10-Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2015
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the transition period from_______ to_______              
Commission File Number: 001-36273
Rice Energy Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
46-3785773
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
400 Woodcliff Drive
Canonsburg, Pennsylvania
 
15317
(Address of principal executive offices)
 
(Zip code)
 
 
 
(724) 746-6720
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þYes ¨No
 
 
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þYes ¨No
 
 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ¨
 
Accelerated filer ¨
Non-accelerated filer þ
 
Smaller reporting company ¨
(Do not check if a smaller reporting company)
 
 
 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨Yes þNo
 
 
 
Number of shares of the registrant’s common stock outstanding at November 2, 2015: 136,383,510 shares





RICE ENERGY INC.
QUARTERLY REPORT ON FORM 10-Q
TABLE OF CONTENTS
 
 
Page
 
 
PART I
 
 
PART II
 
 


2



Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q (the “Quarterly Report”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report, regarding our strategy, future operations, financial position, estimated revenues and income/losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 (the “2014 Annual Report”) on file with the Securities and Exchange Commission (the “SEC”).
Forward-looking statements may include statements about our:
business strategy;
reserves;
financial strategy, liquidity and capital required for our development program;
realized natural gas, NGLs and oil prices;
timing and amount of future production of natural gas, NGLs and oil;
hedging strategy and results;
future drilling plans;
competition and government regulations;
pending legal or environmental matters;
marketing of natural gas, NGLs and oil;
leasehold or business acquisitions;
costs of developing our properties and conducting our gathering and other midstream operations;
consummation of our planned midstream joint venture with Gulfport Energy Corporation (“Gulfport”);
operations of Rice Midstream Partners LP;
general economic conditions;
credit and capital markets;
uncertainty regarding our future operating results; and
plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures; and the other risks described under the heading “Item 1A. Risk Factors” in our 2014 Annual Report.
Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, and NGLs and oil that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report.

3



Commonly Used Defined Terms
As used in the Quarterly Report, unless the context indicates or otherwise requires, the following terms have the following meanings:
“Rice Energy,” the “Company,” “we,” “our,” “us” or like terms refer collectively to Rice Energy Inc. and its consolidated subsidiaries, including Rice Drilling B;
“Rice Drilling B” refers to Rice Drilling B LLC, a wholly-owned subsidiary of Rice Energy;
“RMP” or the “Partnership” refer to Rice Midstream Partners LP (NYSE: RMP);
“Rice Midstream OpCo” refers to Rice Midstream OpCo LLC, a wholly-owned subsidiary of RMP;
“Midstream Holdings” refers to Rice Midstream Holdings LLC, a wholly-owned subsidiary of Rice Energy; and
“Marcellus joint venture” refers collectively to Alpha Shale Resources, LP and its general partner, Alpha Shale Holdings, LLC.


4



PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Rice Energy Inc.
Condensed Consolidated Balance Sheets
(Unaudited)
(in thousands)
September 30, 2015
 
December 31, 2014
Assets
 
 
 
Current assets:
 
 
 
Cash
$
216,084

 
$
256,130

Accounts receivable
224,336

 
199,900

Prepaid expenses and other
5,874

 
3,427

Derivative assets
157,476

 
133,034

Total current assets
603,770

 
592,491

 
 
 
 
Gas collateral account
4,036

 
3,995

Property, plant and equipment, net
3,101,313

 
2,461,331

Deferred financing costs, net
30,078

 
25,103

Goodwill
334,050

 
334,050

Intangible assets, net
46,568

 
47,791

Derivative assets
105,795

 
63,188

Total assets
$
4,225,610

 
$
3,527,949

 
 
 
 
Liabilities and stockholders’ equity
 
 
 
Current liabilities:
 
 
 
Current portion of long-term debt
$

 
$
680

Accounts payable
125,633

 
152,329

Royalties payable
54,141

 
37,172

Accrued capital expenditures
98,686

 
108,290

Accrued interest
38,645

 
9,375

Leasehold payable
21,907

 
30,702

Deferred tax liabilities
63,486

 
54,688

Other accrued liabilities
46,403

 
43,439

Total current liabilities
448,901

 
436,675

 
 
 
 
Long-term liabilities:
 
 
 
Long-term debt
1,521,128

 
900,000

Leasehold payable
7,010

 
4,279

Deferred tax liabilities
214,716

 
209,218

Other long-term liabilities
16,528

 
12,609

Total liabilities
2,208,283

 
1,562,781

 
 
 
 
Stockholders’ equity:
 
 
 
Common stock, $0.01 par value; authorized - 650,000,000 shares; issued and outstanding - 136,383,293 shares and 136,280,766 shares, respectively
1,364

 
1,363

Preferred stock, $0.01 par value; authorized - 50,000,000 shares; none issued

 

Additional paid in capital
1,422,590

 
1,368,001

Accumulated earnings
142,767

 
153,346

Stockholders’ equity before noncontrolling interest
1,566,721

 
1,522,710

Noncontrolling interests in consolidated subsidiaries
450,606

 
442,458

Total liabilities and stockholders’ equity
$
4,225,610

 
$
3,527,949

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

5


Rice Energy Inc.
Condensed Consolidated Statements of Operations
(Unaudited)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands, except share data)
2015
 
2014
 
2015
 
2014
Operating revenues:
 
 
 
 
 
 
 
Natural gas, oil and natural gas liquids (“NGL”) sales
$
130,145

 
$
67,831

 
$
327,947

 
$
246,816

Firm transportation sales, net
88

 
9,733

 
3,353

 
11,851

Gathering, compression and water distribution
13,388

 
1,563

 
34,755

 
2,878

Total operating revenues
143,621

 
79,127

 
366,055

 
261,545

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Lease operating
12,325

 
4,553

 
35,006

 
16,406

Gathering, compression and transportation
24,248

 
7,992

 
55,510

 
22,464

Production taxes and impact fees
1,955

 
1,114

 
5,103

 
2,624

Exploration
830

 
623

 
1,925

 
1,582

Midstream operation and maintenance
4,831

 
1,729

 
10,963

 
3,564

Incentive unit (income) expense
(686
)
 
26,418

 
45,870

 
101,695

Stock compensation expense
4,214

 
2,058

 
11,681

 
3,274

Acquisition expense

 
2,246

 

 
2,246

General and administrative
24,113

 
10,458

 
62,028

 
36,733

Depreciation, depletion and amortization
89,275

 
33,853

 
227,996

 
91,912

Amortization of intangible assets
408

 
408

 
1,224

 
748

Other (income) expense
(265
)
 

 
3,624

 

Total operating expenses
161,248

 
91,452

 
460,930

 
283,248

 
 
 
 
 
 
 
 
Operating loss
(17,627
)
 
(12,325
)
 
(94,875
)
 
(21,703
)
Interest expense
(23,949
)
 
(15,754
)
 
(63,437
)
 
(38,737
)
Gain on purchase of Marcellus joint venture

 

 

 
203,579

Other income (loss)
698

 
(216
)
 
1,894

 
180

Gain on derivative instruments
127,072

 
36,935

 
184,729

 
5,357

Amortization of deferred financing costs
(1,313
)
 
(707
)
 
(3,722
)
 
(1,728
)
Loss on extinguishment of debt

 
(790
)
 

 
(3,934
)
Write-off of deferred financing costs

 

 

 
(6,896
)
Equity loss of joint ventures

 

 

 
(2,656
)
Income before income taxes
84,881

 
7,143

 
24,589

 
133,462

Income tax expense
(19,797
)
 
(14,005
)
 
(18,335
)
 
(18,787
)
Net income (loss)
65,084

 
(6,862
)
 
6,254

 
114,675

Less: Net income attributable to noncontrolling interests
(6,134
)
 

 
(16,833
)
 

Net income (loss) attributable to Rice Energy Inc.
$
58,950

 
$
(6,862
)
 
$
(10,579
)
 
$
114,675

 
 
 
 
 
 
 
 
Weighted average number of shares of common stock—basic
136,381,909

 
132,269,081

 
136,330,198

 
125,411,524

Weighted average number of shares of common stock—diluted
136,521,828

 
132,269,081

 
136,330,198

 
125,678,095

Earnings (loss) per share—basic
$
0.43

 
$
(0.05
)
 
$
(0.08
)
 
$
0.91

Earnings (loss) per share—diluted
$
0.43

 
$
(0.05
)
 
$
(0.08
)
 
$
0.91

 
 
 
 
 
 
 
 
Pro forma income tax benefit
 
 
 
 
 
 
$
5,560

Pro forma net income


 
 
 
 
 
$
120,235

Pro forma earnings per share—basic
 
 
 
 
 
 
$
0.96

Pro forma earnings per share—diluted
 
 
 
 
 
 
$
0.96

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

6


Rice Energy Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
 
Nine Months Ended September 30,
(in thousands)
2015
 
2014
Cash flows from operating activities:
 
 
 
Net income
$
6,254

 
$
114,675

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
227,996

 
91,912

Amortization of deferred financing costs
3,722

 
1,728

Amortization of intangibles
1,224

 
748

Incentive unit expense
45,870

 
101,695

Write-off of deferred financing costs

 
6,896

Loss on extinguishment of debt

 
3,934

Stock compensation expense
11,681

 
3,274

Derivative instruments fair value gain
(184,729
)
 
(5,357
)
Cash receipts (payments) for settled derivatives
117,680

 
(20,782
)
Deferred income tax expense
14,296

 
18,787

Fair value gain on purchase of Marcellus joint venture

 
(203,579
)
Equity loss of joint ventures

 
2,656

Changes in operating assets and liabilities:
 
 
 
(Increase) in accounts receivable
(24,408
)
 
(87,410
)
(Increase) in prepaid expenses and other assets
(3,200
)
 
(2,165
)
(Decrease) in accounts payable
(2,136
)
 
(6,799
)
Increase in accrued liabilities and other
39,177

 
37,861

Increase in royalties payable
16,969

 
11,605

Net cash provided by operating activities
270,396

 
69,679

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures for property and equipment
(919,906
)
 
(642,408
)
Acquisition of Marcellus joint venture, net of cash acquired

 
(82,766
)
Acquisition of Momentum assets

 
(111,447
)
Acquisition of Greene County assets

 
(329,469
)
Proceeds from sale of interest in gas properties
10,201

 
11,542

Net cash used in investing activities
(909,705
)
 
(1,154,548
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from borrowings
635,932

 
900,000

Repayments of debt obligations
(16,390
)
 
(498,983
)
Restricted cash for convertible debt

 
8,268

Debt issuance costs
(8,696
)
 
(19,401
)
Offering costs related to the Partnership’s IPO
(129
)
 

Distributions to the Partnership’s public unitholders
(11,454
)
 

Costs relating to IPO

 
(1,412
)
Proceeds from conversion of warrants

 
1,975

Proceeds from issuance of common stock sold in IPO, net of underwriting fees

 
598,500

Costs relating to August 2014 Equity Offering

 
(784
)

7


Proceeds from issuance of common stock in August 2014 Equity Offering, net of underwriting fees

 
197,072

Net cash provided by financing activities
599,263

 
1,185,235

 
 
 
 
Net (decrease) increase in cash
(40,046
)
 
100,366

Cash at the beginning of the year
256,130

 
31,612

Cash at the end of the period
$
216,084

 
$
131,978

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

8


Rice Energy Inc.
Condensed Consolidated Statements of Equity
(Unaudited)
(in thousands)
 
Common Stock ($0.01 par)
 
Additional Paid-In Capital
 
Accumulated (Deficit) Earnings
 
Total
Balance, January 1, 2014
 
$
880

 
$
362,875

 
$
(65,108
)
 
$
298,647

Shares of common stock issued in IPO, net of offering costs
 
300

 
593,113

 

 
593,413

Shares of common stock issued in purchase of Marcellus joint venture
 
95

 
221,905

 

 
222,000

Conversion of restricted units into shares of common stock at IPO
 

 
36,306

 

 
36,306

Conversion of convertible debentures into shares of common stock after IPO
 
6

 
6,599

 

 
6,605

Conversion of warrants into shares of common stock after IPO
 
7

 
1,968

 

 
1,975

Shares of common stock issued in August 2014 Equity Offering, net of offering costs
 
75

 
196,213

 

 
196,288

Incentive unit compensation
 

 
101,695

 

 
101,695

Stock compensation
 

 
3,274

 

 
3,274

Tax impact of initial public offering and corporate reorganization
 

 
(162,320
)
 

 
(162,320
)
Consolidated net income
 

 

 
114,675

 
114,675

Balance, September 30, 2014
 
$
1,363

 
$
1,361,628

 
$
49,567

 
$
1,412,558

(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, 2015
$
1,363

 
$
1,368,001

 
$
153,346

 
$
1,522,710

 
$
442,458

 
$
1,965,168

Incentive unit compensation

 
45,870

 

