

	Marcellus Shale	Barnett Shale
December 31, 2013
Natural Gas per MMBtu	3.67	3.59
Oil per bbl	—	96.94
Natural Gas liquids per bbl	—	31.26
December 31, 2014
Natural Gas per MMBtu	4.35	4.24
Oil per bbl	—	94.99
Natural Gas liquids per bbl	—	30.66
December 31, 2015
Natural Gas per MMBtu	2.59	2.47
Oil per bbl	—	50.28
Natural Gas liquids per bbl	—	16.22

These prices related to the unweighted average first-of-the-month prices for the preceding twelve month period. These prices were then adjusted for quality, transportation fees, regional price differentials, fractionation costs, processing fees and other costs. For the Marcellus Shale, the relevant benchmark price for natural gas is Henry Hub. For the Barnett Shale, the relevant benchmark prices for oil, natural gas liquids and natural gas are WAHA, West Texas Intermediate and Oil Price Information Service, respectively.

Companies that follow the full cost accounting method are required to make ceiling test calculations. This test ensures that total capitalized costs for oil and gas properties (net of accumulated DD&A and deferred income taxes) do not exceed the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties that are being amortized. Application of these rules during periods of relatively low commodity prices, even if of short-term duration, may result in write-downs.

(14) Subsequent Events

The Company has evaluated subsequent events that occurred after December 31, 2015 through the audit report date, July 26, 2016. On January 19, 2016 the Company issued a Capital Contribution request in the aggregate amount of $20 million, due January 26, 2016. The amount was funded by the Company’s current equity interest owners.

On June 1, 2016, the Company entered into the Sixth Amendment to the Second Amended and Restated Credit Agreement (Sixth Amendment), which stated the borrowing base to be $285 million compared to $276 million as of March 31, 2016.

Any other material subsequent events that occurred during this time have been properly recognized or disclosed in these consolidated financial statements or the notes to the consolidated financial statements.

EX-99.4 8 a17-22068_2ex99d4.htm EX-99.4

Exhibit 99.4

VANTAGE ENERGY, LLC

Condensed Consolidated Balance Sheets

(Unaudited)

(In thousands)	September 30, 2016			December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	1,260		$	2,191
Accounts receivable (Note 2)	11,416			21,989
Accounts receivable—related party	33,199			—
Inventory	806			1,212
Prepayments and deposits	4,191			815
Commodity derivative assets	13,930			40,944
Total current assets	64,802			67,151
Property, plant, and equipment:
Oil and gas properties, full-cost method of accounting:
Proved	1,083,681			1,032,782
Unproved	72,605			74,619
Total oil and gas properties	1,156,286			1,107,401
Accumulated depletion and ceiling write-down	(821,083		)	(634,082		)
Net oil and gas properties	335,203			473,319
Gathering systems, less accumulated depreciation of $7,741 and $5,299	63,553			58,815
Other property, plant, and equipment, less accumulated depreciation of $2,134 and $1,948	717			772
Net property, plant, and equipment	399,473			532,906
Commodity derivative assets	10,689			15,679
Other assets	2,515			2,043
Total assets	$	477,479		$	617,779
Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities (Note 2)	$	33,524		$	40,937
Accounts payable—related party	—			1,100
Current portion of Revolving Credit Facility, net of unamortized deferred financing costs	265,430			—
Current portion of Second Lien Note Payable	2,000			2,000
Total current liabilities	300,954			44,037
Revolving Credit Facility, net of unamortized deferred financing costs	—			270,555
Second Lien Note Payable, net of unamortized deferred financing costs	189,260			189,780
Asset retirement obligations	8,927			8,466
Total liabilities	499,141			512,838
Contingently redeeemable Founders’ units	5,960			5,788
Members’ equity:
Member contributions, net of issuance costs	448,059			428,227
Accumulated deficit	(475,681		)	(329,074		)
Total members’ equity	(27,622		)	99,153
Total liabilities and members’ equity	$	477,479		$	617,779

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

VANTAGE ENERGY, LLC

Condensed Consolidated Statements of Operations

(Unaudited)

	Nine months ended September 30,
(In thousands)	2016			2015
Operating revenues:
Gas revenues	$	66,211		$	53,334
Oil revenues	2,124			2,524
NGLs revenues	8,764			6,683
Midstream revenues	7,244			4,318
Gain on commodity derivatives	9,929			45,123
Total operating revenues	94,272			111,982
Operating expenses:
Production and ad valorem tax expense	5,041			3,244
Marketing and gathering expense	7,457			3,567
Lease operating and workover expense	9,838			12,591
Midstream operating expense	2,198			1,068
General and administrative expense	5,415			5,357
Depreciation, depletion, amortization, and accretion expense	35,793			39,672
Impairment of oil and gas properties	155,994			156,767
Total operating expenses	221,736			222,266
Operating loss	(127,464		)	(110,284		)
Other expenses:
Other expense	153			3
Interest expense	18,990			16,158
Total other expenses	19,143			16,161
Net loss	$	(146,607	)	$	(126,445	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

VANTAGE ENERGY, LLC

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine months ended September 30,
(In thousands)	2016			2015
Cash flows from operating activities:
Net loss	$	(146,607	)	$	(126,445	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	35,793			39,672
Accretion of original issue discount	296			275
Impairment of oil and gas properties	155,994			156,767
Gain on commodity derivatives	(9,929		)	(45,123		)
Settlement of commodity derivatives	41,933			59,491
Changes in operating assets and liabilities:
Accounts receivable	10,573			10,467
Accounts payable—related party	(34,299		)	(7,960		)
Inventory	406			292
Prepayments and deposits	(3,376		)	(1,109		)
Accounts payable and accrued liabilities	6,371			6,074
Net cash provided by operating activities	57,155			92,401
Cash flows from investing activities:
Oil and gas property acquisition, exploration, and development	(60,940		)	(150,588		)
Gathering system additions	(7,916		)	(11,151		)
Water investment additions, net of surcharges refunded	(1,477		)	—
Other property, plant, and equipment additions	(95		)	(438		)
Net cash used in investing activities	(70,428		)	(162,177		)
Cash flows from financing activities:
Borrowings under Revolving Credit Facility	58,000			54,000
Principal payments on Revolving Credit Facility	(63,000		)	—
Principal payments on Second Lien Note Payable	(1,500		)	(1,500		)
Members’ contributions, net	20,004			—
Financing costs	(1,162		)	(1,377		)
Net cash provided by financing activities	12,342			51,123
Net change in cash and cash equivalents	(931		)	(18,653		)
Cash and cash equivalents—beginning of period	2,191			20,479
Cash and cash equivalents—end of period	$	1,260		$	1,826
Supplemental disclosure of cash flow information:
Cash paid for interest	$	19,941		$	17,156
Accrued capital expenditures	$	13,787		$	21,383

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(1) Description of Business and Summary of Significant Accounting Policies

(a) Nature of Operations and Principles of Consolidation

Vantage Energy, LLC (the “Company”) was organized as a limited liability company under the laws of the state of Delaware in 2006. The condensed consolidated financial statements include the accounts of Vantage Energy, LLC and its wholly-owned subsidiaries. All intercompany transactions have been eliminated in consolidation.

The Company is engaged in the exploration and exploitation of oil, natural gas and natural gas liquids, as well as natural gas acquisition, development, and gathering, in various basins in the United States of America, with the primary focus on unconventional natural gas plays.

The accompanying unaudited condensed consolidated financial statements of Vantage Energy, LLC have been prepared by the Company’s management in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information. Accordingly, these financial statements do not include all of the information required by GAAP for annual financial statements. Therefore, these condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes therein for the year ended December 31, 2015. The unaudited condensed consolidated financial statements included herein contain all adjustment which are, in the opinion of management, necessary to present fairly the Company’s financial position as of September 30, 2016 and December 31, 2015, and its condensed consolidated statements of operations and cash flows for the nine months ended September 30, 2016 and 2015. The condensed consolidated statements of operations for the nine months ended September 30, 2016 and 2015 are not necessarily indicative of the results to be expected for future periods.

(b) Use of Estimates

The preparation of these condensed consolidated financial statements requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. As a result, actual amounts could differ from estimated amounts. By their nature, these estimates are subject to measurement uncertainty, and the effect on the condensed consolidated financial statements of changes in such estimates in future periods could be significant. Significant estimates with regard to the Company’s condensed consolidated financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows, the recoverability of unproved oil and gas properties, the calculation of depletion of oil and gas reserves, the estimated cost and timing related to asset retirement obligations, and the estimated fair value of derivative assets and liabilities.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(1) Description of Business and Summary of Significant Accounting Policies (Continued)

(c) Oil and Gas Properties

The Company follows the full-cost method of accounting for oil and gas properties. Pursuant to full-cost accounting rules, the Company is required to perform a “ceiling test” calculation to test its oil and gas properties for possible impairment. If the net capitalized cost of the Company’s oil and gas properties subject to amortization (the carrying value) exceeds the ceiling limitation, the excess is charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects. The present value of estimated future net revenue is computed by applying the average first day of the month oil and gas price for the preceding 12-month period to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves, assuming the continuation of existing economic conditions.

As of June 30, 2016, the carrying value of the Company’s oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation. As a result, the Company recorded an impairment of $156.0 million for the six months ended June 30, 2016. No impairment was required for the three-month period ended September 30, 2016 as the calculated ceiling exceeded the carrying value of the Company’s oil and gas properties subject to the test. As the ceiling test calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in future quarters is a potentially lower ceiling value each quarter. Declines in commodity prices could result in future impairments.

(d) Adoption of New Accounting Principles

The FASB issued ASU 2015-03, Interest Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs, in April 2015. The core principle of ASU 2015-03 will require all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of debt, consistent with debt discounts. The Company adopted this standard as of January 1, 2016, and has applied the standard retrospectively. As a result of adoption, the Company has classified debt issuance costs to its Revolving Credit Facility (defined herein) and Second Lien Note Payable (defined herein) from other assets to debt on its condensed consolidated balance sheets.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(1) Description of Business and Summary of Significant Accounting Policies (Continued)

The retrospective adjustment to the December 31, 2015 condensed consolidated balance sheet is as follows:

	Previously reported December 31, 2015		Adjustments			As adjusted December 31, 2015
	(In thousands)
Other assets	$	4,771	$	(3,390	)	$	1,381
Revolving Credit Facility	271,000		(445		)	270,555
Second Lien Note Payable	192,725		(2,945		)	189,780

(2) Balance Sheet Disclosures

Accounts receivable consist of the following:

	September 30, 2016			December 31, 2015
	(In thousands)
Revenue	$	8,490		$	14,128
Joint interest billings	3,966			5,021
Derivative receivable	52			1,056
Other receivables	108			2,284
Allowance for doubtful accounts	(1,200		)	(500		)
Accounts receivable	$	11,416		$	21,989

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(2) Balance Sheet Disclosures (Continued)

Accounts payable and accrued liabilities consist of the following:

	September 30, 2016		December 31, 2015
	(In thousands)
Accrued capital expenditures	$	5,206	$	18,993
Accounts payable	8,913		1,467
Accrued revenue payable	7,930		6,978
Accrued marketing, gathering and transportation	3,781		5,646
Accrued production and ad valorem taxes	2,813		3,127
Accrued general and administrative expense	2,493		1,854
Accrued production expense payable	2,256		2,264
Other	132		608
Accounts payable and accrued liabilities	$	33,524	$	40,937

(3) Debt

Revolving Credit Facility

Effective July 19, 2007, the Company secured a credit facility with a group of bank lenders. Wells Fargo Bank, N.A. acts as administrative agent. Effective December 20, 2013, the Company amended and restated its credit facility (the “Revolving Credit Facility”) to adjust the borrowing base, increase the maximum commitment to $750 million, and allow for the Second Lien Note Payable (see below). The maturity date of the Revolving Credit Facility is January 1, 2017. As of September 30, 2016 and December 31, 2015, the Company had a borrowing base of $285.0 million and $276.0 million, respectively. As of September 30, 2016 and December 31, 2015, the Company had net outstanding borrowings of $265.4 million and $271.0 million, respectively. On each borrowing, the Company has the election to pay interest at a Base rate or Eurodollar LIBOR. The margin on Base rate loans ranges from 0.75% to 1.75%. The margin on LIBOR loans ranges from 1.75% to 2.75%. The Company pays quarterly commitment fees ranging from 0.375% to 0.500% of the unused borrowing base. The Company generally elects to pay interest based on LIBOR, plus the applicable margin, which was 4.03% in total as of September 30, 2016.

As of September 30, 2016, the Revolving Credit Facility was collateralized by all of the Company’s assets, including its 50% undivided nonoperated interest in the Vantage Midstream assets (as defined in Note 7).

Second Lien Note Payable

In December 2013, the Company entered into a second lien note payable (“Second Lien Note Payable”) with a face amount of $200 million, maturing on December 20, 2018. The Company has the election to pay interest at a Base rate or Eurodollar LIBOR. The margin on Base rate loans is 6.50%. The margin on LIBOR loans is 7.50%.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(3) Debt (Continued)

LIBOR has a floor of 1.00%. As of September 30, 2016, the stated interest rate was 8.5%, and net borrowings of $191.3 million was outstanding. The Second Lien Note Payable contains an optional prepayment provision that enables the Company to prepay the Second Lien Note Payable at par. The Second Lien Note Payable was issued with an original issue discount of $2.0 million, which has been classified as a reduction to the note balance. The discount is amortized over the term of the note using the effective interest method. The Second Lien Note Payable requires quarterly principal payments of $500,000, which commenced March 31, 2014.

As of September 30, 2016, the Second Lien Note Payable was collateralized by a second lien interest in all of the Company’s assets, including its 50% nonoperated interest in the Vantage Midstream assets, and contains certain financial covenants. These covenants include maintenance of a minimum asset coverage ratio and a minimum proved reserves value. As of September 30, 2016, the Company was in compliance with all of its financial covenants.

Borrowings outstanding as of September 30, 2016:

	As of September 30, 2016
(in thousands)	Revolving Credit Facility			Second Lien Note Payable
Principal	$	266,000		$	194,500
Net unamortized premium	—			(979		)
Net unamortized debt issuance costs	(570		)	(2,261		)

Total debt	265,430			191,260
Less: Current portion of long-term debt	265,430			2,000
Total long-term debt	$	—		$	189,260

The Revolving Credit Facility matures on January 1, 2017. The Company expects to repay and retire the Revolving Credit Facility and the Second Lien Note Payable in connection with the net proceeds from a future monetization event, undrawn capital commitments and/or and cash on hand. Additionally, the Company plans to obtain new financing following the anticipated corporate reorganization, contemporaneous with a monetization event. In addition, the Company expects that it will be able to secure incremental equity commitments or other sources of capital, including debt, if necessary, from its current equity investors, other investors, or lenders to address any shortfall. The Company’s current equity investors continue to be supportive of the Company’s long-term growth and financing strategy.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(3) Debt (Continued)

Maturities of outstanding borrowings as of September 30, 2016 are as follows:

(in thousands)	Revolving Credit Facility		Second Lien Note Payable
Year ending December 31,
2016	$	—	$	500
2017	266,000		2,000
2018	—		192,000
Total future maturities of outstanding borrowings	$	266,000	$	194,500

(4) Fair Value Measurements

Level 1:	Quoted prices are available in active markets for identical assets or liabilities.

Level 2:	Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability.

Level 3:	Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(4) Fair Value Measurements (Continued)

The assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize transfers in to and/or out of the fair value hierarchy as of the end of the reporting period in which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented. The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015, by level, within the fair value hierarchy (in thousands):

	September 30, 2016
	Fair value measurements
Description	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivative instruments	$	—	$	24,619	$	—	$	24,619

	December 31, 2015
	Fair value measurements
Description	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivative instruments	$	—	$	56,623	$	—	$	56,623

The Company’s commodity derivative instruments consist of variable-to-fixed price swaps. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires a variety of inputs, including contractual terms, published forward prices, and discount rates as appropriate. The Company’s estimates of fair value of commodity derivative instruments include consideration of the counterparties’ creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within Level 2 of the fair value hierarchy. The counterparties on the Company’s derivative instruments are the same financial institutions that hold the Revolving Credit Facility (Note 3). Accordingly, the Company is not required to post collateral on these derivatives since the banks are secured by the Company’s oil and gas properties.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(5) Asset Retirement Obligations

As of September 30, 2016, the Company’s asset retirement obligation was $8.9 million. Liabilities incurred, accretion expense and revisions to the Company’s estimates were not material for the nine months ended September 30, 2016.

(6) Commodity Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. The Company currently uses fixed price natural gas swaps for which it receives a fixed swap price for future production in exchange for a payment of the variable market price received at the time future production is sold. The Company has entered into various derivative contracts to manage price risk and to achieve more predictable cash flows. As a result of the Company’s hedging activities, the Company may realize prices that are greater or less than the market prices that it would have received otherwise.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(6) Commodity Derivative Instruments (Continued)

The following tables present the gross amounts of the Company’s recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, at fair value.

		September 30, 2016
	Condensed consolidated	Gross amounts
	balance sheet classification	Gross recognized		Offset			Net recognized
				(In thousands)
Derivative assets:
Commodity contracts	Current assets	$	17,917	$	(3,987	)	$	13,930
Commodity contracts	Noncurrent assets	14,234		(3,545		)	10,689
Derivative liabilities:
Commodity contracts	Current liabilities	$	3,987	$	(3,987	)	$	—
Commodity contracts	Noncurrent liabilities	3,545		(3,545		)	—

		December 31, 2015
	Condensed consolidated	Gross amounts
	balance sheet classification	Gross recognized		Offset			Net recognized
				(In thousands)
Derivative assets:
Commodity contracts	Current assets	$	41,242	$	(298	)	$	40,944
Commodity contracts	Noncurrent assets	15,872		(193		)	15,679
Derivative liabilities:
Commodity contracts	Current liabilities	$	298	$	(298	)	$	—
Commodity contracts	Noncurrent liabilities	193		(193		)	—

The table below summarizes the realized and unrealized gains and losses, net related to the Company’s derivative instruments for the nine months ended September 30, 2016 and 2015, recorded as operating revenues in the accompanying condensed consolidated statements of operations.

	Nine months ended September 30,
	2016			2015
	(In thousands)
Commodity derivative instruments:
Realized gains on commodity derivatives, net	$	41,932		$	59,491
Unrealized loss on commodity derivatives, net	(32,003		)	(14,368		)

Gain on commodity derivatives	$	9,929		$	45,123

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s commodity derivative instruments are subject to significant fluctuations from period to period.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(7) Related Party Transactions

(a) Gas Gathering System Operating Agreement

In connection with the Joint Development Agreement between the Company and Vantage Energy II, LLC (“Vantage II”), Vista Gathering, LLC (hereinafter referred to as “Vantage Midstream”) became the operator of the gas gathering and compression assets. Pursuant to a Gas Gathering System Operating Agreement, dated August 2, 2012, between the Company and Vantage Midstream, the Company and Vantage II are to pay their respective 50% shares of the gas gathering system’s operating and development costs, as well as their incurred gas gathering and compression fees. The Company was charged gas gathering and compression fees by Vantage Midstream for the wells that it operates of approximately $8.3 million and $3.7 million for the nine months ended September 30, 2016 and 2015, respectively.

(b) Water Investment

Pursuant to the Water Services and Supply Agreement, Vantage Midstream provides water services required in the Company’s drilling operations. For the nine months ended September 30, 2016, the Company’s payments to Vantage Midstream for water supply and transportation were immaterial.

(c) Management Services Agreement

In August 2012, the Company and Vantage II entered into a Management Services Agreement (“MSA”) whereby the Company is to provide certain executive management, administrative, accounting, finance, engineering, land, and information technology assistance to Vantage II. In exchange for receiving these services, Vantage II will pay the Company a fee (the “MSA Fee”). The MSA Fee is allocated based upon the gross general and administrative expenses incurred by the Company multiplied by a ratio of the relative capital expenditures and oil and natural gas production volumes of the Company and Vantage II. Certain adjustments are made to this calculation to reflect the allocation of general and administrative expenses to Vantage Midstream. The Company billed general and administrative expenses under the MSA to Vantage II of approximately $11.3 million and $8.6 million for the nine months ended September 30, 2016 and 2015, respectively.

(d) MIU Notes Receivable

In December 2014, the Company made loans to certain employees in the form of notes receivable. Interest accrues on the notes at 0.34% per annum, and the notes mature upon the earlier to occur of: 1) December 1, 2017; 2) consummation of Monetization Event (as defined); or 3) fifteen days after the date of voluntary termination of employment by the employee or termination by the Company for cause. As of September 30, 2016, the notes outstanding were approximately $1.3 million and are classified in other assets in the accompanying condensed consolidated balance sheets. The notes are collateralized by a first lien interest in each employees’ Management Incentive Units (“MIUs”) and all potential dividends and distributions and a second lien on all other personal assets. Interest income was not material for the nine months ended September 30, 2016 and 2015, respectively.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(8) Commitments and Contingencies

The Company leases office spaces in Colorado, Pennsylvania, and Texas and various compressors in Pennsylvania and Texas under noncancelable operating leases that expire at various dates through 2017. The associated future remaining obligations of such leases was not material as of September 30, 2016.

On August 22, 2008, the Company secured a letter of credit in the amount of $0.1 million with Wells Fargo Bank, N.A. in connection with the signing of an exploration agreement. Partial draws under this letter of credit are permitted. As of September 30, 2016, no amounts have been drawn under the letter of credit.

As part of a Founder’s employment agreement, the Company will pay $0.5 million to such Founder provided all of the following conditions have been met:

i. The Company’s invested capital equals $250 million or greater

ii. Monetization events aggregating at least $500 million in proceeds have been completed

iii. Distributions to Capital Interest Members are sufficient, in part, to exceed the Second Threshold, as defined in the LLC Agreement.

As of September 30, 2016, none of the $0.5 million has been accrued, as fulfillment of the above criteria has not been deemed probable as of such date.

Effective August 1, 2010, and amended in October 2014, the Company entered into a gas gathering agreement related to its Lake Arlington project in Tarrant County, Texas, which committed the Company to transport a minimum quantity of natural gas for seven years starting on the date gas is first delivered. If the Company transports more than the minimum quantity, the Company will receive a credit for excess transported gas, calculated as actual quantity transported, less minimum transportation quantity, multiplied by a stated dollar amount per MMBtu. This credit can be used to offset shortfalls incurred, if any, in the year immediately before or after the excess quantity was incurred. As of September 30, 2016, remaining total minimum revenue commitments due over the term of the agreement aggregate to $10.9 million. As of September 30, 2016, the portion of the remaining minimum commitment that is due in 2017 totals $7.1 million, subject to a rollover provision in the agreement that permits the Company to roll a portion of any deficit commitment to the subsequent period.