 
45,870

 

 
45,870

Stock compensation
1

 
8,719

 

 
8,720

 
2,898

 
11,618

Distributions to the Partnership's public unitholders

 

 

 

 
(11,454
)
 
(11,454
)
Offering costs related to the Partnerships IPO

 

 

 

 
(129
)
 
(129
)
Consolidated net income (loss)

 

 
(10,579
)
 
(10,579
)
 
16,833

 
6,254

Balance, September 30, 2015
$
1,364

 
$
1,422,590

 
$
142,767

 
$
1,566,721

 
$
450,606

 
$
2,017,327

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

9


Rice Energy Inc.
Notes to Condensed Consolidated Financial Statements
(Unaudited)
1.
Basis of Presentation
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. 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 September 30, 2015 and December 31, 2014 and its condensed consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014 and of cash flows for the nine months ended September 30, 2015 and 2014.
A corporate reorganization occurred concurrently with the completion of the Company’s initial public offering (“IPO”) on January 29, 2014. As a part of this corporate reorganization, the Company acquired all of the outstanding membership interests in Rice Energy Appalachia LLC (“Rice Appalachia”) and Rice Drilling B LLC (“Rice Drilling B”) (other than those already held by Rice Appalachia) in exchange for shares of the Company’s common stock. This reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented.
The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries. Rice Midstream Holdings LLC, a wholly-owned subsidiary of the Company (“Rice Midstream Holdings”), owns a 50.0% interest in Rice Midstream Partners LP, a publicly-traded subsidiary of the Company (the “Partnership”). The financial results of the Partnership are consolidated and the remaining 50.0% interest in the Partnership is reflected as noncontrolling interest in the condensed consolidated financial statements. All intercompany transactions have been eliminated in consolidation.
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, 2014, as filed with the Securities and Exchange Commission (“SEC”) by the Company in its Annual Report on Form 10-K (the “2014 Annual Report”). Certain prior period financial statement amounts have been reclassified to conform to current period presentation.
2.
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. There was no allowance recorded for any of the periods presented in the condensed consolidated financial statements. Accounts receivable as of September 30, 2015 and December 31, 2014 are detailed below.
(in thousands)
September 30, 2015
 
December 31, 2014
Joint interest
$
133,062

 
$
125,300

Natural gas sales
84,236

 
72,206

Other
7,038

 
2,394

Total accounts receivable
$
224,336

 
$
199,900


10


3.
Long-Term Debt
Long-term debt consists of the following as of September 30, 2015 and December 31, 2014:
(in thousands)
September 30, 2015
 
December 31, 2014
Long-term Debt
 
 
 
Senior Notes Due 2022 (a)
$
900,000

 
$
900,000

Senior Notes Due 2023 (b) 
397,128

 

Senior Secured Revolving Credit Facility (c)

 

Midstream Holdings Revolving Credit Facility (d)
152,000

 

RMP Revolving Credit Facility (e)
72,000

 

Other

 
680

Total debt
$
1,521,128

 
$
900,680

Less current portion

 
680

Long-term debt
$
1,521,128

 
$
900,000

Senior Notes
6.25% Senior Notes Due 2022 (a)
On April 25, 2014, the Company 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 of 1933, as amended (the “Securities Act”), which resulted in net proceeds of $882.7 million, after deducting expenses and the initial purchasers’ discounts 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. 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 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 2022 Notes remains outstanding after such redemption. Prior to May 1, 2017, 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 to the redemption date. Upon the occurrence of a Change of Control (as defined in the indenture governing the 2022 Notes), 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 to the date of purchase. 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 to the redemption date.
7.25% Senior Notes Due 2023 (b)
On March 26, 2015, the Company 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 of $389.3 million, after deducting expenses and the initial purchasers’ discounts of approximately $10.7 million. The Company used a portion of the net proceeds for general corporate purposes, including capital expenditures, and intends to use the remaining 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. For the three and nine months ended September 30, 2015, the Company recorded $0.1 million and $0.2 million, respectively, of amortization of the debt discount as interest expense using the effective interest 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 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, 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 to the redemption date. Upon the occurrence of a Change of Control (as defined in the indenture governing the 2023 Notes), unless the Company has given notice to redeem the 2023 Notes,

11


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 to the date of purchase. 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 to the redemption date.
In connection with the issuance and sale of the 2023 Notes, the Company and the Company’s restricted subsidiaries (the “Guarantors”) entered into a registration rights agreement with the initial purchasers, dated March 26, 2015. Pursuant to the registration rights agreement, the Company and the Guarantors have agreed to file a registration statement with the SEC so that holders of the 2023 Notes can exchange the 2023 Notes for registered notes with substantially identical terms. The Company and the Guarantors will use commercially reasonable efforts to cause the exchange to be completed within 365 days after the issuance of the 2023 Notes. The Company and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the 2023 Notes within the specified time periods.
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 Guarantors. The indentures governing the Notes provide that the guarantees of the Notes will be released under certain circumstances, including:
in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as defined in the indentures governing the Notes) of the Company;
in connection with any sale or other disposition of the capital stock of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, such that, immediately after giving effect to such transaction, such Guarantor would no longer constitute a subsidiary of the Company;
if the Company designates any Restricted Subsidiary that is a Guarantor to be an unrestricted subsidiary in accordance with the indentures governing the Notes;
upon legal defeasance or satisfaction and discharge of the indentures governing the Notes; or
if such Guarantor ceases to guarantee any other indebtedness of the Company or a Guarantor under a credit facility, provided no Event of Default (as defined in the indentures governing the Notes) has occurred and is continuing.
The indentures governing the Notes restrict the Company’s ability and the ability of its restricted 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 the Company’s 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 the Company and its restricted subsidiaries will cease to be subject to such covenants.
The indentures governing the Notes contain customary events of default, including:
default in any payment of interest on any Note when due, continued for 30 days;
default in the payment of principal of or premium, if any, on any Note when due;
failure by the Company to comply with its other obligations under the indentures governing the Notes, in certain cases subject to notice and grace periods;
payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the indentures governing the Notes) in the aggregate principal amount of $25.0 million or more;

12


certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the indentures governing the Notes) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;
failure by the Company or Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; and
any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.
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. As of September 30, 2015, the borrowing base under the Third Amended and Restated Credit Agreement (as amended, the “Amended Credit Agreement”) governing the Senior Secured Revolving Credit Facility was $650.0 million and the sublimit for letters of credit was $175.0 million. The Company had zero borrowings outstanding and $125.4 million in letters of credit outstanding under its Amended Credit Agreement as of September 30, 2015, resulting in availability of $524.6 million. On October 30, 2015, a scheduled redetermination occurred as a result of which the borrowing base of the Senior Secured Revolving Credit Facility was increased from $650.0 million to $750.0 million and the sublimit for letters of credit increased from $175.0 million to $250.0 million. The next redetermination of the borrowing base is scheduled for April 1, 2016. The maturity date of the Senior Secured Revolving Credit Facility is January 29, 2019.
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 150 to 250 basis points, depending on the percentage of 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 50 to 150 basis points, depending on the percentage of borrowing base utilized.
The Amended Credit Agreement is secured by liens on at least 80% 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 Rice 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 Company’s obligations under the Amended Credit Agreement are guaranteed by such restricted subsidiaries. The Amended Credit Agreement contains restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things:
incur additional indebtedness;
sell assets;
make loans to others;
make investments;
enter into mergers;
make or declare dividends;
hedge future production or interest rates;
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
The Amended Credit Agreement also requires the Company to maintain certain financial ratios, which are measured at the end of each calendar quarter:
a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and
a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as such term is defined in the Amended Credit Agreement) based on the trailing 12 month period to consolidated interest expense, of not less than 2.5 to 1.0.

13


The Company was in compliance with such covenants and ratios effective as of September 30, 2015.
Midstream Holdings Revolving Credit Facility (d)
On December 22, 2014, Rice Midstream Holdings LLC (“Rice 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 September 30, 2015, Rice Midstream Holdings had $152.0 million of borrowings outstanding and $0.1 million letters of credit under this facility. The 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 revolving credit facility, Rice 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. Rice 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, Rice Midstream Holdings and its restricted subsidiaries (which do not include the Partnership, Rice Midstream Management LLC, a Delaware limited liability company and general partner of the Partnership, or the Company and its subsidiaries other than Rice Midstream Holdings).
The Midstream Holdings Revolving Credit Facility limits the ability of Rice Midstream Holdings 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 Midstream Holdings Revolving Credit Facility also requires Rice Midstream Holdings to maintain the following financial ratios:
an interest coverage ratio, which is the ratio of Rice Midstream Holding’s 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 the 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.
Rice Midstream Holdings was in compliance with such covenants and ratios effective as of September 30, 2015.

14


RMP Revolving Credit Facility (e)
On December 22, 2014, Rice Midstream OpCo LLC, a wholly-owned subsidiary of the Partnership (“Rice Midstream OpCo”), 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 with a maximum credit amount 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. As of September 30, 2015, Rice Midstream OpCo had $72.0 million of borrowings outstanding and no letters of credit under this facility. 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.
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 revolving credit facility, the Partnership may elect to borrow in Eurodollars or at the base rate. Eurodollar loans bears interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 175 to 275 basis points, depending on the leverage ratio then in effect. Base rate loans bears 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 75 to 175 basis points, depending on the leverage ratio then in effect. The Partnership also pays a commitment fee based on the undrawn commitment amount ranging from 35 to 50 basis points.
The RMP Revolving Credit Facility is secured by mortgages and other security interests on substantially all of the properties of, and guarantees from, the Partnership and its restricted subsidiaries.
The RMP Revolving Credit Facility limits the ability of the Partnership 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 the Partnership to maintain the following financial ratios:
an interest coverage ratio, which is the ratio of the Partnership’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;
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 the Partnership 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 Partnership was in compliance with such covenants and ratios effective as of September 30, 2015.

15


Expected Aggregate Maturities
Expected aggregate maturities of the notes payable as of September 30, 2015 are as follows (in thousands):
Remainder of Year Ending December 31, 2015
$

Year Ending December 31, 2016

Year Ending December 31, 2017

Year Ending December 31, 2018

Year Ending December 31, 2019 and Beyond
1,521,128

Total
$
1,521,128

Interest paid in cash was approximately $2.8 million and $33.9 million for the three and nine months ended September 30, 2015, respectively, and $1.2 million and $10.9 million for the three and nine months ended September 30, 2014, respectively.
4.
Derivative Instruments
The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. The Company’s derivative counterparties share in the Amended Credit Agreement collateral. The Company’s hedging activities are intended to support natural gas prices at targeted levels and to manage its exposure to natural gas price fluctuations. To mitigate the potential negative impact on the Company’s cash flow caused by changes in natural gas prices, the Company has entered into financial commodity derivative contracts in the form of swaps, zero cost collars, calls, puts and basis swaps to ensure that it receives minimum prices for a portion of its future natural gas production when management believes that favorable future prices can be secured. 
The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in income currently. As of September 30, 2015, the Company has entered into derivative instruments with various financial institutions, fixing the price it receives for a portion of its natural gas through December 31, 2022, as summarized in the following table:
Swap Contract Expiration
MMBtu/day
 
Weighted
Average Price
Year ending December 31, 2015:
 
 
 
      NYMEX
220,000

 
$
4.08

      TCO
42,000

 
$
3.30

      Dominion South
58,000

 
$
2.45

 
 
 
 
Year ending December 31, 2016:
 
 
 
      NYMEX
363,000

 
$
3.74

      Dominion South
31,000

 
$
2.62

 
 
 
 
Year ending December 31, 2017:
 
 
 
      NYMEX
140,000

 
$
3.70

 
 
 
 
Year ending December 31, 2018:
 
 
 
      NYMEX
5,000

 
$
3.60

 
 
 
 
Year ending December 31, 2019:
 
 
 
      NYMEX
20,000

 
$
3.23


16


Collar Contract Expiration
MMBtu/day
 
Floor/Ceiling
Year ending December 31, 2015:
 
 
 
      NYMEX
183,000

 
$3.97/$4.65
 
 
 
 
Year ending December 31, 2016:
 
 
 
      NYMEX
50,000

 
$2.91/$3.60
 
 
 
 
Year ending December 31, 2017:
 
 
 
      NYMEX
220,000

 
$3.13/$3.61
 
 
 
 
Year ending December 31, 2018:
 
 
 
      NYMEX
280,000

 
$3.16/$3.62
 
 
 
 
Year ending December 31, 2019:
 
 
 