Effective August 1, 2013, the Company entered into a gas gathering agreement related to its Wedgwood project in Tarrant County, Texas, under which the Company is required to make a minimum revenue commitment of $8.8 million over four years starting on the date gas is first delivered. The gas gathering fee on which the minimum revenue commitment is based is $0.55 per MMBtu, and remains at that level under the agreement until the Company sells 20,000,000 MMBtu from its Wedgewood project, at which time the gas gathering fee reduces to $0.34 per MMBtu for all subsequent volumes. As of September 30, 2016, the Company had a remaining total commitment of $2.2 million. As of September 30, 2016 the portion of the remaining minimum revenue commitment that is due in 2017 totals $1.5 million, subject to a rollover provision in the agreement that permits the Company to roll a portion of any deficit obligations to the subsequent period.

On April 17, 2014, the Company entered into a 20,000 MMBtu/d firm marketing agreement to market a portion of production associated with volumes produced in the Marcellus Shale. The agreement began in October 2014 and continues through October 2020. Under the contract, the Company is paid based on TETCO M-2 pricing with the ability to share in downstream price upside when market conditions allow.

VANTAGE ENERGY, LLC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(8) Commitments and Contingencies (Continued)

(9) Capital Structure

Capital Interests

Total capital contributions and deemed commitments associated with outstanding Capital Interests are as follows:

	September 30, 2016		December 31, 2015
	(In thousands)
Institutional investors (deemed commitment—$470,559)	$	445,716	$	420,940
Founders (deemed commitment—$6,281)	5,960		5,788
Other employees (deemed commitment—$2,169)	2,103		2,055
Friends and family (deemed commitment—$6,225)	5,827		5,568
Total (total deemed commitment—$485,234)	$	459,606	$	434,351

Management Incentive Units

The Company has issued management incentive units to certain employees. The management incentive units participate only in distributions in liquidation events, meeting requisite financial thresholds after Capital Interests have recovered their investment and special allocation amounts. Management incentive units have no voting rights. Compensation expense for these awards will be recognized when all performance, market, and service conditions are probable of being satisfied (in general, upon a liquidating event), which has not occurred as of September 30, 2016. Accordingly, no value was assigned to the interests when issued.

(10) Subsequent Events

The Company has evaluated subsequent events that occurred after September 30, 2016 through, September 19, 2017. Any material subsequent events that occurred during this time have been properly recognized or disclosed in these condensed consolidated financial statements or the notes to the condensed consolidated financial statements. Effective October 19, 2016, Vantage Energy, LLC was acquired by Rice Energy Inc.

EX-99.5 9 a17-22068_2ex99d5.htm EX-99.5

Exhibit 99.5

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Managers and Members
Vantage Energy II, LLC:

We have audited the accompanying consolidated balance sheets of Vantage Energy II, LLC and subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Vantage Energy II, LLC and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.


	/s/ KPMG LLP

Denver, Colorado
July 26, 2016

VANTAGE ENERGY II, LLC

Consolidated Balance Sheets

December 31, 2015 and 2014

(In thousands)

	2015			2014
Assets
Current assets:
Cash and cash equivalents	$	2,439		$	21,185
Accounts receivable	10,397			10,123
Accounts receivable—related party	1,100			12,524
Inventory	242			171
Prepayments and deposits	70			59
Commodity derivative assets	30,737			10,254
Total current assets	44,985			54,316

Property, plant, and equipment:
Oil and gas properties, full-cost method of accounting:
Proved	420,197			313,695
Unproved	187,509			150,310
Total oil and gas properties	607,706			464,005
Accumulated depletion, depreciation, and amortization	(233,920		)	(24,929		)

Net oil and gas properties	373,786			439,076
Gathering system, less accumulated depreciation of $5,551 and $2,510	59,970			53,116
Net property, plant, and equipment	433,756			492,192
Commodity derivative assets	7,957			3,236
Other assets	1,877			1,601
Water investment, less accumulated amortization of $11 and $0	662			—
Total assets	$	489,237		$	551,345

Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	39,016		$	25,645
Total current liabilities	39,016			25,645
Revolving credit facility	149,000			100,000
Second Lien note payable, net of original issue discount of $1,464 and $2,337	98,539			97,663
Asset retirement obligations	2,091			1,484
Total liabilities	288,646			224,792
Contingently redeemable Founders’ units	498			498
Commitments and contingencies (note 8)
Members’ equity:
Member contributions, net of issuance costs	299,662			299,662
Retained earnings (accumulated deficit)	(99,569		)	26,393
Total members’ equity	200,093			326,055
Total liabilities and members’ equity	$	489,237		$	551,345

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY II, LLC

Consolidated Statements of Operations

Years ended December 31, 2015, 2014, and 2013

(In thousands)

	2015			2014			2013
Operating revenues:
Gas revenues	$	65,252		$	43,622		$	25,841
Midstream revenues	4,054			2,990			821
Gain (loss) on commodity derivatives	51,793			14,434			(1,393		)
Total operating revenues	121,099			61,046			25,269
Operating expenses:
Production and ad valorem tax expense	1,911			1,723			971
Marketing and gathering expense	9,745			5,333			4,560
Lease operating and workover expense	4,934			2,517			860
Midstream operating expense	1,834			891			313
General and administrative expense	7,308			5,423			4,214
Depreciation, depletion, amortization, and accretion expense	39,698			18,302			9,128
Impairment of oil and gas properties	172,673			—			—
Total operating expenses	238,103			34,189			20,046
Operating income (loss)	(117,004		)	26,857			5,223
Other expense:
Other expense	(180		)	—			—
Interest income (expense), net of capitalized interest	(8,778		)	(4,027		)	14
Total other income (expense)	(8,958		)	(4,027		)	14
Net income (loss)	$	(125,962	)	$	22,830		$	5,237

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY II, LLC

Consolidated Statements of Changes in Members’ Equity

Years ended December 31, 2015, 2014, and 2013

(In thousands)

	Contingently		Members’ Equity
	Redeemable Founders’ Units		Members’ Contributions		Accumulated Earnings (Deficit)		Total
Balance at December 31, 2012	133		79,795		(1,674	)	78,121
Members’ contributions	349		209,920		—		209,920
Net income	—		—		5,237		5,237

Balance at December 31, 2013	$	482	$	289,715	3,563		293,278
Members’ contributions	16		9,947		—		9,947
Net income	—		—		22,830		22,830

Balance at December 31, 2014	498		299,662		26,393		326,055
Members’ contributions	—		—		—		—
Net loss	—		—		(125,962	)	(125,962	)

Balance at December 31, 2015	$	498	$	299,662	(99,569	)	200,093

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY II, LLC

Consolidated Statements of Cash Flows

Years ended December 31, 2015, 2014, and 2013

(In thousands)

	2015			2014		2013
Cash flows from operating activities:
Net income (loss)	$	(125,962	)	22,830		5,237
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	39,698			18,302		9,128
Accretion of original issue discount	876			417		—
Impairment of proved oil and gas properties	172,673			—		—
(Gain) loss on commodity derivatives	(51,793		)	(14,434	)	1,393
Settlements on commodity derivatives	26,589			935		(1,684	)
Receipt from (payment for) novated commodity derivatives	—			300		—
Changes in operating assets and liabilities:
Accounts receivable	(274		)	(7,088	)	(3,035	)
Accounts receivable—related party	11,424			(3,231	)	(9,600	)
Inventory	(71		)	(171	)	—
Prepayments and deposits	(11		)	(59	)	—
Accounts payable and accrued liabilities	8,484			3,299		6,632

Net cash provided by operating activities	81,633			21,100		8,071

Cash flows from investing activities:
Oil and gas property exploration, acquisition, and development	(134,223		)	(176,799	)	(224,296	)
Gathering system additions	(13,117		)	(34,442	)	(8,695	)
Water investment additions	(1,512		)	—		—
Other assets	—			(1,374	)	—
Net cash used in investing activities	(148,852		)	(212,615	)	(232,991	)

Cash flows from financing activities:
Member contributions	—			9,963		210,269
Borrowings under revolving credit facility	49,000			125,000		—
Principal payments on revolving credit facility	—			(25,000	)	—
Borrowings under second lien note payable	—			97,250		—
Deferred financing costs	(527		)	(292	)	—
Net cash provided by financing activities	48,473			206,921		210,269
Net change in cash and cash equivalents	(18,746		)	15,406		(14,651	)
Cash and cash equivalents—beginning of year	21,185			5,779		20,430
Cash and cash equivalents—end of year	$	2,439		21,185		5,779

Supplemental disclosure of cash flow information:
Cash paid for interest	$	12,204		5,297		—
Supplemental disclosure of selected non cash accounts:
Accrued capital additions	$	20,366		15,484		12,819
Capitalized asset retirement obligations	534			887		445

See accompanying notes to consolidated financial statements.

VANTAGE ENERGY II, LLC

Notes to Consolidated Financial Statements

December 31, 2015, 2014, and 2013

(1) Description of Business and Summary of Significant Accounting Policies

(a) Nature of Operations and Principles of Consolidation

Vantage Energy II, LLC (the Company) was organized as a limited liability company under the laws of the state of Delaware in 2012. The consolidated financial statements include the accounts of Vantage Energy II, LLC and its two wholly owned subsidiaries. All intercompany balances have been eliminated in consolidation.

The Company is engaged in the exploration and exploitation of petroleum and natural gas, as well as natural gas acquisition, development, and gathering, with a focus in unconventional resources in the Appalachian Basin of the United States.

(b) Use of Estimates

Reserve estimates are, by their nature, inherently imprecise. The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures,

(c) Cash and Cash Equivalents

(d) Oil and Gas Properties

The Company follows the full-cost method of accounting for natural gas and crude oil properties. All costs associated with property acquisition, exploration, and development activities are capitalized. Exploration and development costs include dry hole costs, geological and geophysical costs, direct overhead related to exploration and development activities, and other costs incurred for the purpose of finding oil and gas reserves. Salaries and benefits paid to employees directly involved in the exploration and development of properties, as well as other internal costs that can be directly identified with acquisition, exploration, and development activities, are also capitalized. For the years ended December 31, 2015, 2014, and 2013, the Company capitalized certain internal costs of approximately $4.5 million, $3.6 million, and $4.1 million, respectively.

Capitalized costs, as adjusted for estimated future development costs and estimated asset retirement costs, less estimated salvage values, are depreciated, depleted, and amortized using the units-of-production method based on estimated proved reserves as determined by petroleum engineers. The costs of wells-in-progress and unevaluated properties, including any related capitalized interest and internal costs, are not amortized. For the purposes of this calculation, crude oil and natural gas liquid reserves and production are converted to equivalent volumes of natural gas based on the relative energy content of one barrel to six thousand cubic feet of gas. Proceeds from the disposal of properties are

Pursuant to the full-cost accounting rules, the Company is required to perform a “ceiling test”. If the net capitalized cost of the Company’s oil and gas properties subject to the amortization (the carrying value) exceeds the ceiling limitation, the excess would be charged to expense. The ceiling limitation is equal to the sum of the present value discounted at 10% of estimated future net cash flows from proved reserves, the cost of properties not being amortized, the lower of cost or estimated fair value of unproven properties included in the costs being amortized, and all related income tax effects. The present value of estimated future net revenue is computed by applying the average first day of the month oil and gas price for the preceding 12-month period to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves, assuming the continuation of existing economic conditions.

For the year ended December 31, 2015, the carrying value of the Company’s oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation by $172.7 million. As a result, the Company recorded an impairment of $172.7 million. No impairment was recorded in 2014 or 2013. The ceiling test calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter commodity prices in future quarters could result in a potentially lower ceiling value in future periods. This could result in ongoing impairments each quarter until prices stabilize or improve.

(e) Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2015, by the year in which such costs were incurred. Included in the $187.5 million of costs not subject to amortization are approximately $61 million that the Company deems significant related to its acquisition of properties from Chesapeake Energy in the Marcellus Shale during 2013. The Company expects to evaluate and develop these Marcellus Shale properties over the next three to five years and to include the relevant costs in the amortization computation as such evaluation activities are completed.

	Costs Incurred (In thousands)
	Prior to 2013		During 2014	During 2015	Total
Acquisition Costs	$	109,639	38,888	18,065	166,592
Exploration and development costs	—		—	9,355	9,355
Capitalized Interest	2,444		1,036	8,082	11,562
Total	$	112,083	39,924	35,502	187,509

(f) Joint Ventures

(g) Inventory

(h) Gas Gathering System

The Company’s gas gathering assets are held by Vista Gathering, LLC (hereinafter referred to as Vantage Midstream). The Company has a 100% membership interest in Vantage Midstream, operates the majority of Vantage Midstream’s assets, and owns a 50% undivided working interest in such assets. All gas transported in the gas gathering system relates to wells in which the Company and/or Vantage Energy, LLC (Vantage I), an affiliate under common management, owns a working interest and for which either the Company or Vantage I serves as operator. Vantage Midstream also owns a 38% nonoperated interest in the Appalachia Midstream Services, Rogersville system gas gathering joint venture. The Company and Vantage I each own a 50% undivided working interest in Vantage Midstream’s assets.

The Company’s gas gathering assets are being depreciated on the straight-line method over a 20-year useful life. For the years ended December 31, 2015, 2014, and 2013, the Company recognized depreciation expense on its gas gathering system assets of approximately $3.0 million, $1.7 million, and $0.7 million, respectively. Maintenance and repairs are charged to expense as incurred. Expenditures that extend the useful lives of assets are capitalized. When assets are retired or otherwise disposed of, the cost of the assets and the related accumulated depreciation are removed from the accounts. Any gain or loss on retirements is reflected in other income in the year in which the asset is disposed.

The Company reviews its long-lived assets other than oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Company performs an analysis of the anticipated undiscounted future net cash flows of the related long-lived assets and if the carrying value of the related asset exceeds the undiscounted cash flows, the carrying value is reduced to the asset’s fair value and an impairment loss is recorded against the long-lived asset. There have been no provisions for impairment recorded for the years ended December 31, 2015, 2014 and 2013.

(i) Water Investment

Vantage Midstream entered into a 10-year agreement for Water System Expansion and Supply with Southwestern Pennsylvania Water Authority (SPWA) on February 18, 2015. The purpose of the agreement was to fund and assist SPWA in constructing an expansion to its water supply system; grant the Company preferred rights to water volumes for its use in its oil and gas operations; and create a repayment structure for the Company and Vantage Midstream through a surcharge applicable to all oil and gas water users. The proposed water system improvements to be funded by the Company are estimated to be $14.7 million; however, the Company may terminate the agreement without penalty. The surcharge in the amount of $3.50 per 1,000 gallons of water sold to oil and gas users from the system is collected by SPWA and remitted to Vantage Midstream. The costs incurred by us are capitalized and are being amortized on a straight line basis over the life of the agreement. Payments to Vantage Midstream from SPWA derived from surcharges paid to SPWA by third parties are applied as a recovery of capital investment for funds advanced by Vantage Midstream to expand the system, while payments to Vantage Midstream from SPWA derived from surcharges from the Company are recorded as an offset to Vantage Midstream’s cost of water.

The Company entered in a Water Services and Supply Agreement with Vantage Midstream effective May 1, 2015. Under the agreement, Vantage Midstream will provide water services required by the Company, including the supply of water for injection and related collection, recycling, purifying, and the disposal of water after use. Vantage Midstream is responsible for the sourcing and transportation of water as requested by the Company. Vantage Midstream will also collect, clean, recycle, transport, and/or dispose of produced water and flow back water resulting from the Company’s operations. The Company’s 50% undivided working interest in the profits of the water business are eliminated against the full cost pool upon consolidation.

(j) Deferred Financing Cost

Costs associated with obtaining debt financing are deferred and amortized over the term of the debt. These costs, net of amortization, are included in other assets.

(k) Asset Retirement Obligations

Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and returning such land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and the cost of such liability is recorded as an increase in the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period and the capitalized cost is depleted as part of the full-cost pool or is depreciated as part of the gas gathering system. Revisions to estimated asset retirement obligations result in adjustments to the related capitalized asset and corresponding liability.

(l) Commodity Derivatives

The Company uses commodity derivative instruments to provide a measure of stability to its cash flows in an environment of volatile natural gas prices and to manage its exposure to commodity price risk. The Company records all derivative instruments at fair value within the accompanying consolidated balance sheets. Changes in fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. Management has decided not to use hedge accounting under the accounting guidance for its derivatives; therefore, the changes in fair value are recognized in earnings. The Company classifies cash payment and receipts on its derivative instruments in operating cash flows in the accompanying consolidated statements of cash flows.

(m) Revenue Recognition

The Company accounts for natural gas sales using the “entitlements method”. Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. The Company sells the majority of its products soon after production at various locations, including the wellhead, at which time title and risk of loss pass to the buyer. At December 31, 2015 and 2014, the Company did not have any material gas imbalances.

(n) Concentrations of Credit Risk

The Company grants credit in the normal course of business to oil and gas purchasers in the United States of America. Collectability of the Company’s natural gas revenue is dependent upon the financial wherewithal of the Company’s purchasers, as well as general economic conditions of the industry. To date, the Company has not had any bad debts.

Approximately, 54%, 28%, and 15% of the Company’s accounts receivable as of December 31, 2015 were due from Asset Risk Management (ARM), South Jersey, and Noble Group, respectively.

Approximately, 41%, 24%, and 24% of the Company’s accounts receivable as of December 31, 2014 were due from South Jersey Industries, Sequent Energy, and Noble Group, respectively.

Approximately, 39% and 32% of the Company’s oil and gas revenue for the year ended December 31, 2015 were generated from ARM and South Jersey, respectively. Approximately, 51% and 48% of the Company’s oil and gas revenue for the year ended December 31, 2014 were generated from EQT Production Company and Sequent Energy, respectively. Approximately 69% and 30% of the Company’s oil and gas revenues for the year ended December 31, 2013 was generated from EQT Production Company and Sequent Energy, respectively.

Although a substantial portion of production is purchased by these major customers, the Company does not believe the loss of any one or both customers would have a material adverse effect on our business, as other customers or markets would be accessible to us,

(o) Marketing and Gathering Costs

The Company sells its gas at the wellhead and receives payment net of gathering expenses. Vantage Midstream gathers all gas, excluding the Appalachia Midstream Services joint venture area. Vantage Midstream gathering fees are $0.26 per mmbtu for initial wells and $0.50 per mmbtu for subsequent wells, with a sliding scale downward to $0.25 per mmbtu based on cumulative system throughput.

(p) Impact Fees

(q) Capitalized Interest

The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. For the years ended December 31, 2015, 2014, and 2013, the Company capitalized interest costs to unproved properties of $4.2 million, $2.7 million, and $0, respectively.

(r) Income Taxes

The Company accounts for uncertainty in income taxes in accordance with generally accepted accounting principles, which prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing in the consolidated financial statements tax positions taken or expected to be taken on a tax return, including a decision on whether or not to file in a particular jurisdiction. Only tax positions that meet a more-likely than-not recognition threshold at the effective date may be recognized or continue to be recognized.

Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. No interest or penalties have been assessed as of December 31, 2015. The Company’s information returns for tax years subject to examination by tax authorities include 2012 through the current year for state and federal tax reporting purposes.

(s) New Accounting Pronouncements

effective for annual reporting periods beginning after December 15, 2017. The Company will implement the provisions of ASU 2014-09 as of January 1, 2018. The Company has not yet determined the impact of the new standard on its current policies for revenue recognition.

The FASB issued ASU 2015-03, Interest Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs, in April 2015. The core principle of ASU 2015-03 will require all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of debt, consistent with debt discounts. Upon adoption of ASU 2015-03, the new standard is limited to the presentation of debt issuance costs. The standard does not affect the recognition and measurement of debt issuance costs. In August 2015, the FASB issued ASU 2015-15, Interest—Imputations of Interest, Subtopic 835-30, Interest (ASU 2015-15). The guidance in ASU 2015-03 did not address the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. ASU 2015-15 was issued to clarify that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. The amendments in ASU 2015-03 should be applied on a retrospective basis and early adoption is permitted. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. The Company will implement the provision of ASU 2015-03 as of January 1, 2016. The Company does not believe the impact of the new standard on its presentation of debt issuance costs will have a material effect on the Company’s financial statements and related disclosures.

(2) Balance Sheet Disclosures

Accounts receivable consist of the following:

	December 31
	2015		2014
	(In thousands)
Joint interest billings	$	141	219
Revenue	10,256		9,904
	$	10,397	10,123

	December 31
	2015		2014
	(In thousands)
Accrued capital expenditures	$	20,366	15,484
Accrued marketing, gathering, and transportation costs	4,077		4,151
Cash calls payable	232		—
Accrued impact fees payable	1,911		1,555
Accrued interest payable	1,380		1,456
Accounts payable	5,643		1,248
Accrued production expense payable	1,124		753
Accrued general and administrative expenses	1,535		644
Accrued revenue payable	2,748		354
	$	39,016	25,645

Accounts payable and accrued liabilities consist of the following:

(3) Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations

The assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize transfers in and/or out of the fair value hierarchy as of the end of the reporting period in which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 by level within the fair value hierarchy (in thousands):

	December 31, 2015
	Fair value measurements
Description	Level 1		Level 2	Level 3	Total
Assets:
Commodity derivative instruments	$	—	38,694	—	38,694

	December 31, 2014
	Fair value measurements
Description	Level 1		Level 2	Level 3	Total
Assets:
Commodity derivative instruments	$	—	13,490	—	13,490

The Company’s commodity derivative instruments consist of variable-to-fixed price swaps. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires a variety of inputs, including contractual terms, published forward prices, and discount rates, as appropriate. The Company’s estimates of fair value of commodity derivative instruments include consideration of the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. The counterparties on the Company’s derivative instruments are the same financial institutions that hold the Revolving Credit Facility (note 7). Accordingly, the Company is not required to post collateral on these derivatives since the bank is secured by the Company’s oil and gas assets.

Non-Recurring Fair Value Measurements

The Company uses the income valuation technique using a discounted cash flow model to estimate the initial fair value of asset retirement obligations using estimated gross well costs of reclamation ranging in amounts from $10,000 to $100,000, timing of expected future dismantlement costs ranging from 20 to 28 years, and a weighted average credit-adjusted risk-free rate. Accordingly, the fair value is based on unobservable pricing inputs and, therefore, is included within the Level 3 fair value hierarchy. During the years ended December 31, 2015 and 2014, the Company recorded liabilities for asset retirement obligations of $0.3 million and $0.9 million, respectively. See note 4 for additional information.

Other Financial Instruments

Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities. The financial statement carrying amounts of these items approximate their fair values due to their short-term nature.