      NYMEX
130,000

 
$3.09/$3.60

17


Basis Contract Expiration
MMBtu/day
 
Swap ($/MMBtu)
Year ending December 31, 2015:
 
 
 
      TCO
40,000

 
$
(0.33
)
      Dominion South
11,000

 
$
(1.12
)
      M2
12,000

 
$
(0.94
)
      TETCO ELA
61,000

 
$
(0.11
)
      MichCon
3,000

 
$
(0.04
)
 
 
 
 
Year ending December 31, 2016:
 
 
 
      TCO
44,000

 
$
(0.32
)
      Dominion South
45,000

 
$
(1.10
)
      M2
40,000

 
$
(1.08
)
      TETCO ELA
110,000

 
$
(0.10
)
      MichCon
24,000

 
$
(0.01
)
      Chicago
40,000

 
$
(0.05
)
      ANR SE
35,000

 
$
(0.10
)
 
 
 
 
Year ending December 31, 2017:
 
 
 
      TCO
27,000

 
$
(0.33
)
      Dominion South
75,000

 
$
(0.94
)
      M2
65,000

 
$
(1.01
)
      TETCO ELA
80,000

 
$
(0.09
)
      MichCon
4,000

 
$
(0.04
)
      Chicago
10,000

 
$
(0.16
)
 
 
 
 
Year ending December 31, 2018:
 
 
 
      TCO
19,000

 
$
(0.40
)
      Dominion South
75,000

 
$
(0.70
)
      TETCO ELA
40,000

 
$
(0.08
)
      MichCon
4,000

 
$
(0.04
)
      Chicago
10,000

 
$
(0.19
)
 
 
 
 
Year ending December 31, 2019:
 
 
 
      TCO
10,000

 
$
(0.38
)
      Dominion South
60,000

 
$
(0.61
)
      TETCO ELA
10,000

 
$
(0.10
)
      MichCon
20,000

 
$
(0.12
)




18


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 condensed consolidated balance sheets for the periods presented, all at fair value (refer to Note 5 for derivative instruments at fair value):
 
As of September 30, 2015
(in thousands)
Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross

Derivative instruments subject to master netting arrangements

Derivative instruments, net
Derivative assets
$
337,629

 
$
(74,358
)
 
$
263,271

 
 
 
 
 
 
 
As of December 31, 2014
(in thousands)
Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross
 
Derivative instruments subject to master netting arrangements
 
Derivative instruments, net
Derivative assets
$
201,775

 
$
(5,553
)
 
$
196,222

5.
Fair Value of Financial Instruments
The Company determines fair value on a recurring basis for derivative instruments as these instruments are required to be recorded at fair value for each reporting amount. 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 4 for details relating to derivative instruments):
 
As of September 30, 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
$
263,271

 
$
263,271

 
$

 
$
263,271

 
$

Total assets
$
263,271

 
$
263,271

 
$

 
$
263,271

 
$

 
As of December 31, 2014
 
 
 
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
$
196,222

 
$
196,222

 
$

 
$
196,222

 
$

Total assets
$
196,222

 
$
196,222

 
$

 
$
196,222

 
$


19


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 carrying amount of long-term debt as reported on the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 is shown in the table below (refer to Note 3 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.
 
As of September 30, 2015
 
As of December 31, 2014
Long-Term Debt (in thousands)
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
Senior Notes Due 2022
$
900,000

 
$
807,750

 
$
900,000

 
$
839,250

Senior Notes Due 2023
397,128

 
375,000

 

 

Midstream Holdings Revolving Credit Facility
152,000

 
152,000

 

 

RMP Revolving Credit Facility
72,000

 
72,000

 

 

Other

 

 
680

 
680

Total
$
1,521,128

 
$
1,406,750

 
$
900,680

 
$
839,930

6.
Financial Information by Business Segment
The Company operates in two business segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. The midstream segment is engaged in the gathering and compression of natural gas, oil and NGL production, and in the provision of water services to support the well completion activities, of Rice Energy and third parties. The midstream segment includes the financial results of the Partnership as well as the Company’s 50.0% limited partner interest and incentive distribution rights in the Partnership.
Business segments are evaluated for their contribution to the Company’s consolidated results based on operating income, which is defined as segment operating revenues less expenses. 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, 2014 contained in its 2014 Annual Report.

20


The operating results and assets of the Company’s reportable segments were as follows as of and for the three months ended September 30, 2015:
(in thousands)
 
Exploration and Production
 
Midstream
 
Elimination of Intersegment Transactions
 
Consolidated Total
Operating revenues:
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$
130,145

 
$

 
$

 
$
130,145

Firm transportation sales, net
 
88

 

 

 
88

Gathering, compression and water distribution
 

 
38,766

 
(25,378
)
 
13,388

Total operating revenues
 
$
130,233

 
$
38,766

 
$
(25,378
)
 
$
143,621

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
Lease operating
 
12,325

 

 

 
12,325

Gathering, compression and transportation
 
41,654

 

 
(17,406
)
 
24,248

Production taxes and impact fees
 
1,955

 

 

 
1,955

Exploration
 
830

 

 

 
830

Midstream operation and maintenance
 

 
4,831

 

 
4,831

Incentive unit income
 
(453
)
 
(233
)
 

 
(686
)
Stock compensation expense
 
2,657

 
1,557

 

 
4,214

General and administrative
 
18,592

 
5,521

 

 
24,113

Depreciation, depletion and amortization
 
84,408

 
5,345

 
(478
)
 
89,275

Amortization of intangible assets
 

 
408

 

 
408

       Other income
 
(71
)
 
(194
)
 

 
(265
)
Total operating expenses
 
$
161,897

 
$
17,235

 
$
(17,884
)
 
$
161,248

 
 
 
 
 
 
 
 
 
Operating (loss) income
 
$
(31,664
)
 
$
21,531

 
$
(7,494
)
 
$
(17,627
)
 
 
 
 
 
 
 
 
 
Capital expenditures for segment assets
 
$
185,897

 
$
119,184

 
$
(7,972
)
 
$
297,109















21


The operating results and assets of the Company’s reportable segments were as follows for the three months ended September 30, 2014:
(in thousands)
 
Exploration and Production
 
Midstream
 
Elimination of Intersegment Transactions
 
Consolidated Total
Operating revenues:
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$
67,831

 
$

 
$

 
$
67,831

Firm transportation sales, net
 
9,733

 

 

 
9,733

Gathering, compression and water distribution
 

 
1,620

 
(57
)
 
1,563

Total operating revenues
 
$
77,564

 
$
1,620

 
$
(57
)
 
$
79,127

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
Lease operating
 
4,553

 

 

 
4,553

Gathering, compression and transportation
 
8,049

 

 
(57
)
 
7,992

Production taxes and impact fees
 
1,114

 

 

 
1,114

Exploration
 
623

 

 

 
623

Midstream operation and maintenance
 

 
1,729

 

 
1,729

Incentive unit expense
 
19,468

 
6,950

 

 
26,418

Stock compensation expense
 
1,786

 
272

 

 
2,058

General and administrative
 
10,342

 
116

 

 
10,458

Depreciation, depletion and amortization
 
32,854

 
999

 

 
33,853

Acquisition costs
 
762

 
1,484

 

 
2,246

Amortization of intangible assets
 

 
408

 

 
408

Total operating expenses
 
$
79,551

 
$
11,958

 
$
(57
)
 
$
91,452

 
 
 
 
 
 
 
 
 
Operating loss
 
$
(1,987
)
 
$
(10,338
)
 
$

 
$
(12,325
)
 
 
 
 
 
 
 
 
 
Capital expenditures for segment assets
 
$
17,942

 
$
182,817

 
$

 
$
200,759
















22



The operating results and assets of the Company’s reportable segments were as follows as of and for the nine months ended September 30, 2015:
(in thousands)
 
Exploration and Production
 
Midstream
 
Elimination of Intersegment Transactions
 
Consolidated Total
Operating revenues:
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$
327,947

 
$

 
$

 
$
327,947

Firm transportation sales, net
 
3,353

 

 

 
3,353

Gathering, compression and water distribution
 

 
103,025

 
(68,270
)
 
34,755

Total operating revenues
 
$
331,300

 
$
103,025

 
$
(68,270
)
 
$
366,055

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
Lease operating
 
35,006

 

 

 
35,006

Gathering, compression and transportation
 
102,021

 

 
(46,511
)
 
55,510

Production taxes and impact fees
 
5,103

 

 

 
5,103

Exploration
 
1,925

 

 

 
1,925

Midstream operation and maintenance
 

 
10,963

 

 
10,963

Incentive unit expense
 
43,930

 
1,940

 

 
45,870

Stock compensation expense
 
7,889

 
3,792

 

 
11,681

General and administrative
 
48,007

 
14,021

 

 
62,028

Depreciation, depletion and amortization
 
216,665

 
12,341

 
(1,010
)
 
227,996

Amortization of intangible assets
 

 
1,224

 

 
1,224

       Other expense
 
2,979

 
645

 

 
3,624

Total operating expenses
 
$
463,525

 
$
44,926

 
$
(47,521
)
 
$
460,930

 
 
 
 
 
 
 
 
 
Operating (loss) income
 
$
(132,225
)
 
$
58,099

 
$
(20,749
)
 
$
(94,875
)
 
 
 
 
 
 
 
 
 
Capital expenditures for segment assets
 
$
638,539

 
$
303,126

 
$
(21,759
)
 
$
919,906


23


The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2014:
(in thousands)
 
Exploration and Production
 
Midstream
 
Elimination of Intersegment Transactions
 
Consolidated Total
Operating revenues:
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$
246,816

 
$

 
$

 
$
246,816

Firm transportation sales, net
 
11,851

 

 

 
11,851

Gathering, compression and water distribution
 

 
3,080

 
(202
)
 
2,878

Total operating revenues
 
$
258,667

 
$
3,080

 
$
(202
)
 
$
261,545

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
Lease operating
 
16,406

 

 

 
16,406

Gathering, compression and transportation
 
22,666

 

 
(202
)
 
22,464

Production taxes and impact fees
 
2,624

 

 

 
2,624

Exploration
 
1,582

 

 

 
1,582

Midstream operation and maintenance
 

 
3,564

 

 
3,564

Incentive unit expense
 
90,032

 
11,663

 

 
101,695

Stock compensation expense
 
2,871

 
403

 

 
3,274

Acquisition expense
 
762

 
1,484

 

 
2,246

General and administrative
 
29,340

 
7,393

 

 
36,733

Depreciation, depletion and amortization
 
89,316

 
2,596

 

 
91,912

Amortization of intangible assets
 

 
748

 

 
748

Total operating expenses
 
$
255,599

 
$
27,851

 
$
(202
)
 
$
283,248

 
 
 
 
 
 
 
 
 
Operating income (loss)
 
$
3,068

 
$
(24,771
)
 
$

 
$
(21,703
)
 
 
 
 
 
 
 
 
 
Capital expenditures for segment assets
 
$
412,234

 
$
230,174

 
$

 
$
642,408

As of September 30, 2015: (in thousands)
 
Exploration and Production
 
Midstream
 
Elimination of Intersegment Transactions
 
Consolidated Total
Segment assets
 
$
3,303,477

 
$
943,892

 
$
(21,759
)
 
$
4,225,610

Goodwill
 
$
294,908

 
$
39,142

 
$

 
$
334,050

As of December 31, 2014: (in thousands)
 
Exploration and Production
 
Midstream
 
Elimination of Intersegment Transactions
 
Consolidated Total
Segment assets
 
$
2,935,814

 
$
592,135

 
$

 
$
3,527,949

Goodwill
 
$
294,908

 
$
39,142

 
$

 
$
334,050

7.
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 remaining participating interests are held by