(4) Asset Retirement Obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of oil and gas properties and the gas gathering system:

	December 31
	2015		2014
	(In thousands)
Beginning of year	$	1,484	564
Liabilities incurred	288		860
Accretion expense	73		30
Revisions to estimate	246		30
End of year	$	2,091	1,484

(5) Commodity Derivative Instruments

While the use of instruments limits the downside risk of adverse price changes, their use may also limit future revenue from favorable price changes. The Company has adopted fair value accounting for its derivatives; therefore, changes in the fair value of derivative financial instruments are recognized in earnings. Cash payments or receipts on such contracts are included in cash flows from operating activities in the consolidated statements of cash flows.

At December 31, 2015, the terms of outstanding commodity derivative contracts were as follows:

Commodity

Quantity
remaining

Prices

Price index

Contract
period

Estimated
fair value

(in
thousands)

Natural gas swaps (MMBtu):

Dominion South Point

65,201,000

1.67 - 3.13

Dominion South Point

1/16 - 12/19

38,694

Total (MMBtu)

65,201,000

38,694

The Company estimates that 2016 hedged volumes, in aggregate, represent approximately 63% of the Company’s estimated proved gas production for 2016, based upon the year-end external reserve report.

Depending on changes in oil and natural gas futures markets and management’s view of underlying supply and demand trends, the Company may increase or decrease its hedging positions.

The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and by counterparty. As of December 31, 2015, the Company’s commodity derivative instruments were subject to an enforceable master netting arrangement that provides for offsetting of amounts payable or receivable between the Company and the counterparty. The agreement also provides that in the event of an early termination, the counterparty has the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in the accompanying consolidated balance sheets.

The following tables provide a reconciliation between the net assets and liabilities reflected in the accompanying consolidated balance sheets and the potential effects of master netting arrangements on the gross fair value of the commodity derivative contracts:

		December 31, 2015
	Consolidated balance sheet classification	Gross recognized assets/ liabilities		Gross amounts offset		Net recognized fair value assets/ liabilities
				(In thousands)
Commodity derivative assets:
Commodity contracts	Current assets	$	30,868	(131	)	30,737
Commodity contracts	Noncurrent assets	7,998		(41	)	7,957
Total commodity derivative assets		$	38,866	(172	)	38,694
Commodity derivative liabilities:
Commodity contracts	Current liabilities	$	131	(131	)	—
Commodity contracts	Noncurrent liabilities	41		(41	)	—
Total commodity derivative liabilities		$	172	(172	)	—

		December 31, 2014
	Consolidated balance sheet classification	Gross recognized assets/ liabilities		Gross amounts offset		Net recognized fair value assets/ liabilities
				(In thousands)
Commodity derivative assets:
Commodity contracts	Current assets	$	10,296	(42	)	10,254
Commodity contracts	Noncurrent assets	3,391		(155	)	3,236
Total commodity derivative assets		$	13,687	(197	)	13,490
Commodity derivative liabilities:
Commodity contracts	Current liabilities	$	42	(42	)	—
Commodity contracts	Noncurrent liabilities	155		(155	)	—
Total commodity derivative liabilities		$	197	(197	)	—

The table below summarizes the realized and unrealized gains related to the Company’s commodity derivative instruments. These realized and unrealized gains are recorded in the accompanying consolidated statement of operations.

	Location of gains recognized in	Year ended December 31
	earnings	2015		2014	2013
		(In thousands)
Commodity derivative instruments:
Realized gains (losses) on commodity derivative instruments	Operating revenue	$	26,589	935	(1,684	)
Unrealized gain on commodity derivative instruments	Operating revenue	25,204		13,499	291
Total gain (loss) on commodity derivatives		$	51,793	14,434	(1,393	)

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s commodity derivative instruments are subject to large fluctuations from period to period.

(6) Related Party Transactions

(a) Gas Gathering System Operating Agreement

In connection with the Joint Development Agreement with Vantage I, the Company, through its wholly owned subsidiary, Vantage Midstream, became the operator of the gas gathering assets. Pursuant to a Gathering System Operating Agreement, dated August 2, 2012, between the Company and Vantage I, the Company and Vantage I are to pay their respective 50% shares of the gas gathering system operating and development costs, as well as their incurred gas gathering and compression fees. The Company was charged gas gathering and

compression fees by Vantage Midstream of $23.9 million, $9.8 million, and $1.4 million for the years ended December 31, 2015, 2014, and 2013, respectively.

(b) Water Investment

Pursuant to the Water Services and Supply Agreement, Vantage Midstream provides water services required in the Company’s drilling operations. The Company paid fees to Vantage Midstream of $6.5 million for the year ended December 31, 2015. No such fees were paid in 2014 or 2013.

(c) Management Services Agreement

In August 2012, the Company and Vantage I entered into a Management Services Agreement (MSA) whereby Vantage I is to provide certain executive management, administrative, accounting, finance, engineering, land, and information technology assistance to the Company. In exchange for providing these services, the Company will pay Vantage I a fee (the MSA Fee). Through June 2014, the MSA Fee was calculated as 50% of the overall gross general and administrative expenses incurred by Vantage I. Starting in July 2014, the MSA Fee is based upon the gross general and administrative expenses incurred by Vantage I multiplied by a ratio of the relative capital expenditures and oil and natural gas production volumes of the Company and Vantage I. Certain adjustments are made to this calculation to reflect the allocation of general and administrative expenses to Vantage Midstream. For the years ended December 31, 2015, 2014, and 2013, the Company recorded gross general and administrative expenses incurred under the MSA of approximately $12.0 million, $8.7 million, and $8.3 million, respectively.

(d) MIU Notes Receivable

In December 2014, the Company made loans to certain employees in the form of notes receivable. Interest accrues on the notes at 0.34% per annum, and the notes mature upon the earlier to occur of: 1) December 1, 2017; 2) consummation of Monetization Event (as defined); or 3) fifteen days after the date of voluntary termination of employment by the employee or termination by the Company for cause. As of December 31, 2015, the notes had a balance of $1.4 million and are classified in other assets in the accompanying consolidated balance sheets. The notes are collateralized by a first lien interest in the employees’ interest in each employees’ Management Incentive Units (MIUs) and all potential dividends and distributions and a second lien on all other personal assets. Interest income was deemed de minimus for the year ended December 31, 2015.

(e) Derivative Novations

In November 2013, the Company entered into an agreement to purchase certain derivative contracts from Vantage I, as approved by Wells Fargo Bank, N.A. The Company determined the total fair value of the derivative contracts on the date of transfer to be approximately $1.7 million.

In January 2014, the Company entered into an agreement to purchase certain derivative contracts from Vantage I, as approved by Wells Fargo Bank, N.A. The Company determined the total fair value of the derivative contracts on the date of transfer to be approximately $0.3 million.

(7) Long-Term Debt

(a) Revolving Credit Facility

Effective November 29, 2012, the Company secured a credit facility (the Revolving Credit Facility) with a group of bank lenders. Wells Fargo Bank, N.A. acts as administrative agent. Effective December 4, 2014 the Company amended and restated its Revolving Credit Facility to add a lien on the Vantage Midstream gas gathering system and add a midstream borrowing base. The maturity date of the Revolving Credit Facility is January 1, 2017. The Revolving Credit Facility has a maximum commitment of $500 million and as of December 31, 2015 and 2014, had a borrowing base of $166 million and $126 million, respectively. As of December 31, 2015 and 2014, the Company had outstanding borrowings of $149 million and $100 million, respectively. On each borrowing, the Company has the election to pay interest at a Base rate or LIBOR. The margin on Base rate loans ranges from 0.75% to 1.75%. The margin on LIBOR loans ranges from 1.75% to 2.75%. The Company pays quarterly a commitment fee ranging from 0.375% to 0.50% of the unused borrowing base. The Company elected to pay interest based on LIBOR, plus the applicable margin, which was 2.93% in total as of December 31, 2015.

As of December 31, 2015, the Revolving Credit Facility was collateralized by all of the Company’s assets, including its 50% operated interest in the Vantage Midstream assets.

The Revolving Credit Facility contains certain financial covenants, including maintenance of a minimum current ratio and a maximum leverage ratio. As of December 31, 2015, the Company was not in compliance with the minimum current ratio covenant under the Revolving Credit Facility. On May 10, 2016, the Company entered into the Eighth Amendment to Credit Agreement (Eighth Amendment), which included among other things, an equity cure right, applied retroactively to December 31, 2015, applicable to the Company’s covenants under its credit agreement. The Company executed two $10 million capital calls, aggregating $20 million, from its current equity owners during the

first four months of 2016, and such equity was included in the calculation of the current ratio covenant as of December 31, 2015, and, as a result, the Company was in compliance with all of its financial covenants as of December 31, 2015.

(b) Second Lien Term Loan

In May 2014, the Company entered into a second lien note payable (Second Lien note payable) with a face amount of $100 million, maturing on May 8, 2017. The Company has the election to pay interest at a Base rate or Eurodollar LIBOR. The margin on Base rate loans is 6.50%. The margin on LIBOR loans is 7.50%. As of December 31, 2015, the stated interest rate was 8.50%, and $100.0 million remained outstanding. The Second Lien note payable contains an optional prepayment provision that enables the Company to prepay the Second Lien note payable at par. The Second Lien note payable was issued with an original issue discount of $2.75 million, which has been classified as a reduction to the note balance. The discount is amortized over the term of the note using the effective interest method.

As of December 31, 2015, the Second Lien note payable was collateralized by a second lien interest in all of the Company’s assets, including its 50% operated interest in the Vantage Midstream assets, and contains certain financial covenants. These covenants include maintenance of a maximum leverage ratio. As of December 31, 2015 and 2014, the Company was in compliance with this financial covenant.

During the years ended December 31, 2015, 2014, and 2013, the Company recognized gross interest expense of approximately $13.0 million, $6.7 million, and $0, respectively.

Maturities of long-term debt as of December 31, 2015 (including current maturities, excluding unamortized debt discounts) are as follows (in thousands):

	Revolving Credit Facility		Second Lien
Year ending December 31,
2016	$	—	—
2017	149,000		100,000
Total future maturities of long-term debt	$	149,000	100,000

(8) Commitments and Contingencies

As of December 31, 2015, the Company, as counterparty along with Vantage I, had contracts with certain rig operators and pipe suppliers totaling approximately $0.5 million of commitments for 2016. The commitments are allocated evenly between Vantage I and Vantage II.

On April 17, 2014, the Company entered into a 20,000 Mmbtu/d firm marketing agreement to market gas production associated with volumes produced in the Marcellus Shale. The agreement begins in October 2014 and continues through October 2020. Under the contract, the Company is paid based on TETCO M-2 pricing with the ability to share in downstream price upside when market conditions allow.

On May 9, 2014, the Company entered into a 37,500 Mmbtu/d firm marketing agreement to market gas production associated with volumes produced in the Marcellus Shale. The agreement began in November 2014 and continues through October 2019. Under the contract, the Company is paid based on TETCO M-2 pricing.

(9) Capital Structure

Summarized below are the classes of interests that have been authorized:

a) Class I Interest Units (Class I Units)

b) Class M Management Incentive Units (Class M Units).

Effective July 29, 2012, the Members approved the Amended and Restated Limited Liability Company Agreement (the Agreement).

Class I Units

Class I Units are issued to Members from time to time in exchange for a Member’s capital commitment to make cash contributions when called by the Company pursuant to the terms as described in the Agreement.

The Company is authorized to issue as many Class I Units as its board of managers approves. Total capital commitments and contributions associated with outstanding Class I Units are as follows:

	December 31
	2015		2014
	(In thousands)
Institutional investors (commitment—$400,000)	$	298,804	298,804
Founders (commitment—$667)	498		498
Other employees/friends and family (commitment—$1,225)	967		967
Total (total commitment—$401,892)	$	300,269	300,269

As of December 31, 2015 and 2014, the Company had undrawn commitments of $101.6 million and $101.7 million, respectively. Included in the member contributions on the consolidated balance sheets are equity issuance costs of approximately $0.1 million as of December 31, 2015 and 2014.

In June 2018, all capital commitments associated with the Class I Units will be reduced to contributions made at that time. In addition, the capital commitments of the Founders and selected other employees are subject to an additional increase of up to $7.0 million in the aggregate depending upon distributions received from Vantage I.

Decisions of the Company are approved by the majority of the Company’s board of managers. As of December 31, 2015, the Company’s board of managers comprised eight managers, including six appointed by the Institutional Investors, and the two Founders. One of the managers appointed by each Institutional Investor shall be subject to approval by the Founders.

Distributions of funds associated with the Class I Units follow a prescribed framework, which is outlined in detail in the Agreement. In general, distributions are first made to those Members who have made capital contributions in accordance with sharing ratios until such Members receive distributions to meet an internal rate of return threshold of 8%. Subsequent distributions are then allocated between the Class I and Class M Units in accordance with the provisions of the Agreement.

The Class I Units are illiquid, subject to substantial transfer restrictions, and have certain drag-along and tag-along rights as provided for in the Agreement.

The Company has the right, but not the obligation, to repurchase all of the Class I Units of management members if employment is terminated for any reason. If employment is terminated without cause, the repurchase price of the Class I Units is based on the fair market value of the units, as defined in the Agreement. If employment is terminated for cause, the repurchase price is equal to the lesser of i) the aggregate unreturned capital contributions and ii) the fair market value. However, the Company option to acquire does not apply to the Founders if employment is terminated due to death or disability. Upon termination of employment without cause or due to death or disability, the Founders/heirs may put their Class I Units of the Company at fair market value. The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

Upon termination of employment without cause or due to death or disability, the Founders/heirs may put their Class I Units to the Company at fair market value. Upon the occurrence of death or disability, the exercise of this put right is at the discretion of the Founders/heirs, which is an event outside of the Company’s control. Under the standard codified within ASC 480, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” and Emerging Issues Tax Force (“EITF”) Topic D-98, stock subject to redemption requirements outside the control of the Company are required to be classified outside of permanent equity. Accordingly, the Founders’ equity is classified outside of members’ equity. The occurrence of these events is not deemed probable, and therefore, the Founders’ equity has been measured at historic cost. The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

Class M Management Incentive Units

The Company has issued management incentive units to certain employees. The management incentive units participate only in distributions in liquidation events, meeting requisite financial thresholds after Capital Interests have recovered their investment, and special allocation amounts. Management incentive units have no voting rights. Compensation expense for these awards will be recognized when all performance, market, and service conditions are probable of being satisfied (in general, upon a liquidating event). Accordingly, no value was assigned to the interests when issued.

The Management Incentive Plan, as described in the Agreement, authorizes up to 2,000,000 nonvoting Class M Units. Class M Units may be granted with an assigned participation level.

Class M Units issued to the Founders may not exceed 900,000 and vest 15% on each of the first, second, and third annual grant-date anniversaries and 100% upon consummation of a monetization event. However, if a Founder’s employment is terminated without cause or due to death or disability, the Class M Units held will be at least 50% vested.

The Class M Units issued to all others vest in accordance with individual grant letters, but generally require a service period of between three and five years before vesting in 45% of the Class M Units, with the remaining Class M Units vesting upon a monetization event if employed by the Company for more than one year. All vested Class M Units shall be forfeited for no consideration if employment is terminated for cause. All unvested Class M Units, whether to Founders or management members, shall be forfeited upon termination of employment for any reason.

The Company has the right, but not the obligation, to repurchase all of the vested Class M Units of management members if employment is terminated for any reason. If employment is terminated without cause, the repurchase price of the Class M Units is based on the fair market value of the units, as defined in the Agreement. However, the Company’s option to acquire the Class M Units does not apply to the Founders if employment is terminated due to death or disability.

Upon termination of employment upon death or disability, the Founders/heirs may put their Class M Units to the Company at fair market value. The put option cannot be exercised if a Founder voluntarily terminates employment or is terminated for cause.

The following table presents the activity for Class M Units outstanding:

	Units
Outstanding—December 31, 2013	1,817,000
Granted	20,000
Forfeited	(90,850	)

Outstanding—December 31, 2014	1,746,150
Granted	52,550
Forfeited	(167,100	)

Outstanding—December 31, 2015	1,631,600

As of December 31, 2015 and 2014, 649,650 and 448,825, respectively, Class M Units were vested. For financial reporting purposes, no related compensation expense has been recorded as of December 31, 2015 and 2014, as the grant-date fair value of the Class M Units was deemed immaterial.

(10) Liquidity

The Revolving Credit Facility matures on January 1, 2017. The Company expects to repay and retire the Revolving Credit Facility in connection with the net proceeds from the completion of the public offering and cash on hand. The Company intends the Second Lien note payable to remain outstanding following the completion of the public offering. Additionally, the Company plans to obtain new financing following the anticipated corporate reorganization, contemporaneous with the offering.

In the event that some deficiency exists between the proceeds of the offering or the terms of the new facility and the Company’s current facility, as of December 31, 2015 the Company has available undrawn capacity under its existing borrowing base of $17 million and available undrawn capacity under its equity commitments of $102 million to address such a deficiency. In addition, the Company expects that it will be able to secure incremental equity commitments and other sources of capital, including debt, if necessary, from its current equity investors, other investors or lenders to address any shortfall. The Company’s current equity investors continue to be supportive of the Company’s long-term growth and financing strategy.

(11) Supplemental Information on Gas Producing Activities (unaudited)

The following is supplemental information regarding our consolidated gas producing activities. The amounts shown include our net working and royalty interests in all of our gas properties.

(a) Capitalized Costs Relating to Gas Producing Activities

	December 31,
	2015			2014		2013
				(In thousands)
Proved properties	$	420,197		313,695		158,222
Unproved properties	187,509			150,310		127,995
	607,706			464,005		286,217
Accumulated depreciation and depletion	(223,920		)	(24,929	)	(8,408		)
Net capitalized costs	$	373,786		439,076		$	277,809

(b) Costs incurred in Certain Gas Activities

	December 31,
	2015		2014	2013
	(In thousands)
Acquisitions:
Unproved properties	$	507	10,704	$	195,577
Proved properties	—		—	114
Development costs	137,829		161,756	39,274
Exploration costs	—		—	48
Gas expenditures	$	138,336	172,460	$	235,013

c) Results of Operations for Gas Producing Activities

	December 31,
	2015			2014	2013
Revenues	$	65,252		43,622	25,841
Production costs	16,590			9,573	6,391
Depletion and accretion	36,390			16,550	8,409
Impairment of proved oil and gas properties	172,673			—	—
Results of operations from producing activities	(160,401		)	17,499	11,041
Depletion and accretion rate per Mcf	$	0.88		1.13	1.19

(d) Gas Reserve Information

Proved reserve quantities are based on estimates prepared by the independent petroleum engineering firm Wright & Company for the years ended December 31, 2015, 2014, and 2013 in accordance with guidelines established by the Securities and Exchange Commission (the “SEC”).

	Natural Gas
	Millions of Cubic Feet
*Proved developed and undeveloped reserves as of:*
January 1, 2013	64,250
Revisions	19,826
Extensions and discoveries	77,259
Acquisitions	145,430
Production	(7,082	)
December 31, 2013	299,683
Revisions of previous estimates	22,039
Extensions and discoveries	195,724
Acquisitions	3,558
Production	(14,683	)
December 31, 2014	506,321
Revisions of previous estimates	75,400
Extensions and discoveries	282,540
Divestitures	(1,671	)
Acquisitions	31,437
Production	(41,130	)
December 31, 2015	852,897
*Proved developed reserves as of:*
January 1, 2013	4,236
December 31, 2013	36,020
December 31, 2014	155,674
December 31, 2015	318,170
*Proved undeveloped reserves as of:*
January 1, 2013	60,014
December 31, 2013	263,663
December 31, 2014	350,647
December 31, 2015	534,727

All of the Company’s reserves as of December 31, 2013, 2014, and 2015 were located in the Appalachian Basin.

Total proved reserves increased 346,576 MMcf in 2015 primarily due to the following:

Revisions of previous estimates Previous estimates of proved reserves were revised upward primarily attributable to technical revisions associated with PUD inventory performance after conversion to PDP as well as the base PDP reserves being revised.

Extensions and discoveries Proved reserves increased primarily attributable to increased technical certainty in areas of existing leasehold ownership, ties to internal and external development activity.

Acquisitions Proved reserves increased primarily attributable to new leasehold acquisition from third parties allowing for higher certainty in inventory development.

Total proved reserves increased 206,638 MMcf in 2014 primarily due to the following:

Extensions and discoveries Proved reserves increased primarily attributable to increased technical certainty in areas of existing leasehold ownership, tied to internal and external development activity. Additional extensions tied to development and conversion from non-proven inventory to PDP reserves in year-end 2014.

Acquisitions Proved reserves increased primarily attributable to new leasehold acquisition from third parties allowing for higher certainty in inventory development.

Total proved reserves increased 235,433 MMcf in 2013 primarily due to the following:

Revisions of previous estimates Revisions to proved reserves were primarily attributable to increases in price; however, the Company did experience an increase due to technical revisions.

Extensions and discoveries Extensions and discoveries during the year ended December 31, 2013 resulted primarily from new proved undeveloped locations added during the year associated with the drilling of new wells.

Acquisitions Acquisitions during the year ended December 31, 2013 resulted from properties acquired from third parties.

(e) Standardized Measure of Discounted Future Net Cash Flows

The following summary sets forth the Standardized Measure (in thousands):

	December 31,
	2015			2014			2013
Future cash inflows	$	916,592		$	1,733,819		$	913,960
Future production costs	(222,386		)	(162,863		)	(87,329		)
Future development costs	(276,271		)	(282,455		)	(201,304		)
Future income tax expense(1)	—			—			—
Future net cash flows	417,935			1,288,501			625,327
10% annual discount for estimated timing of cash flows	(229,951		)	(690,854		)	(369,291		)
Standardized measure of Discounted Future Net Cash Flows	$	187,984		$	597,647		$	256,036

(1) Future net cash flows do not include the effects of income taxes on future revenues because Vantage II was a limited liability company to subject to entity-level income taxation as of December 31, 2015, 2014, and 2013. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Vantage II’s member. If Vantage II had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2015, 2014, and 2013 would have been $81.6 million, $243.2 million, and $63.3 million, respectively, net of the discount. The unaudited Standardized Measure at December 31, 2015, 2014, and 2013 would have been $106.3 million, $354.5 million, and $192.8 million, respectively.