24


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.
The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments under these contracts as of September 30, 2015 totaled $4.8 billion (remainder of 2015 - $27.9 million, 2016 - $117.2 million, 2017 - $151.4 million, 2018 - $226.9 million, 2019 - $222.5 million, 2020 - $222.3 million and thereafter - $3.9 billion).
The Company has three horizontal rigs under contract, of which one expires in 2016 and two expire in 2017. The Company also has two tophole drilling rigs under contract, of which one expires in 2016 and one expires in 2018. Future payments under these contracts as of September 30, 2015 totaled $53.8 million (remainder of 2015 - $10.7 million, 2016 - $28.9 million, 2017 - $12.1 million and 2018 - $2.1 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. These types of drilling obligations 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.
The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.
8.
Stockholders’ Equity
On January 29, 2014, pursuant to the Master Reorganization Agreement among the Company, Rice Drilling B, Rice Appalachia, Rice Energy Holdings LLC (“Rice Holdings”), Rice Energy Family Holdings, LP (“Rice Partners”), NGP Rice Holdings, LLC (“NGP Holdings”), NGP RE Holdings, L.L.C., (“NGP RE Holdings”) NGP RE Holdings II, L.L.C. (“NGP RE II” and, together with NGP RE Holdings, “Natural Gas Partners”), Mr. Daniel J. Rice III, Rice Merger LLC (“Merger Sub”) and each of the persons holding incentive units representing interests in Rice Appalachia (collectively, the “Incentive Unitholders”) dated as of January 23, 2014, (i) (a) Rice Partners contributed a portion of its interests in Rice Appalachia to Rice Holdings, (b) Natural Gas Partners contributed its interests in Rice Appalachia to NGP Holdings and (c) the Incentive Unitholders contributed a portion of their incentive units to Rice Holdings and NGP Holdings, in each case in return for substantially similar incentive units in such entities; (ii) NGP Holdings, Rice Holdings and Mr. Daniel J. Rice III contributed their respective interests in Rice Appalachia to the Company in exchange for 43,452,550, 20,300,923 and 2,356,844 shares of common stock, respectively; (iii) Rice Partners contributed its remaining interest in Rice Appalachia to the Company in exchange for 20,000,000 shares of common stock; (iv) the Incentive Unitholders contributed their remaining interests in Rice Appalachia to the Company in exchange for 160,831 shares of common stock, each of which were issued by the Company in connection with the closing of the IPO. In connection with the IPO, in the first quarter of 2014, the Company recognized non-cash compensation expense of $3.4 million for these 160,831 shares.
In addition, on January 29, 2014, pursuant to the Agreement and Plan of Merger among the Company, Rice Drilling B and Merger Sub dated as of January 23, 2014, the Company issued 1,728,852 shares of common stock to the members of Rice Drilling B (other than Rice Appalachia) in exchange for their units in Rice Drilling B.
In August 2014, the Company completed a public offering (the “August 2014 Equity Offering”) of 13,729,650 shares of common stock at $27.30 per share, which included 7,500,000 shares sold by the Company and 6,229,650 shares sold by NGP Holdings and an affiliate of Alpha Natural Resources, Inc. (the “Selling Stockholders”). After deducting underwriting discounts and commissions of $7.7 million and transaction costs, the Company received net proceeds of $196.3 million. The Company received no proceeds from the sale of shares by the Selling Stockholders. The net proceeds from this offering were used to fund a portion of the Company’s 2014 capital budget.
On December 22, 2014, the Partnership completed an initial public offering (the “RMP IPO”) of 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. A wholly-owned subsidiary of the Company serves as the general partner of the Partnership. The Company continues to consolidate 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 condensed consolidated financial statements.
On May 12, 2015, the Company and NGP Holdings entered into an Underwriting Agreement with Goldman, Sachs & Co.

25


and Citigroup Global Markets Inc., relating to the offer and sale by NGP Holdings (the “Secondary Offering”) of 6,000,000 shares of common stock at a price to the public of $24.20 per share ($23.99 per share net of underwriting discounts and commissions). The Secondary Offering closed on May 15, 2015. The Company did not receive any proceeds from the sale of shares of common stock by NGP Holdings.
The Company’s Board of Directors did not declare or pay a dividend for the three or nine months ended September 30, 2015 or 2014. On August 13, 2015, a cash distribution of $0.1905 per common and subordinated unit was paid by the Partnership to the Partnership’s unitholders related to the second quarter of 2015. On October 23, 2015, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders for the third quarter of 2015 of $0.1935 per common and subordinated unit. The cash distribution will be paid on November 12, 2015 to unitholders of record at the close of business on November 3, 2015.
9.
Incentive Units
In connection with the IPO and the related corporate reorganization, the Rice Appalachia incentive unit holders contributed their Rice Appalachia incentive units to NGP Holdings and Rice Holdings in return for (i) incentive units in such entities that, in the aggregate, were substantially similar to the Rice Appalachia 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 our 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 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. The recognized and unrecognized compensation expense related to the NGP Holdings incentive units is sensitive to certain assumptions, including the estimated timing of NGP Holdings’ sale of the Company’s common stock. Compensation (income) expense relative to the NGP Holdings incentive units was $(7.7) million and $(8.6) million for the three and nine months ended September 30, 2015, respectively, and $7.5 million and $47.1 million for the three and nine months ended September 30, 2014, respectively. As of September 30, 2015, the estimated unrecognized compensation expense related to the NGP Holdings interests is approximately $13.9 million.

In the first quarter of 2014, NGP Holding’s distribution thresholds with regard to certain classes (tiers) of incentive units were satisfied as a result of NGP Holdings’ distribution of net proceeds from its sale of the Company’s common stock in the IPO, and NGP Holdings made cash distributions to its members, including holders of incentive units, in an aggregate amount of $4.4 million. As a result of the Company’s August 2014 Equity Offering, NGP Holdings paid approximately $12.0 million in the third quarter of 2014 to holders of certain classes of incentive units. The sale of the Company’s stock by NGP Holdings in the Secondary Offering triggered a payment to holders of certain classes of incentive units in May 2015, which resulted in approximately $26.7 million expense for the nine months ended September 30, 2015.
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 $7.1 million and $27.7 million for the three and nine months ended September 30, 2015, respectively, and $6.9 million and $34.7 million for the three and nine months ended September 30, 2014, respectively. The Company will recognize approximately $45.1 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 and September 2015, Rice Holdings distributed one quarter and one third, 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 2016 and 2017, Rice Holdings will distribute one half and all, 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.  As a result, over time, the shares of the Company’s common stock held by Rice Holdings will be transferred in their entirety to Rice Energy Irrevocable Trust and the incentive unitholders. 

26


Total compensation (income) expense relative to the NGP Holdings and Rice Holdings incentive units was $(0.7) million and $45.9 million for the three and nine months ended September 30, 2015, respectively, and $26.4 million and $101.7 million for the three and nine months ended September 30, 2014, respectively. Of the total compensation (income) expense recognized for the three and nine months ended September 30, 2015, approximately $1.7 million and $12.8 million, respectively, related to changes in certain service condition assumptions.
Three tranches of the incentive units have a time vesting feature. A roll forward of those units from December 31, 2014 to September 30, 2015 is included below.
Vested Units Balance, December 31, 2014
1,800,911

   Vested During Period
793,440

   Forfeited During Period

   Granted During Period

   Canceled During Period

Vested Units Balance, September 30, 2015
2,594,351

Four 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 September 30, 2015. 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

NGP Holdings
 
Valuation Date
9/30/2015

Dividend Yield
0.00
%
Expected Volatility
47.86
%
Risk-Free Rate
0.33
%
Expected Life (Years)
1.0


27


10.
Stock-Based Compensation
During the year ended December 31, 2014 and the nine months ended September 30, 2015, the Company granted stock compensation awards to certain non-employee directors and employees under the Company’s long-term incentive plan. The awards consisted of restricted stock units, which vest upon the passage of time, and performance stock units, which vest based upon attainment of specified performance criteria. Stock compensation expense related to these awards was $3.3 million and $8.7 million for the three and nine months ended September 30, 2015, respectively, and $2.1 million and $3.3 million for the three and nine months ended September 30, 2014, respectively. As of September 30, 2015, the Company has unrecognized compensation expense related to these equity awards of $23.4 million.
Stock compensation expense also includes phantom unit awards granted in connection with the closing of the Partnership’s IPO to certain non-employee directors of the Partnership and executive officers and employees of Rice Energy. The Partnership recorded $1.0 million and $3.0 million of equity compensation expense related to these awards in the three and nine months ended September 30, 2015, respectively. As of September 30, 2015, the Partnership has unrecognized compensation expense related to these awards of $3.8 million.
11.
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 three and nine months ended September 30, 2015 and 2014. As indicated in Note 1, the Company’s corporate reorganization was considered a transaction amongst entities under common control. Therefore, the weighted average shares used in the Company’s EPS calculation assume that the Rice Energy Inc. corporate structure was in place for all periods presented.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands, except share data)
2015
 
2014
 
2015
 
2014
Income (numerator):
 
 
 
 
 
 
 
Net income (loss)
$
58,950

 
$
(6,862
)
 
$
(10,579
)
 
$
114,675

 
 
 
 
 
 
 
 
Weighted-average number of shares of common stock (denominator):
 
 
 
 
 
 
 
Basic
136,381,909

 
132,269,081

 
136,330,198

 
125,411,524

Diluted
136,521,828

 
132,269,081

 
136,330,198

 
125,678,095

 
 
 
 
 
 
 
 
Earnings (loss) per share:
 
 
 
 
 
 
 
Basic
$
0.43

 
$
(0.05
)
 
$
(0.08
)
 
$
0.91

Diluted
$
0.43

 
$
(0.05
)
 
$
(0.08
)
 
$
0.91

For the three months ended September 30, 2015, 237,181 shares attributable to equity awards were not included in the diluted earnings per share calculation as to do so would have been anti-dilutive.
For the nine months ended September 30, 2015, 160,248 shares attributable to equity awards were not included in the diluted earnings per share calculation as the Company incurred a net loss for the periods presented herein.
For the three months ended September 30, 2014, 76,800 shares were not considered dilutive as the Company incurred a net loss for the periods presented herein.
12.
Income Taxes
The Company is a corporation 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 did not report any income tax benefit or expense for periods prior to the consummation of its IPO because Rice Drilling B, the Company’s accounting predecessor, is a limited liability company that was not subject to federal income tax. The reorganization of the Company’s business in connection with the closing of the IPO, such that it is now held by a corporation subject to federal income tax, required the

28


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 pro forma EPS for the nine months ended September 30, 2014 disclosed in the accompanying condensed consolidated statements of operations assumes a statutory tax rate.
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. 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 its 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.

The tax expense for the three and nine months ended September 30, 2015 was $19.8 million and $18.3 million, respectively, resulting in an effective tax rate of approximately 23% and 75%, respectively. Tax expense of $14.0 million was recorded for the three months ended September 30, 2014, resulting in an effective tax rate of approximately 196%. Tax expense of $18.8 million was recorded for the nine months ended September 30, 2014, resulting in an effective tax rate of approximately 14%. The effective tax rate for the three and nine months ended September 30, 2015 and 2014 differs from the statutory rate due principally to nondeductible incentive unit expense, pre-tax income prior to the IPO and the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners.

Based on management’s analysis, the Company did not have any uncertain tax positions as of September 30, 2015.
13.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”), No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” or ASU No. 2014-09. 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. 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. In August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.” The amendments in this update deferred the effective date for implementation of ASU 2014-09 by one year. ASU 2014-09 will now be effective for annual reporting periods beginning after December 15, 2017 and should be applied retrospectively. Early application is permitted only for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that period. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.
In February 2015, the FASB issued ASU, 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis.” ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for periods beginning after December 15, 2015 with early adoption permitted. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements.
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 with early adoption permitted. 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 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 is currently evaluating the impact of the provisions of ASU 2015-03 and ASU 2015-15.
In September 2015, the FASB issued ASU, 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments.” ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. ASU 2015-16