(f) Changes in the Standardized Measure

A summary of the changes in the Standardized Measure are contained in the table below (in thousands):

	December 31,
	2015			2014			2013
Beginning of the period	$	597,649		$	256,035		$	25,132
Net changes in prices and production costs	(563,534		)	39,500			10,939
Net change in future development costs	76,285			(26,080		)	—
Sales, net of production costs	(58,282		)	(39,382		)	(18,489		)
Extensions	20,397			253,772			45,760
Acquisitions	1,232			5,462			144,735
Divestitures	(2,789		)				—
Revisions of previous quantity estimates	16,618			26,014			16,938
Previously estimated development costs incurred	67,943			30,105			3,873
Accretion of discount	59,765			25,604			2,513
Changes in timing and other	(27,300		)	26,619			24,634
End of period	$	187,984		$	597,649		$	256,035

(g) Impact of Pricing

The following average index prices were used in determining the Standardized Measure of:

	For the year ended December 31,
	2015		2014		2013
Natural Gas per Mcf	$	2.59	$	4.35	$	3.67

(12) Subsequent Events

The Company has evaluated subsequent events that occurred after December 31, 2015 through the audit report date, July 26, 2016. On February 9, 2016, the Company issued a Capital Contribution request in the aggregate amount of $10 million, due February 23, 2016. On March 30, 2016, the Company issued a Capital Contribution request in the aggregate amount of $10 million, due April 11, 2016. These amounts were funded by the Company’s Capital Members.

In May 2016, the Company loaned Vantage II Alpha, an affiliate formed by the Company’s Investors and Management Members, $10 million in connection with an acquisition. It is expected that Vantage II Alpha will merge with and into the Company by the end of the year.

On May 5, 2016, the Company issued a Capital Contribution request in the aggregate amount of $10 million. Institutional investors funded $10 million on May 6, 2016 and the remainder, which is less than $0.1 million, is due from the other Capital Members by May 19, 2016.

On May 10, 2016, the Company entered into the Eighth Amendment to Credit Agreement (Eighth Amendment), which included among other things, an equity cure right, applied retroactively to December 31, 2015, applicable to the Company’s covenants under its credit agreement.

On June 1, 2016, the Company entered into the Ninth Amendment to the Credit Agreement (Ninth Amendment), which stated the borrowing base to be $186 million compared to $166 million as of March 31, 2016.

EX-99.6 10 a17-22068_2ex99d6.htm EX-99.6

Exhibit 99.6

VANTAGE ENERGY II GROUP

Condensed Combined Balance Sheets

(Unaudited)

(In thousands)	September 30, 2016			December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	18,901		$	2,439
Accounts receivable (Note 2)	13,152			10,397
Accounts receivable—related party	—			1,100
Inventory	840			242
Prepayments and deposits	376			70
Commodity derivative assets	26,173			30,737
Total current assets	59,442			44,985
Property, plant, and equipment:
Oil and gas properties, full-cost method of accounting:
Proved	522,376			420,197
Unproved	553,883			187,509
Total oil and gas properties	1,076,259			607,706
Accumulated depletion, depreciation, and amortization	(340,444		)	(233,920		)
Net oil and gas properties	735,815			373,786
Gathering system, less accumulated depreciation of $8,020 and $5,551	104,809			59,970
Net property, plant, and equipment	840,624			433,756
Commodity derivative assets	23,261			7,957
Other assets	2,509			2,041
Total assets	$	925,836		$	488,739

Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities (Note 2)	$	47,712		$	39,016
Account payable—related party	33,199			—
Current portion of Revolving Credit Facility, net of unamortized deferred financing costs	141,599			—
Current portion of Second Lien Note Payable, net of unamortized deferred financing costs	99,050			—
Total current liabilities	321,560			39,016
Revolving Credit Facility, net of unamortized deferred financing costs	—			148,845
Second Lien Note Payable, net of unamortized deferred financing costs	—			98,196
Asset retirement obligations	3,468			2,091
Total liabilities	325,028			288,148
Contingently redeemable Founders’ units	1,125			498
Members’ equity:
Member contributions, net of issuance costs	723,077			299,662
Accumulated deficit	(123,394		)	(99,569		)
Total members’ equity	599,683			200,093
Total liabilities and members’ equity	$	925,836		$	488,739

The accompanying notes are an integral part of these unaudited condensed combined financial statements.

VANTAGE ENERGY II GROUP

Condensed Combined Statements of Operations

(Unaudited)

	Nine months ended September 30,
(In thousands)	2016			2015
Operating revenues:
Gas revenues	$	73,963		$	51,695
Midstream revenues	2,568			3,022
Gain on commodity derivatives	42,800			33,083
Total operating revenues	119,331			87,800
Operating expenses:
Production and ad valorem tax expense	1,669			1,115
Marketing and gathering expense	11,044			7,919
Lease operating and workover expense	2,623			4,366
Midstream operating expense	2,205			1,068
General and administrative expense	8,009			6,735
Depreciation, depletion, amortization, and accretion expense	28,457			32,165
Impairment of oil and gas properties	81,673			18,853
Total operating expenses	135,680			72,221
Operating (loss) income	(16,349		)	15,579
Other expenses:
Other (income) expense	(3		)	180
Interest expense	7,479			6,439
Total other expenses	7,476			6,619
Net (loss) income	$	(23,825	)	$	8,960

The accompanying notes are an integral part of these unaudited condensed combined financial statements.

VANTAGE ENERGY II GROUP

Condensed Combined Statements of Cash Flows

(Unaudited)

	Nine months ended September 30,
(In thousands)	2016			2015
Cash flows from operating activities:
Net (loss) income	$	(23,825	)	$	8,960
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	28,457			32,165
Accretion of original issue discount	712			646
Impairment of proved oil and gas properties	81,673			18,853
Gain on commodity derivatives	(42,800		)	(33,083		)
Settlements on commodity derivatives	32,235			17,213
Changes in operating assets and liabilities:
Accounts receivable	(2,755		)	3,568
Accounts receivable—related party	34,299			7,960
Inventory	(598		)	141
Prepayments and deposits	(306		)	13
Accounts payable and accrued liabilities	6,273			12,969
Net cash provided by operating activities	113,365			69,405
Cash flows from investing activities:
Oil and gas property exploration, acquisition, and development	(120,732		)	(98,885		)
Purchase of natural gas properties	(342,630		)	—
Gathering system additions	(48,044		)	(11,403		)
Water investment additions	(1,477		)	—
Other assets	(135		)	—
Net cash used in investing activities	(513,018		)	(110,288		)
Cash flows from financing activities:
Member contributions	424,042			—
Borrowings under Revolving Credit Facility	55,000			27,000
Principal payments on Revolving Credit Facility	(62,000		)	—
Deferred financing costs	(927		)	(447		)
Net cash provided by financing activities	416,115			26,553
Net change in cash and cash equivalents	16,462			(14,330		)
Cash and cash equivalents—beginning of period	2,439			21,185
Cash and cash equivalents—end of period	$	18,901		$	6,855
Supplemental disclosure of cash flow information:
Cash paid for interest	$	10,539		$	9,003
Accrued capital expenditures	$	(2,419	)	$	8,346
Capitalized asset retirement obligations	$	876		$	298

The accompanying notes are an integral part of these unaudited condensed combined financial statements.

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(1) Description of Business and Summary of Significant Accounting Policies

(a) Nature of Operations and Principles of Consolidation

Vantage Energy II, LLC (“Vantage II”) was organized as a limited liability company under the laws of the state of Delaware in 2012. Vantage II Alpha, LLC (“Vantage II Alpha”) was formed in May 2016 by the Investors and substantially all of the Management Members of Vantage II in connection with Vantage II’s entry into a purchase and sale agreement with a wholly owned subsidiary of Alpha Natural Resources, Inc. for the purchase of certain natural gas properties located in Greene County, Pennsylvania. Vantage II Alpha was formed as a transitory entity solely to facilitate the funding of the acquisition of the properties in an expeditious manner. Given the high degree of common ownership among the two entities, the accompanying condensed combined financial statements include the accounts of Vantage Energy II and its wholly-owned subsidiaries and Vantage II Alpha (collectively, the “Company”). All intercompany transactions have been eliminated in consolidation.

The Company is engaged in the exploration and exploitation of oil, natural gas and natural gas liquids, as well as natural gas acquisition, development, and gathering, with a focus in unconventional resources in the Appalachian Basin of the United States.

In June 2016, Vantage II Alpha closed on a purchase, funded with sponsor equity, of primarily unproved property which is reflected in these unaudited condensed combined financial statements based on the preliminary purchase price allocation. The assets purchased generally consist of approximately 27,400 net undeveloped acres, non-operating royalty mineral interests in 25 producing wells and certain related assets. Substantially all of the $340 million purchase price is expected to be allocated to unproved leasehold acreage acquired. Vantage II Alpha had no operations prior to this date.

The accompanying unaudited condensed combined financial statements of Vantage Energy II Group have been prepared by the Company’s management in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information. Accordingly, these financial statements do not include all of the information required by GAAP for annual financial statements. Therefore, these condensed combined financial statements should be read in conjunction with the audited financial statements and notes therein for the year ended December 31, 2015. The unaudited condensed combined financial statements included herein contain all adjustments which are, in the opinion of management, necessary to present fairly the Company’s financial position as of September 30, 2016 and December 31, 2015, and its condensed combined statements of operations and cash flows for the nine months ended September 30, 2016 and 2015. The condensed combined statements of operations for the nine months ended September 30, 2016 and 2015 are not necessarily indicative of the results to be expected for future periods.

(b) Use of Estimates

The preparation of these condensed combined financial statements requires management to make estimates and assumptions that affect the amounts reported in the condensed combined financial statements and accompanying notes.

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(1) Description of Business and Summary of Significant Accounting Policies (Continued)

As a result, actual amounts could differ from estimated amounts. By their nature, these estimates are subject to measurement uncertainty, and the effect on the condensed combined financial statements of changes in such estimates in future periods could be significant. Significant estimates with regard to the Company’s condensed combined financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows, the recoverability of unproved oil and gas properties, the calculation of depletion of oil and gas reserves, the estimated cost and timing related to asset retirement obligations, and the estimated fair value of derivative assets and liabilities.

Reserve estimates are, by their nature, inherently imprecise. The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

(c) Oil and Gas Properties

As of June 30, 2016, the carrying value of the Company’s oil and gas properties subject to the test exceeded the calculated value of the ceiling limitation. As a result, the Company recorded an impairment of $81.7 million for the six months ended June 30, 2016. No impairment was required for the three-month period ended September 30, 2016 as the calculated ceiling exceeded the carrying value of the Company’s oil and gas properties subject to the test. As the ceiling test calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter commodity prices in future quarters could result in a potentially lower ceiling value in future periods. Declines in commodity prices could result in future impairments.

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(1) Description of Business and Summary of Significant Accounting Policies (Continued)

(d) Adoption of New Accounting Principles

	Previously reported December 31, 2015		Adjustments			As adjusted December 31, 2015
	(In thousands)
Other assets	$	1,877	$	(498	)	$	1,379
Revolving Credit Facility	149,000		(155		)	148,845
Second Lien Note Payable	98,539		(343		)	98,196

(2) Balance Sheet Disclosures

Accounts receivable consist of the following:

	September 30, 2016		December 31, 2015
	(In thousands)
Joint interest billings	$	230	$	141
Revenue	12,922		10,256
Accounts receivable	$	13,152	$	10,397

Accounts payable and accrued liabilities consist of the following:

	September 30, 2016		December 31, 2015
	(In thousands)
Accrued capital expenditures	$	22,785	$	20,366
Accounts payable	10,607		5,643
Accrued revenue payable	4,466		2,748
Accrued marketing, gathering and transportation costs	4,224		4,077
Accrued general and administrative expenses	1,822		1,535
Accrued impact fees payable	1,486		1,911
Accrued interest payable	1,367		1,380
Other	955		1,356
Accounts payable and accrued liabilities	$	47,712	$	39,016

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(3) Debt

Revolving Credit Facility

Effective November 29, 2012, the Company secured a credit facility (the “Revolving Credit Facility”) with a group of bank lenders. Wells Fargo Bank, N.A. acts as administrative agent. Effective December 4, 2014 the Company amended and restated its Revolving Credit Facility to add a lien on the Vantage Midstream (as defined in Note 7) gas gathering system and add a midstream borrowing base. The maturity date of the Revolving Credit Facility is January 1, 2017. The Revolving Credit Facility has a maximum commitment of $500 million and as of September 30, 2016 and December 31, 2015, had a borrowing base of $186 million and $166 million, respectively. As of September 30, 2016 and December 31, 2015, the Company had net outstanding borrowings of $142 million and $149 million, respectively. On each borrowing, the Company has the election to pay interest at a Base rate or LIBOR. The margin on Base rate loans ranges from 0.75% to 1.75%. The margin on LIBOR loans ranges from 1.75% to 2.75%. The Company pays quarterly, a commitment fee ranging from 0.375% to 0.50% of the unused borrowing base. The Company elected to pay interest based on LIBOR, plus the applicable margin, which was 3.78% in total as of September 30, 2016.

As of September 30, 2016, the Revolving Credit Facility was collateralized by all of the Company’s assets, including its 50% undivided operated interest in the Vantage Midstream assets (as defined in Note 7).

The Revolving Credit Facility contains certain financial covenants, including maintenance of a minimum current ratio and a maximum leverage ratio. As of September 30, 2016, the Company was in compliance with all financial covenants.

Second Lien Note Payable

In May 2014, the Company entered into a second lien note payable (“Second Lien Note Payable”) with a face amount of $100 million, maturing on May 8, 2017. The Company has the election to pay interest at a Base rate or Eurodollar LIBOR. The margin on Base rate loans is 6.50%. The margin on LIBOR loans is 7.50%. As of September 30, 2016, the stated interest rate was 8.5%, and the Company had net outstanding borrowings of $99 million. The Second Lien Note Payable contains an optional prepayment provision that enables the Company to prepay the Second Lien Note Payable at par. The Second Lien Note Payable was issued with an original issue discount of $2.8 million, which has been classified as a reduction to the note balance. The discount is amortized over the term of the note using the effective interest method.

As of September 30, 2016 and December 31, 2015, the Second Lien Note Payable was collateralized by a second lien interest in all of the Company’s assets, including its 50% operated interest in the Vantage Midstream assets, and contains certain financial covenants. These covenants include maintenance of a maximum leverage ratio. As of September 30, 2016, the Company was in compliance with all financial covenants.

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(3) Debt (Continued)

Borrowings outstanding as of September 30, 2016:

	As of September 30, 2016
(in thousands)	Revolving Credit Facility			Second Lien Note Payable
Principal	$	142,000		$	100,000
Net unamortized premium	—			(749		)
Net unamortized debt issuance costs	(401		)	(201		)
Total debt	141,599			99,050
Less: Current portion of long-term debt	141,599			99,050
Total long-term debt	$	—		$	—

The Revolving Credit Facility matures on January 1, 2017. The Company expects to repay and retire the Revolving Credit Facility and the Second Lien Note Payable in connection with the net proceeds from a future monetization event, undrawn capital commitments and/or cash on hand. Additionally, the Company plans to obtain new financing following the anticipated corporate reorganization, contemporaneous with a monetization event. In addition, the Company expects that it will be able to secure incremental equity commitments or other sources of capital, including debt, if necessary, from its current equity investors, other investors, or lenders to address any shortfall. The Company’s current equity investors continue to be supportive of the Company’s long-term growth and financing strategy.

Maturities of outstanding borrowings as of September 30, 2016 are as follows:

(in thousands)	Revolving Credit Facility		Second Lien Note Payable
Year ending December 31, 2017	$	142,000	$	100,000
Total future maturities of outstanding borrowings	$	142,000	$	100,000

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(4) Fair Value Measurements

Authoritative guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1: Quoted prices are available in active markets for identical assets or liabilities.

Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability.

Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

The assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s policy is to recognize transfers in and/or out of the fair value hierarchy as of the end of the reporting period in which the event or change in circumstances caused the transfer. The Company has consistently applied the valuation techniques discussed below in all periods presented. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 by level within the fair value hierarchy (in thousands):

	September 30, 2016
	Fair value measurements
Description	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivative instruments	$	—	$	49,434	$	—	$	49,434

	December 31, 2015
	Fair value measurements
Description	Level 1		Level 2		Level 3		Total
Assets:
Commodity derivative instruments	$	—	$	38,694	$	—	$	38,694

The Company’s commodity derivative instruments consist of variable-to-fixed price swaps. The fair values of the swap agreements are determined under the income valuation technique using a discounted cash flow model. The valuation model requires a variety of inputs, including contractual terms, published forward prices, and discount rates, as appropriate. The Company’s estimates of fair value of commodity derivative instruments include consideration of the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within Level 2 of the fair value hierarchy. The counterparties on the Company’s derivative instruments are the same financial institutions that hold the Revolving Credit Facility (Note 3). Accordingly, the Company is not required to post collateral on these derivatives since the bank is secured by the Company’s oil and gas properties.

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(5) Asset Retirement Obligations

As of September 30, 2016, the Company’s asset retirement obligation was $3.5 million. Liabilities incurred, accretion expense and revisions to the Company’s estimates were not material for the nine months ended September 30, 2016.

(6) Commodity Derivative Instruments

	Condensed consolidated	September 30, 2016
	balance sheet classification	Gross recognized		Offset			Net recognized
		(In thousands)
Commodity derivative assets:
Commodity contracts	Current assets	$	26,259	$	(86	)	$	26,173
Commodity contracts	Noncurrent assets	28,247		(4,986		)	23,261
Commodity derivative liabilities:
Commodity contracts	Current liabilities	$	86	$	(86	)	$	—
Commodity contracts	Noncurrent liabilities	4,986		(4,986		)	—

	Condensed consolidated	December 31, 2015
	balance sheet classification	Gross recognized		Offset			Net recognized
		(In thousands)
Commodity derivative assets:
Commodity contracts	Current assets	$	30,868	$	(131	)	$	30,737
Commodity contracts	Noncurrent assets	7,998		(41		)	7,957
Commodity derivative liabilities:
Commodity contracts	Current liabilities	$	131	$	(131	)	$	—
Commodity contracts	Noncurrent liabilities	41		(41		)	—

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(6) Commodity Derivative Instruments (Continued)

The table below summarizes the realized and unrealized gains, net related to the Company’s commodity derivative instruments for the nine months ended September 30, 2016 and 2015, recorded as operating revenues in the accompanying condensed combined statement of operations.

	Nine months ended September 30,
	2016		2015
	(In thousands)
Commodity derivative instruments:
Realized gains on commodity derivatives, net	$	32,235	$	17,213
Unrealized gains on commodity derivatives, net	10,565		15,870
Gain on commodity derivatives	$	42,800	$	33,083

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s commodity derivative instruments are subject to significant fluctuations from period to period.

(7) Related Party Transactions

(a) Gas Gathering System Operating Agreement

In connection with the Joint Development Agreement with Vantage Energy, LLC (“Vantage I”), the Company, through its wholly owned subsidiary, Vista Gathering, LLC (hereinafter referred to as “Vantage Midstream”), became the operator of the gas gathering and compression assets. Pursuant to a Gathering System Operating Agreement, dated August 2, 2012, between the Company and Vantage I, the Company and Vantage I are to pay their respective 50% shares of the gas gathering system operating and development costs, as well as their incurred gas gathering and compression fees. The Company was charged gas gathering and compression fees by Vantage Midstream for the wells that it operates of approximately $23.1 million and $17.1 million for the nine months ended September 30, 2016 and 2015, respectively.

(b) Water Investment

Pursuant to the Water Services and Supply Agreement, Vantage Midstream provides water services required in the Company’s drilling operations. For the nine months ended September 30, 2016, the Company paid water supply and transportation fees to Vantage Midstream of $15.7 million.

(c) Management Services Agreement

In August 2012, the Company and Vantage I entered into a Management Services Agreement (“MSA”) whereby Vantage I is to provide certain executive management, administrative, accounting, finance, engineering, land, and information technology assistance to the Company. In exchange for providing these services, the Compny will pay Vantage I a fee (the “MSA Fee”). The MSA Fee is based upon the gross general and administrative expenses incurred by Vantage I multiplied by a ratio of the relative capital expenditures and oil and natural gas production volumes of the Company and Vantage I. Certain adjustments are made to this calculation to reflect the allocation of general and

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(7) Related Party Transactions (Continued)

administrative expenses to Vantage Midstream. The Company recorded gross general and administrative expenses incurred under the MSA of approximately $11.3 million and $8.6 million for the nine months ended September 30, 2016 and 2015, respectively.

(d) MIU Notes Receivable

In December 2014, the Company made loans to certain employees in the form of notes receivable. Interest accrues on the notes at 0.34% per annum, and the notes mature upon the earlier to occur of: 1) December 1, 2017; 2) consummation of Monetization Event (as defined); or 3) fifteen days after the date of voluntary termination of employment by the employee or termination by the Company for cause. As of September 30, 2016, the notes outstanding were approximately $1.3 million and are classified in other assets in the accompanying condensed combined balance sheets. The notes are collateralized by a first lien interest in the employees’ interest in each employees’ Management Incentive Units (“MIUs”) and all potential dividends and distributions and a second lien on all other personal assets. Interest income was not material for the nine months ended September 30, 2016 and 2015, respectively.

(8) Commitments and Contingencies

The Company leases various compressors in Pennsylvania under noncancelable operating leases that expire at various dates through 2017. The associated future remaining obligations of such leases was not material as of September 30, 2016.

On April 17, 2014, the Company entered into a 20,000 Mmbtu/d firm marketing agreement to market gas production associated with volumes produced in the Marcellus Shale. The agreement began in October 2014 and continues through October 2020. Under the contract, the Company is paid based on TETCO M-2 pricing with the ability to share in downstream price upside when market conditions allow.

VANTAGE ENERGY II GROUP

Notes to Condensed Combined Financial Statements

(Unaudited)

(9) Capital Structure

Class I Units

The Company and Vantage II Alpha are authorized to issue as many Class I Units as their respective boards of managers approves. Total capital commitments and contributions associated with outstanding Class I Units are as follows:

	September 30, 2016		December 31, 2015
	(In thousands)
Institutional investors (commitment—$775,000)	$	722,143	$	298,804
Founders (commitment—$1,303)	1,125		498
Other employees/friends and family (commitment—$1,225)	1,044		967
Total (total commitment—$777,528)	$	724,312	$	300,269

Management Incentive Units

The Company has issued management incentive units to certain employees. The management incentive units participate only in distributions in liquidation events, meeting requisite financial thresholds after Capital Interests have recovered their investment, and special allocation amounts. Management incentive units have no voting rights. Compensation expense for these awards will be recognized when all performance, market, and service conditions are probable of being satisfied (in general, upon a liquidating event), which has not occurred as of September 30, 2016. Accordingly, no value was assigned to the interests when issued.

(10) Subsequent Events

The Company has evaluated subsequent events that occurred after September 30, 2016 through, September 19, 2017. Any material subsequent events that occurred during this time have been properly recognized or disclosed in these condensed combined consolidated financial statements or the notes to the condensed combined consolidated financial statements. Effective October 19, 2016, the Company was acquired by Rice Energy Inc.