29


is effective for periods beginning after December 15, 2015 with early adoption permitted. The Company is currently evaluating the impact of the provisions of ASU 2015-16.
14.
Subsequent Events
On October 6, 2015, Rice Midstream Holdings, a wholly-owned subsidiary of the Company, signed a letter of intent with Gulfport Energy Corporation (“Gulfport”) to form a midstream joint venture (the “Midstream JV”) to develop natural gas gathering and water services assets to support Gulfport’s dry gas Utica Shale development in eastern Belmont County, Ohio and Monroe County, Ohio. Rice Midstream Holdings will own 75% of the Midstream JV and be responsible for constructing and operating the Midstream JV’s assets. Gulfport will own the remaining 25% of the Midstream JV and dedicate approximately 77,000 net leasehold acres, including the acreage recently acquired in its Paloma Partners III, LLC and American Energy - Utica, LLC transactions. Gulfport will also contribute to the Midstream JV an existing 11-mile gas gathering pipeline and a 350 MDth/d TETCO interconnect, which are both located in Monroe County, Ohio.
On October 30, 2015, a scheduled redetermination of the Senior Secured Revolving Credit Facility occurred as a result of which the borrowing base increased from $650.0 million to $750.0 million and the sublimit for letters of credit increased from $175.0 million to $250.0 million. In addition, the Company entered into the Sixth Amendment (the “Sixth Amendment”) to the Amended Credit Agreement, which (a) capped EBITDAX attributable cash distributions received by the Company from to Rice Midstream Holdings at (i) EBITDA (as defined in the Midstream Holdings Credit Agreement (defined below), as amended) of Rice Midstream Holdings multiplied by (ii) the percentage of Rice Midstream Holdings’ equity interests that are owned by the Company, and (b) expanded the hedging covenant in the Amended Credit Agreement to provide for, and permit as secured obligations thereunder, certain firm transportation reimbursement agreements of the Company and its subsidiaries with the lenders and their affiliates. Please see Note 3 for additional information regarding the Senior Secured Revolving Credit Facility.
On October 30, 2015, Rice Midstream Holdings entered into the First Amendment (the “First Amendment”) to its Credit Agreement, among Rice Midstream Holdings, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders and other parties thereto (the “Midstream Holdings Credit Agreement”). The First Amendment amends the Midstream Holdings Credit Agreement to permit the Midstream JV. The First Amendment, among other things, (i) permits unlimited investment into the Midstream JV, subject to certain pro forma leverage and credit facility availability tests, (ii) amends the EBITDA definition to provide for certain capital expansion project add-backs related to the Midstream JV and (iii) allows for cash distributions from unrestricted subsidiaries of Rice Midstream Holdings other than the Midstream JV in amounts up to 40% of EBITDA for reporting periods ending in 2016 (and 25% thereafter), subject to an increased margin chargeable on the loans, and an exclusion for any cash distributions received from the Midstream JV, in each case during such reporting periods. Additionally, the First Amendment provides that, in connection with the Company’s sale of the midstream water entities described below, the aggregate commitments under the Credit Agreement shall be reduced, if the commitments are then higher than such amount, to an amount equal to (i) EBITDA for the most recently completed four fiscal quarters (as adjusted to give pro forma effect to the acquisition of the Water Assets (defined below)) multiplied by (ii) a factor of 15.0, rather than a factor of 5.0. Please see Note 3 for additional information regarding the Midstream Holdings Revolving Credit Facility.
On November 4, 2015, the Company entered into a Purchase and Sale Agreement (the “Purchase Agreement”) by and between the Company and the Partnership, pursuant to which the Company sold all of the outstanding limited liability company interests of Rice Water Services (PA) LLC (“PA Water”) and Rice Water Services (OH) LLC (“OH Water”), two wholly-owned indirect subsidiaries of the Company that own and operate the Company’s water services business (the “Water Assets”). The acquired business includes the Company’s Pennsylvania and Ohio fresh water distribution systems and related facilities that provide access to 15.9 MMgal/d of fresh water from the Monongahela River, the Ohio River and other regional water sources in Pennsylvania and Ohio. The Company has also granted the Partnership, until December 31, 2025, (i) the exclusive right to develop water treatment facilities in the areas of dedication defined in the Water Services Agreements (defined below) and (ii) an option to purchase any water treatment facilities acquired by the Company in such areas at the Company’s acquisition cost (collectively, the “Option”). In consideration for the acquisition of the Water Assets and the receipt of the Option, the Partnership paid the Company $200.0 million in cash plus an additional amount, if certain of the conveyed systems’ capacities increase by 5.0 MMgal/d on or prior to December 31, 2017, equal to $25.0 million less the capital expenditures expended by the Partnership to achieve such increase, in accordance with the terms of the Purchase Agreement.
In connection with the closing of the acquisition of the Water Assets, on November 4, 2015, the Company entered into Amended and Restated Water Services Agreements (the “Water Services Agreements”) with PA Water and OH Water, respectively, whereby PA Water and OH Water, as applicable, have agreed to provide certain fluid handling services to the Company, including the exclusive right to provide fresh water for well completions operations in the Marcellus and Utica Shales and to collect and recycle or dispose of flowback, produced water and other fluids for the Company within areas of dedication in defined service areas in Pennsylvania and Ohio. The initial term of the Water Services Agreements is until December 22, 2029 and from month to month thereafter. Under the agreements, the Company will pay (i) a variable fee, based on volumes of water

30


supplied, for freshwater deliveries by pipeline directly to the well site, subject to annual CPI adjustments and (ii) a produced water hauling fee of actual out-of-pocket cost incurred by PA Water and OH Water, plus a 2% margin.  
15.
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. The Company’s subsidiaries that constitute its midstream segment, including the Partnership, 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, the Guarantors and the non-guarantor subsidiaries. The principal elimination entries eliminate investment in subsidiaries and certain intercompany balances and transactions.


31


Condensed Consolidated Balance Sheet as of September 30, 2015
 
 
 
 
 
 
(in thousands)
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash
$
98,218

 
$
80,165

 
$
37,701

 
$

 
$
216,084

Accounts receivable
209

 
212,890

 
11,237

 

 
224,336

Receivable from affiliates
32,200

 
(34,120
)
 
1,981

 

 
61

Prepaid expenses and other assets
3,510

 
1,658

 
645

 

 
5,813

Derivative assets
35,903

 
121,573

 

 

 
157,476

Total current assets
170,040

 
382,166

 
51,564

 

 
603,770

 
 
 
 
 
 
 
 
 
 
Investments in subsidiaries
2,656,435

 
138,775

 

 
(2,795,210
)
 

Gas collateral account

 
3,995

 
41

 

 
4,036

Property, plant and equipment, net
11,621

 
2,308,174

 
802,267

 
(20,749
)
 
3,101,313

Deferred financing costs, net
25,769

 

 
4,309

 

 
30,078

Goodwill

 
294,908

 
39,142

 

 
334,050

Intangible assets, net

 

 
46,568

 

 
46,568

Derivative assets
22,518

 
83,277

 

 

 
105,795

Deferred tax asset
71,485

 

 

 
(71,485
)
 

Total assets
$
2,957,868

 
$
3,211,295

 
$
943,891

 
$
(2,887,444
)
 
$
4,225,610

 
 
 
 
 
 
 
 
 
 
Liabilities and stockholders’ equity
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
4,978

 
77,614

 
43,041

 

 
125,633

Royalties payables

 
54,141

 

 

 
54,141

Accrued capital expenditures

 
42,629

 
56,057

 

 
98,686

Accrued interest
38,421

 

 
224

 

 
38,645

Leasehold payables

 
21,907

 

 

 
21,907

Deferred tax liabilities
14,088

 
49,398

 

 

 
63,486

Payable to affiliate

 

 

 

 

Other accrued liabilities
12,544

 
32,214

 
1,645

 

 
46,403

Total current liabilities
70,031

 
277,903

 
100,967

 

 
448,901

 
 
 
 
 
 
 
 
 
 
Long-term liabilities:
 
 
 
 
 
 
 
 
 
Long-term debt
1,297,128

 

 
224,000

 

 
1,521,128

Leasehold payable

 
7,010

 

 

 
7,010

Deferred tax liabilities

 
258,951

 
27,250

 
(71,485
)
 
214,716

Other long-term liabilities
3,239

 
10,996

 
2,293

 

 
16,528

Total liabilities
1,370,398

 
554,860

 
354,510

 
(71,485
)
 
2,208,283

Stockholders’ equity before noncontrolling interest
1,587,470

 
2,656,435

 
138,775

 
(2,815,959
)
 
1,566,721

Noncontrolling interest

 

 
450,606

 

 
450,606

Total liabilities and stockholders’ equity
$
2,957,868

 
$
3,211,295

 
$
943,891

 
$
(2,887,444
)
 
$
4,225,610


32



Condensed Consolidated Balance Sheet as of December 31, 2014
 
 
 
 
(in thousands)
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Assets
 
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
 
Cash
 
$
181,835

 
$
41,934

 
$
32,361

 
$

 
$
256,130

Accounts receivable
 
1,773

 
196,974

 
1,153

 

 
199,900

Receivable from affiliates
 
634

 
55

 
2,198

 
(2,799
)
 
88

Prepaid expenses and other assets
 
1,296

 
1,702

 
341

 

 
3,339

Derivative assets
 
47,291

 
85,743

 

 

 
133,034

Total current assets
 
232,829

 
326,408

 
36,053

 
(2,799
)
 
592,491

 
 
 
 
 
 
 
 
 
 
 
Investments in subsidiaries
 
2,177,895

 
86,148

 

 
(2,264,043
)
 

Gas collateral account
 

 
3,995

 

 

 
3,995

Property, plant and equipment, net
 
10,348

 
1,986,856

 
464,127

 

 
2,461,331

Deferred financing costs, net
 
20,081

 

 
5,022

 

 
25,103

Goodwill
 

 
294,908

 
39,142

 

 
334,050

Intangible assets, net
 

 

 
47,791

 

 
47,791

Other non-current assets
 
8,290

 
54,898

 

 

 
63,188

Total assets
 
$
2,449,443

 
$
2,753,213

 
$
592,135

 
$
(2,266,842
)
 
$
3,527,949

 
 
 
 
 
 
 
 
 
 
 
Liabilities and stockholders’ equity
 
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
 
Current portion of long-term debt
 
$

 
$
680

 
$

 
$

 
$
680

Accounts payable
 
19,231

 
101,132

 
31,966

 

 
152,329

Royalties payables
 

 
37,172

 

 

 
37,172

Accrued capital expenditures
 
1,515

 
89,858

 
16,917

 

 
108,290

Accrued interest
 
9,375

 

 

 

 
9,375

Leasehold payables
 

 
30,702

 

 

 
30,702

Deferred tax liabilities
 
54,688

 
39,197

 

 
(39,197
)
 
54,688

Other accrued liabilities
 
16,652

 
27,502

 
2,086

 
(2,801
)
 
43,439

Total current liabilities
 
101,461

 
326,243

 
50,969

 
(41,998
)
 
436,675

 
 
 
 
 
 
 
 
 
 
 
Long-term liabilities:
 
 
 
 
 
 
 
 
 
 
Long-term debt
 
900,000

 

 

 

 
900,000

Deferred tax liabilities
 
12,497

 
237,155

 
10,660

 
(51,094
)
 
209,218

Leasehold payable
 

 
4,279

 

 

 
4,279

Other long-term liabilities
 
3,068

 
7,641

 
1,900

 

 
12,609

Total liabilities
 
1,017,026

 
575,318

 
63,529

 
(93,092
)
 
1,562,781

Stockholders’ equity before noncontrolling interest
 
1,432,417

 
2,177,895

 
86,148

 
(2,173,750
)
 
1,522,710

Noncontrolling interest
 

 

 
442,458

 

 
442,458

Total liabilities and stockholders’ equity
 
$
2,449,443

 
$
2,753,213

 
$
592,135

 
$
(2,266,842
)
 
$
3,527,949



  

33


Condensed Consolidated Statement of Operations for the Three Months Ended September 30, 2015
 
 
(in thousands)
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Operating revenues:
 
 
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$

 
$
130,145

 
$

 
$

 
$
130,145

Firm transportation sales, net
 

 
88

 

 

 
88

Gathering, compression and water distribution
 

 

 
38,766

 
(25,378
)
 
13,388

Total operating revenues
 

 
130,233

 
38,766

 
(25,378
)
 
143,621

 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
Lease operating
 

 
12,325

 

 

 
12,325

Gathering, compression and transportation
 

 
41,654

 

 
(17,406
)
 
24,248

Production taxes and impact fees
 

 
1,955

 

 

 
1,955

Exploration
 

 
830

 

 

 
830

Midstream operation and maintenance
 

 

 
4,831

 

 
4,831

Incentive unit income
 

 
(453
)
 
(233
)
 

 
(686
)
Stock compensation expense
 

 
2,657

 
1,557

 

 
4,214

General and administrative
 

 
18,592

 
5,521

 

 
24,113

Depreciation, depletion and amortization
 

 
84,408

 
5,345

 
(478
)
 
89,275

       Amortization of intangible assets
 

 

 
408

 

 
408

       Other income
 

 
(71
)
 
(194
)
 

 
(265
)
Total operating expenses
 

 
161,897

 
17,235

 
(17,884
)
 
161,248

 
 
 
 
 
 
 
 
 
 
 
Operating (loss) income
 

 
(31,664
)
 
21,531

 
(7,494
)
 
(17,627
)
Interest expense
 
(22,424
)
 
(88
)
 
(1,437
)
 

 
(23,949
)
Other income
 
170

 
506

 
22

 

 
698

Gain on derivative instruments
 
31,175

 
95,897

 

 

 
127,072

Amortization of deferred financing costs
 
(1,060
)
 

 
(253
)
 

 
(1,313
)
Equity income (loss) in affiliate
 
41,444

 
(981
)
 

 
(40,463
)
 

Income (loss) before income taxes
 
49,305

 
63,670

 
19,863

 
(47,957
)
 
84,881

Income tax (expense) benefit
 
(19,797
)
 
(23,092
)
 
(6,350
)
 
29,442

 
(19,797
)
Net income (loss)
 
29,508

 
40,578

 
13,513

 
(18,515
)
 
65,084

Less: Net income attributable to the noncontrolling interests
 

 

 
(6,134
)
 

 
(6,134
)
Net income (loss) attributable to Rice Energy
 
$
29,508

 
$
40,578

 
$
7,379

 
$
(18,515
)
 
$
58,950


 

34


Condensed Consolidated Statement of Operations for the Three Months Ended September 30, 2014
 
 
(in thousands)
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Operating revenues:
 
 
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$

 
$
67,831

 
$

 
$

 
$
67,831

Firm transportation sales, net
 

 
9,733

 

 

 
9,733

Gathering, compression and water distribution
 

 

 
1,620

 
(57
)
 
1,563

Total operating revenues
 

 
77,564

 
1,620

 
(57
)
 
79,127

 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
Lease operating
 

 
4,553

 

 

 
4,553

Gathering, compression and transportation
 

 
8,049

 

 
(57
)
 
7,992

Production taxes and impact fees
 

 
1,114

 

 

 
1,114

Exploration
 

 
623

 

 

 
623

Midstream operation and maintenance
 

 
(515
)
 
2,244

 

 
1,729

Incentive unit expense
 

 
19,468

 
6,950

 

 
26,418

Stock compensation expense
 

 
1,786

 
272

 

 
2,058

General and administrative
 

 
10,341

 
117

 

 
10,458

       Depreciation, depletion and
       amortization
 

 
32,854

 
999

 

 
33,853

       Acquisition expense
 

 
160

 
2,086

 

 
2,246

       Amortization of intangible assets
 

 

 
408

 

 
408

Total operating expenses
 

 
78,433

 
13,076

 
(57
)
 
91,452

 
 
 
 
 
 
 
 
 
 
 
Operating loss
 

 
(869
)
 
(11,456
)
 

 
(12,325
)
Interest expense
 
(14,665
)
 
(1,089
)
 

 

 
(15,754
)
Other income (expense)
 
190

 
(406
)
 

 

 
(216
)
Gain on derivative instruments
 

 
36,935

 

 

 
36,935

Amortization of deferred financing costs
 
(707
)
 

 

 

 
(707
)
Loss on extinguishment of debt
 

 
(790
)
 

 

 
(790
)
Equity in income (loss) of affiliate
 
5,603

 
(9,335
)
 

 
3,732

 

Income (loss) before income taxes
 
(9,579
)
 
24,446

 
(11,456
)
 
3,732

 
7,143

Income tax (expense) benefit
 
(14,005
)
 
(18,840
)
 
2,119

 
16,721

 
(14,005
)
Net (loss) income
 
(23,584
)
 
5,606

 
(9,337
)
 
20,453

 
(6,862
)
Less: Net income attributable to the noncontrolling interests
 

 

 

 

 

Net (loss) income attributable to Rice Energy
 
$
(23,584
)
 
$
5,606

 
$
(9,337
)
 
$
20,453

 
$
(6,862
)


35


Condensed Consolidated Statement of Operations for the Nine Months Ended September 30, 2015
 
 
(in thousands)
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Operating revenues:
 
 
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$

 
$
327,947

 
$

 
$

 
$
327,947

Firm transportation sales, net
 

 
3,353

 

 

 
3,353

Gathering, compression and water distribution
 

 

 
103,025

 
(68,270
)
 
34,755

Total operating revenues
 

 
331,300

 
103,025

 
(68,270
)
 
366,055

 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
Lease operating
 

 
35,006

 

 

 
35,006

Gathering, compression and transportation
 

 
102,021

 

 
(46,511
)
 
55,510

Production taxes and impact fees
 

 
5,103

 

 

 
5,103

Exploration
 

 
1,925

 

 

 
1,925

Midstream operation and maintenance
 

 

 
10,963

 

 
10,963

Incentive unit expense
 

 
43,930

 
1,940

 

 
45,870

Stock compensation expense
 

 
7,889

 
3,792

 

 
11,681

General and administrative
 

 
48,007

 
14,021

 

 
62,028

Depreciation, depletion and amortization
 

 
216,665

 
12,341

 
(1,010
)
 
227,996

       Amortization of intangible assets
 

 

 
1,224

 

 
1,224

       Other expense
 

 
2,979

 
645

 

 
3,624

Total operating expenses
 

 
463,525

 
44,926

 
(47,521
)
 
460,930

 
 
 
 
 
 
 
 
 
 
 
Operating (loss) income
 

 
(132,225
)
 
58,099

 
(20,749
)
 
(94,875
)
Interest expense
 
(60,232
)
 
(137
)
 
(3,068
)
 

 
(63,437
)
Other income
 
526

 
1,338

 
30

 

 
1,894

Gain on derivative instruments
 
40,274

 
144,455

 

 

 
184,729

Amortization of deferred financing costs
 
(2,966
)
 

 
(756
)
 

 
(3,722
)
Equity (loss) income in affiliate
 
(28,127
)
 
(921
)
 

 
29,048

 

(Loss) income before income taxes
 
(50,525
)
 
12,510

 
54,305

 
8,299

 
24,589

Income tax (expense) benefit
 
(18,335
)
 
(41,647
)
 
(16,634
)
 
58,281

 
(18,335
)
Net (loss) income
 
(68,860
)
 
(29,137
)
 
37,671

 
66,580

 
6,254

Less: Net income attributable to the noncontrolling interests
 

 

 
(16,833
)
 

 
(16,833
)
Net (loss) income attributable to Rice Energy
 
$
(68,860
)
 
$
(29,137
)
 
$
20,838

 
$
66,580

 
$
(10,579
)


36


Condensed Consolidated Statement of Operations for the Nine Months Ended September 30, 2014
 
 
(in thousands)
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Operating revenues:
 
 
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
 
$

 
$
246,816

 
$

 
$

 
$
246,816

Firm transportation sales, net
 

 
11,851

 

 

 
11,851

Gathering, compression and water distribution
 

 

 
3,080

 
(202
)
 
2,878

Total operating revenues
 

 
258,667

 
3,080

 
(202
)
 
261,545

 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
Lease operating
 

 
16,406

 

 

 
16,406

Gathering, compression and transportation
 

 
22,666

 

 
(202
)
 
22,464

Production taxes and impact fees
 

 
2,624

 

 

 
2,624

Exploration
 

 
1,582

 

 

 
1,582

Midstream operation and maintenance
 

 

 
3,564

 

 
3,564

Incentive unit expense
 

 
90,032

 
11,663

 

 
101,695

Stock compensation expense
 

 
2,871

 
403

 

 
3,274

General and administrative
 

 
29,340

 
7,393

 

 
36,733

       Depreciation, depletion and
       amortization
 

 
89,316

 
2,596

 

 
91,912

       Acquisition expense
 

 
160

 
2,086

 

 
2,246

       Amortization of intangible assets
 

 

 
748

 

 
748

Total operating expenses
 

 
254,997

 
28,453

 
(202
)
 
283,248

 
 
 
 
 
 
 
 
 
 
 
Operating loss
 

 
3,670

 
(25,373
)
 

 
(21,703
)
Interest expense
 
(24,917
)
 
(13,820
)
 

 

 
(38,737
)
Gain on purchase of Marcellus joint venture
 

 
203,579

 

 

 
203,579

Other income (expense)
 
210

 
(30
)
 

 

 
180

Loss on derivative instruments
 

 
5,357

 

 

 
5,357

Amortization of deferred financing costs
 
(1,239
)
 
(489
)
 

 

 
(1,728
)
Loss on extinguishment of debt
 

 
(3,934
)
 

 

 
(3,934
)
Write-off of deferred financing costs
 

 
(6,896
)
 

 

 
(6,896
)
Equity loss of joint ventures
 

 
(2,656
)
 

 

 
(2,656
)
Equity in income (loss) of affiliate
 
136,220

 
(16,842
)
 

 
(119,378
)
 

Income (loss) before income taxes
 
110,274

 
167,939

 
(25,373
)
 
(119,378
)
 
133,462

Income tax (expense) benefit
 
(18,787
)
 
(31,720
)
 
8,532

 
23,188

 
(18,787
)
Net income (loss)
 
91,487

 
136,219

 
(16,841
)
 
(96,190
)
 
114,675

Less: Net income attributable to the noncontrolling interests
 

 

 

 

 

Net income (loss) attributable to Rice Energy
 
$
91,487

 
$
136,219

 
$
(16,841
)
 
$
(96,190
)
 
$
114,675



37


Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2015
 
(in thousands)
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities
 
$
(47,935
)
 
$
275,383

 
$
64,707

 
$
(21,759
)
 
$
270,396

 
 
 
 
 
 
 
 
 
 
 
Capital expenditures for property and equipment
 
(3,885
)
 
(634,654
)
 
(303,126
)
 
21,759

 
(919,906
)
Proceeds from sale of interest in gas properties
 

 
10,201

 

 

 
10,201

Investment in subsidiaries
 
(419,385
)
 
(31,386
)
 

 
450,771

 

Net cash (used in) provided by investing activities
 
(423,270
)
 
(655,839
)
 
(303,126
)
 
472,530

 
(909,705
)
 
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings
 
411,932

 

 
224,000

 

 
635,932

Repayments of debt obligations
 
(15,692
)
 
(698
)
 

 

 
(16,390
)
Debt issuance costs
 
(8,652
)
 

 
(44
)
 

 
(8,696
)
Offering costs related to the Partnership’s IPO
 

 

 
(129
)
 

 
(129
)
Distributions to the Partnership’s public unitholders
 

 

 
(11,454
)
 

 
(11,454
)
Parent distributions, net
 

 
419,385

 
31,386

 
(450,771
)
 

Net cash provided by (used in) financing activities
 
387,588


418,687


243,759


(450,771
)

599,263

 
 
 
 
 
 
 
 
 
 
 
Increase (decrease) in cash
 
(83,617
)
 
38,231

 
5,340

 

 
(40,046
)
Cash, beginning of year
 
181,835

 
41,934

 
32,361

 

 
256,130

Cash, end of period
 
$
98,218

 
$
80,165

 
$
37,701

 
$

 
$
216,084



38


Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2014
 
 
(in thousands)
 
Parent
 
Guarantors
 
Non-Guarantors
 
Eliminations
 
Consolidated
Net cash provided by (used in) operating activities
 
$
12,393

 
$
51,176

 
$
6,110

 
$

 
$
69,679

 
 
 
 
 
 
 
 
 
 
 
Capital expenditures for property and equipment
 
(7,358
)

(404,876
)

(230,174
)


 
(642,408
)
Investment in subsidiaries
 
(1,572,448
)
 
(226,808
)
 

 
1,799,256

 

Acquisition of Marcellus JV, net of cash acquired
 

 
(82,766
)
 

 

 
(82,766
)
Acquisition of Greene County assets
 

 
(329,469
)
 

 

 
(329,469
)
Acquisition of Momentum assets
 

 
(111,447
)
 

 

 
(111,447
)
Proceeds from sale of interest in gas properties
 

 
11,542

 

 

 
11,542

Net cash provided by (used in) investing activities
 
(1,579,806
)
 
(1,143,824
)
 
(230,174
)
 
1,799,256

 
(1,154,548
)
 
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings
 
900,000

 

 

 

 
900,000

Repayments of debt obligations
 

 
(498,983
)
 

 

 
(498,983
)
Restricted cash for convertible debt
 

 
8,268

 

 

 
8,268

Debt issuance costs
 
(24,283
)
 
5,744

 
(862
)
 

 
(19,401
)
Costs relating to IPO
 
(1,412
)
 

 

 

 
(1,412
)
Proceeds from conversion of warrants
 

 
1,975

 

 

 
1,975

Proceeds from issuance of common stock sold in IPO, net of underwriting fees
 
598,500

 

 

 

 
598,500

Costs relating to August 2014 Equity Offering
 
(784
)
 

 

 

 
(784
)
Proceeds from issuance of common stock in August 2014 Equity Offering, net of underwriting fees
 
197,072

 

 

 

 
197,072

Parent contributions, net
 

 
1,572,448

 
226,808

 
(1,799,256
)
 

Net cash provided by (used in) financing activities
 
1,669,093

 
1,089,452

 
225,946

 
(1,799,256
)
 
1,185,235

 
 
 
 
 
 
 
 
 
 
 
Increase (decrease) in cash
 
101,680

 
(3,196
)
 
1,882

 

 
100,366

Cash, beginning of year
 

 
31,408

 
204

 

 
31,612

Cash, end of period
 
$
101,680

 
$
28,212

 
$
2,086

 
$

 
$
131,978

  


39



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 2014 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 “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 engaged in the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. We operate in two business segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. The midstream segment is engaged in the gathering and compression of natural gas, oil and NGL production, and in the provision of water services to support the well completion activities, of Rice Energy and third parties.
On January 29, 2014, we completed our initial public offering and related transactions (the “IPO”), including our reorganization and concurrent acquisition of Foundation PA Coal Company LLC’s (“Alpha Holdings”) 50% interest in our Marcellus joint venture. On December 22, 2014, RMP completed its initial public offering and related transactions (the “RMP IPO”), including our contribution to it of certain gas gathering and compression assets.
As a result of the reorganizations that occurred during 2014, our historical financial condition and results of operations for the periods presented in this Quarterly Report may not be comparable, either from period to period or going forward. For example, information for the period from January 1, 2014 through January 29, 2014, pertains to the historical financial statements and results of operations of our accounting predecessor. Whereas our accounting predecessor, Rice Drilling B, was not subject to federal income tax during this period, we are a corporation subject to federal income tax at a statutory rate of 35% of pretax earnings. In addition, such period reflects 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 50.0% limited partner interest and all of the incentive distribution rights in RMP. In addition to these interests, RMP distributed to us approximately $414.4 million of the net proceeds of the RMP IPO raised from the sale of common units representing the remaining 50.0% limited partner interest in RMP. Indirectly through Midstream Holdings, we own and control the general partner of RMP. As such, the results of operations of RMP and the assets we contributed to it remain consolidated into our results of operations following the RMP IPO and concurrent contribution. However, for the periods after December 22, 2014, our results of operations give effect to the noncontrolling interest in RMP attributable to the 50.0% limited partner interest of 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, our midstream segment did not charge fees for providing such services to our exploration and production segment.
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 distribution revenues are primarily derived from our gathering and compression contracts with third parties in addition to fees charged to outside working interest owners.

40



The following table provides detail of our operating revenues from the condensed consolidated statements of operations for the three and nine months ended September 30, 2015 and 2014.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
(in thousands)
2015
 
2014
 
2015
 
2014
Natural gas sales
$
129,689

 
$
67,625

 
$
323,294

 
$
246,583

Oil and NGL sales
456

 
206

 
4,653

 
233

Firm transportation sales, net
88

 
9,733

 
3,353

 
11,851

Gathering, compression and water distribution
13,388

 
1,563

 
34,755

 
2,878

Total operating revenues
$
143,621

 
$
79,127

 
$
366,055

 
$
261,545

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.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
NYMEX Henry Hub High ($/MMBtu)
$
2.93

 
$
4.44

 
$
3.30

 
$
7.94

NYMEX Henry Hub Low ($/MMBtu)
$
2.52

 
$
3.74

 
$
2.49

 
$
3.74

 
 
 
 
 
 
 
 
NYMEX Henry Hub Price ($/MMBtu)
$
2.73

 
$
3.94

 
$
2.78

 
$
4.47

Less: Average Basis Impact ($/MMBtu) (1)
(0.52
)
 
(1.11
)
 
(0.62
)
 
(0.62
)
Plus: Btu Uplift (MMBtu/Mcf)
0.11

 
0.14

 
0.11

 
0.19

Pre-Hedge Realized Price ($/Mcf)
$
2.32

 
$
2.97

 
$
2.27

 
$
4.04

(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 three and nine months ended September 30, 2014. The remainder of the three and nine months ended September 30, 2014 reflects 100% of the volumes sold by our Marcellus joint venture.
Consolidated Results of Operations
Below are some highlights of our financial and operating results for the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014:
Our natural gas, oil and NGL sales were $130.1 million and $67.8 million in the three months ended September 30, 2015 and 2014, respectively, and $327.9 million and $246.8 million in the nine months ended September 30, 2015 and 2014, respectively.
Our production volumes were 56,031 MMcfe and 22,757 MMcfe in the three months ended September 30, 2015 and 2014, respectively, and 143,752 MMcfe and 61,116 MMcfe in the nine months ended September 30, 2015 and 2014, respectively.
Our firm transportation sales, net, were $0.1 million and $9.7 million in the three months ended September 30, 2015 and 2014, respectively, and $3.4 million and $11.9 million in the nine months ended September 30, 2015 and 2014, respectively.
Our gathering, compression and water distribution revenues were $13.4 million and $1.6 million in the three months ended September 30, 2015 and 2014, respectively, and $34.8 million and $2.9 million in the nine months ended September 30, 2015 and 2014, respectively.
Our per unit cash production costs were $0.68 per Mcfe and $0.60 per Mcfe in the three months ended September 30, 2015 and 2014, respectively, and $0.67 per Mcfe and $0.68 per Mcfe in the nine months ended September 30, 2015 and 2014, respectively.
Our general and administrative expenses were $24.1 million and $10.5 million in the three months ended September 30, 2015 and 2014, respectively, and $62.0 million and $36.7 million in the nine months ended September 30, 2015 and 2014, respectively.
The following tables set forth selected operating and financial data for the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014:
 
Three Months Ended September 30,
 
 
 
Nine Months Ended September 30,
 
 
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Natural gas sales (in thousands):
$
129,689

 
$
67,625

 
$
62,064

 
$
323,294

 
$
246,583

 
$
76,711

Oil and NGL sales (in thousands):
456

 
206

 
250

 
4,653

 
233

 
4,420

Natural gas, oil and NGL sales (in thousands):
$
130,145

 
$
67,831

 
$
62,314

 
$
327,947

 
$
246,816

 
$
81,131

 
 
 
 
 
 
 
 
 
 
 
 
Firm transportation sales, net (in thousands):
$
88

 
$
9,733

 
$
(9,645
)
 
$
3,353

 
$
11,851

 
$
(8,498
)
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas production (MMcf):
55,806

 
22,740

 
33,066

 
142,454

 
61,096

 
81,358

Oil and NGL production (MBbls):
37

 
3

 
34

 
216

 
3

 
213

Total production (MMcfe)
56,031

 
22,757

 
33,274

 
143,752

 
61,116

 
82,636

 
 
 
 
 
 
 
 
 
 
 
 
Average natural gas prices before effects of hedges per Mcf:
$
2.32

 
$
2.97

 
$
(0.65
)
 
$
2.27

 
$
4.04

 
$
(1.77
)
Average realized natural gas prices after effects of hedges per Mcf (1):
3.18

 
2.98

 
0.20

 
3.10

 
3.70

 
(0.60
)
Average oil and NGL prices per Bbl:
12.17

 
72.48

 
(60.31
)
 
21.51

 
68.82

 
(47.31
)
 
 
 
 
 
 
 
 
 
 
 
 
Average costs per Mcfe:
 
 
 
 
 
 
 
 
 
 
 
Lease operating
$
0.22

 
$
0.20

 
$
0.02

 
$
0.24


$
0.27

 
$
(0.03
)
Gathering, compression and transportation
0.43

 
0.35

 
0.08

 
0.39


0.37

 
0.02

Production taxes and impact fees
0.03

 
0.05

 
(0.02
)
 
0.04


0.04

 

General and administrative
0.43

 
0.46

 
(0.03
)
 
0.43


0.60

 
(0.17
)
Depreciation, depletion and amortization
1.59

 
1.49

 
0.10

 
1.59


1.50

 
0.09

 
 
 
 
 
 
 
 
 
 
 
 
Total gathering, compression and water distribution (in thousands):
$
13,388

 
$
1,563

 
$
11,825

 
$
34,755

 
$
2,878

 
$
31,877

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

41



 
Three Months Ended September 30,
 
 
 
Nine Months Ended September 30,
 
 
(in thousands, except per share data)
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
$
130,145

 
$
67,831

 
$
62,314

 
$
327,947

 
$
246,816

 
$
81,131

Firm transportation sales, net
88

 
9,733

 
(9,645
)
 
3,353

 
11,851

 
(8,498
)
Gathering, compression and water distribution
13,388

 
1,563

 
11,825

 
34,755

 
2,878

 
31,877

Total operating revenues
143,621

 
79,127

 
64,494

 
366,055

 
261,545

 
104,510

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Lease operating
12,325

 
4,553

 
7,772

 
35,006

 
16,406

 
18,600

Gathering, compression and transportation
24,248

 
7,992

 
16,256

 
55,510

 
22,464

 
33,046

Production taxes and impact fees
1,955

 
1,114

 
841

 
5,103

 
2,624

 
2,479

Exploration
830

 
623

 
207

 
1,925

 
1,582

 
343

Midstream operation and maintenance
4,831

 
1,729

 
3,102

 
10,963

 
3,564

 
7,399

Incentive unit (income) expense
(686
)
 
26,418

 
(27,104
)
 
45,870

 
101,695

 
(55,825
)
Stock compensation expense
4,214

 
2,058

 
2,156

 
11,681

 
3,274

 
8,407

Acquisition expense

 
2,246

 
(2,246
)
 

 
2,246

 
(2,246
)
General and administrative
24,113

 
10,458

 
13,655

 
62,028

 
36,733

 
25,295

Depreciation, depletion and amortization
89,275

 
33,853

 
55,422

 
227,996

 
91,912

 
136,084

Amortization of intangible assets
408

 
408

 

 
1,224

 
748

 
476

Other (income) expense
(265
)
 

 
(265
)
 
3,624

 

 
3,624

Total operating expenses
161,248

 
91,452

 
69,796

 
460,930

 
283,248

 
177,682

 
 
 
 
 
 
 
 
 
 
 
 
Operating loss
(17,627
)
 
(12,325
)
 
(5,302
)
 
(94,875
)
 
(21,703
)
 
(73,172
)
Interest expense
(23,949
)
 
(15,754
)
 
(8,195
)
 
(63,437
)
 
(38,737
)
 
(24,700
)
Gain on purchase of Marcellus joint venture

 

 

 

 
203,579

 
(203,579
)
Other income (loss)
698

 
(216
)
 
914

 
1,894

 
180

 
1,714

Gain on derivative instruments
127,072

 
36,935

 
90,137

 
184,729

 
5,357

 
179,372

Amortization of deferred financing costs
(1,313
)
 
(707
)
 
(606
)
 
(3,722
)
 
(1,728
)
 
(1,994
)
Loss on extinguishment of debt

 
(790
)
 
790

 

 
(3,934
)
 
3,934

Write-off of deferred financing costs

 

 

 

 
(6,896
)
 
6,896

Equity loss of joint ventures

 

 

 

 
(2,656
)
 
2,656

Income before income taxes
84,881

 
7,143

 
77,738

 
24,589

 
133,462

 
(108,873
)
Income tax expense
(19,797
)
 
(14,005
)
 
(5,792
)
 
(18,335
)
 
(18,787
)
 
452

Net income (loss)
65,084

 
(6,862
)
 
71,946

 
6,254

 
114,675

 
(108,421
)
Less: Net income attributable to noncontrolling interests
(6,134
)
 

 
(6,134
)
 
(16,833
)
 

 
(16,833
)
Net income (loss) attributable to Rice Energy Inc.
$
58,950

 
$
(6,862
)
 
$
65,812

 
$
(10,579
)
 
$
114,675

 
$
(125,254
)
 
 
 
 
 
 
 
 
 
 
 
 
Weighted average number of shares of common stock - basic
136,381,909

 
132,269,081

 
4,112,828

 
136,330,198

 
125,411,524

 
10,918,674

Weighted average number of shares of common stock - diluted
136,521,828

 
132,269,081

 
4,252,747

 
136,330,198

 
125,678,095

 
10,652,103

Earnings per share - basic
$
0.43

 
$
(0.05
)
 
0.48

 
$
(0.08
)
 
$
0.91

 
(0.99
)
Earnings per share - diluted
$
0.43

 
$
(0.05
)
 
0.48

 
$
(0.08
)
 
$
0.91

 
(0.99
)

42




Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014
Total operating revenues. The $64.5 million increase in total operating revenues was mainly a result of an increase in natural gas, oil and NGL production in the third quarter of 2015 compared to the third quarter of 2014 which was the result of increased drilling and completion activity, 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 the third quarter of 2015 was $2.32 per Mcf compared to $2.97 per Mcf in the third quarter of 2014, in each case before the effect of hedges. Additionally, operating revenues were positively impacted by a $11.8 million increase in gathering, compression and water service revenues period-over-period. This increase primarily relates to increased third-party volumes and related revenues on gathering contracts as well as additional third-party volumes and revenues on new gathering contracts. Firm transportation sales, net, decreased period-over-period from $9.7 million in the third quarter of 2014 to $0.1 million in the third quarter of 2015 as we further utilized existing contracts for our operated production.
Lease operating. The $7.8 million increase in lease operating expenses was attributable to an increase in the number of producing wells in the third quarter of 2015 as compared to the prior period.
Gathering, compression and transportation. Gathering, compression and transportation expense for the third quarter of 2015 is mainly comprised of $20.0 million of transportation contracts with third parties and $2.5 million of gathering charges from third parties. The $16.3 million increase in the expense was primarily attributable to increased firm transportation expense in the third quarter of 2015 compared to the third quarter of 2014.
Midstream operation and maintenance. The $3.1 million increase in midstream operation and maintenance expense period-over-period was primarily due to additional contract labor for the maintenance of existing assets as well as additional leases on compression equipment.
Incentive unit expense. Incentive unit expense decreased $27.1 million period-over-period. In the third quarter of 2014, the $26.4 million expense primarily consisted of $6.9 million of non-cash compensation expense related to the Rice Holdings incentive units, $7.5 million of non-cash compensation expense related to the quarterly fair market value adjustment for the NGP Holdings incentive units and $12.0 million related to payments made to certain holders of NGP Holdings incentive units. In the third quarter of 2015, the $0.7 million income consisted of $7.0 million of non-cash compensation expense related to the Rice Holdings incentive units, offset by $7.7 million of non-cash income related to the quarterly fair market value adjustment for the NGP Holdings incentive units which was largely driven by the decline in the Company’s stock price at September 30, 2015. See “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—9. Incentive Units” for additional information.
General and administrative. The $13.7 million increase period-over-period was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. At September 30, 2015, we had 376 employees as compared to 255 employees at September 30, 2014. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation and information technology projects to support our growth activities.
DD&A. The $55.4 million increase period-over-period was primarily a result of an increase in production driven by a greater number of producing wells in the third quarter of 2015 compared to third quarter of 2014, which is consistent with our expanded drilling program. In addition, the increase was also the result of an increase in midstream assets placed in service in the third quarter of 2015 as compared to the third quarter of 2014 and the related depreciation on those assets.
Interest expense. The $8.2 million increase period-over-period was a result of higher levels of average borrowings outstanding during the third quarter of 2015 in order to fund our capital programs.
Gain on derivative instruments. The $127.1 million gain on derivative contracts in the third quarter of 2015 was due to cash receipts of $47.8 million on the settlement of maturing contracts and a $79.3 million unrealized gain in the third quarter of 2015 due to the decline in commodity prices as compared to our hedged prices. The $36.9 million gain on derivative contracts in the third quarter of 2014 was comprised of $36.8 million in unrealized gains and $0.1 million of cash receipts on the settlement of maturing contracts.
Income tax expense. The $5.8 million increase in the income tax expense period-over-period was attributable to an increase in taxable income offset by a lower estimated annual effective state tax rate.

43



Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Total operating revenues. The $104.5 million increase in total operating revenues was mainly a result of the gathering, compression and water service revenues for the nine months ended September 30, 2015 as compared to the same period in 2014. In addition, an increase in natural gas, oil and NGL production for the nine months ended September 30, 2015 compared to 2014 was the result of increased drilling and completion activity, 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 for the nine months ended September 30, 2015 was $2.27 per Mcf compared to $4.04 per Mcf for the nine months ended September 30, 2014, in each case before the effect of hedges. Additionally, operating revenues were positively impacted by a $31.9 million increase in gathering, compression and water service revenues period-over-period. This increase primarily relates to increased third-party volumes and related revenues on existing gathering contracts as well as additional third-party volumes and revenues on new gathering contracts. Firm transportation sales, net, decreased period-over-period from $11.9 million for the nine months ended September 30, 2014 to $3.4 million for the nine months ended September 30, 2015 as we further utilized existing contracts for our operated production.
Lease operating. The $18.6 million increase in lease operating expenses was attributable to an increase in the number of producing wells in the nine months ended September 30, 2015 as compared to the prior period. However, lease operating expenses per unit of production decreased period-over-period due to improved operating efficiencies, primarily relating to production water hauling and recycling.
Gathering, compression and transportation. Gathering, compression and transportation expense for the nine months ended September 30, 2015 is mainly comprised of $44.1 million of transportation contracts with third parties, $4.2 million of charges from our working interest partners on our non-operated wells and $4.1 million of gathering charges from third parties. The $33.0 million increase in the expense period-over-period was primarily attributable to increased firm transportation expense in the nine months ended September 30, 2015 compared to the same period in 2014.
Midstream operation and maintenance. The $7.4 million increase in midstream operation and maintenance expense period-over-period was primarily due to additional contract labor for the maintenance of existing assets as well as additional leases on compression equipment.
Incentive unit expense. Incentive unit expense decreased $55.8 million period-over-period. In the nine months ended September 30, 2014, the $101.7 million expense primarily consisted of $34.7 million and $47.1 million of non-cash compensation expense related to the Rice Holdings and NGP Holdings incentive units, respectively, as well as $3.4 million of non-cash compensation expense related to extinguishment of the legacy incentive unit burden of Mr. Daniel J. Rice IV and $16.4 million related to payments made to certain holders of NGP Holdings incentive units. In the nine months ended September 30, 2015, the $45.9 million expense consisted of $27.7 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 $8.6 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 the Company’s stock price at September 30, 2015. See “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—9. Incentive Units” for additional information.
General and administrative. The $25.3 million increase period-over-period was primarily attributable to the addition of personnel to support our growth activities and related salary and employee benefits. At September 30, 2015, we had 376 employees as compared to 255 employees at September 30, 2014. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation and information technology projects to support our growth activities as well as additional costs incurred in connection with our obligations under Section 404 of the Sarbanes Oxley Act of 2002.
DD&A. The $136.1 million increase period-over-period was primarily a result of an increase in production driven by a greater number of producing wells in the nine months ended September 30, 2015 compared to the same period in 2014, which is consistent with our expanded drilling program. In addition, the increase was also the result of an increase in midstream assets placed in service in the nine months ended September 30, 2015 as compared to the same period in 2014 and the related depreciation on those assets.
Interest expense. The $24.7 million increase was a result of higher levels of average borrowings outstanding during the nine months ended September 30, 2015 in order to fund our capital programs.
Gain on derivative instruments. The $184.7 million gain on derivative contracts in the nine months ended September 30, 2015 was due to cash receipts of $117.7 million on the settlement of maturing contracts and a $67.0 million unrealized gain in 2015 due to the decline in commodity prices as compared to our hedged prices. The $5.4 million gain on derivative contracts in

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the nine months ended September 30, 2014 was comprised of $26.1 million in unrealized gains and $20.8 million of cash payments on the settlement of maturing contracts.
Income tax expense. The $0.5 million decrease in income tax expense period-over-period was primarily attributable to a lower estimated annual effective tax rate.
Business Segment Results of Operations
We operate in two business segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, exploration and development of natural gas, oil and NGL properties in the Appalachian Basin. The midstream segment is engaged in the gathering and compression of natural gas, oil and NGL production of, and in the provision of water services to support the well completion activities of Rice Energy and third parties. The midstream segment includes the financial results of the Partnership as well as the Company’s 50.0% limited partner interest and incentive distribution rights in the Partnership.
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—6. Financial Information by Business Segment” for a reconciliation of each segment’s operating income to our consolidated operating income.
The following tables set forth selected operating and financial data for each business segment during the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014:
Exploration and Production Segment
 
Three Months Ended September 30,
 
 
 
Nine Months Ended September 30,
 
 
(in thousands, except volumes)
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Natural gas, oil and NGL sales
$
130,145

 
$
67,831

 
$
62,314

 
$
327,947

 
$
246,816

 
$
81,131

Firm transportation sales, net
88

 
9,733

 
(9,645
)
 
3,353

 
11,851

 
(8,498
)
Total operating revenues
130,233

 
77,564

 
52,669

 
331,300

 
258,667

 
72,633

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Lease operating
12,325

 
4,553

 
7,772

 
35,006

 
16,406

 
18,600

Gathering, compression and transportation
41,654

 
8,049

 
33,605

 
102,021

 
22,666

 
79,355

Production taxes and impact fees
1,955

 
1,114

 
841

 
5,103

 
2,624

 
2,479

Exploration
830

 
623

 
207

 
1,925

 
1,582

 
343

Incentive unit (income) expense
(453
)
 
19,468

 
(19,921
)
 
43,930

 
90,032

 
(46,102
)
Stock compensation expense
2,657

 
1,786

 
871

 
7,889

 
2,871

 
5,018

General and administrative
18,592

 
10,342

 
8,250

 
48,007

 
29,340

 
18,667

Depreciation, depletion and amortization
84,408

 
32,854

 
51,554

 
216,665

 
89,316

 
127,349

Other (income) expense
(71
)
 

 
(71
)
 
2,979

 

 
2,979

Acquisition expense

 
762

 
(762
)
 

 
762

 
(762
)
Total operating expenses
161,897

 
79,551

 
82,346

 
463,525

 
255,599

 
207,926

 
 
 
 
 
 
 
 
 
 
 
 
Operating (loss) income
$
(31,664
)
 
$
(1,987
)
 
$
(29,677
)
 
$
(132,225
)
 
$
3,068

 
$
(135,293
)
 
 
 
 
 
 
 
 
 
 
 
 
Operating volumes:
 
 
 
 
 
 
 
 
 
 
 
Natural gas production (MMcf):
55,806

 
22,740

 
33,066

 
142,454

 
61,096

 
81,358

Oil and NGL production (MBbls):
37

 
3

 
34

 
216

 
3

 
213

Total production (MMcfe)
56,031

 
22,757

 
33,274

 
143,752

 
61,116

 
82,636


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Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014
Total operating revenues. The $62.3 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in the third quarter of 2015 compared to the third quarter of 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 the third quarter of 2015 was $2.32 per Mcf compared to $2.97 per Mcf in the third quarter of 2014, in each case before the effect of hedges. The increase in operating revenues for the third quarter of 2015 were offset by a $9.6 million decrease period-over-period 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. The $7.8 million increase in lease operating expenses was attributable to an increase in the number of producing wells in 2015 as compared to the prior period.
Gathering, compression and transportation. Gathering, compression and transportation expense for the third quarter of 2015 primarily includes $20.0 million of transportation contracts with third parties and $19.9 million of affiliate and third party gathering fees. The $33.6 million increase in gathering, compression and transportation expenses was mainly due to the gathering agreements with the midstream segment as well as increased firm transportation expense in the third quarter of 2015 compared to the third quarter of 2014.
General and administrative. The $8.3 million increase in segment general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support our growth activities. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation and information technology projects to support our growth activities.
DD&A. The $51.6 million increase was a result of an increase in production and greater number of producing wells in the third quarter of 2015 compared to 2014, which is consistent with our expanded drilling program.
Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Total operating revenues. The $81.1 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 $2.27 per Mcf compared to $4.04 per Mcf in 2014, in each case before the effect of hedges. The increase in operating revenues in 2015 were offset by a $8.5 million decrease period-over-period 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. The $18.6 million increase in lease operating expenses was attributable to an increase in the number of producing wells in 2015 as compared to the prior period. However, lease operating expenses per unit of production decreased period-over-period due to improved operating efficiencies, primarily relating to production water hauling and recycling.
Gathering, compression and transportation. Gathering, compression and transportation expense for 2015 is primarily comprised of $50.6 million of affiliate and third party gathering fees, $44.1 million of transportation contracts with third parties and $4.2 million of charges from our working interest partners on our non-operated wells. The $79.4 million increase in gathering, compression and transportation expenses was mainly due to the gathering agreements with the midstream segment as well as increased firm transportation expense in 2015 compared to 2014.
General and administrative. The $18.7 million increase in segment general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support our growth activities. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation and information technology projects to support our growth activities as well as additional costs incurred in connection with our obligations under Section 404 of the Sarbanes Oxley Act of 2002.
DD&A. The $127.3 million increase was a result of an increase in production and greater number of producing wells in 2015 compared to 2014, which is consistent with our expanded drilling program.


46



Midstream Segment
 
Three Months Ended September 30,
 
 
 
Nine Months Ended September 30,
 
 
(in thousands, except volumes)
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering revenues
$
28,414

 
$
1,409

 
$
27,005

 
$
72,324

 
$
2,712

 
$
69,612

Compression revenues
420

 
211

 
209

 
1,594

 
368

 
1,226

Water distribution revenues
9,932

 

 
9,932

 
29,107

 

 
29,107

Total operating revenues
38,766

 
1,620

 
37,146

 
103,025

 
3,080

 
99,945

 
 
 
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
Midstream operation and maintenance
4,831

 
1,729

 
3,102

 
10,963

 
3,564

 
7,399

Incentive unit (income) expense
(233
)
 
6,950

 
(7,183
)
 
1,940

 
11,663

 
(9,723
)
Stock compensation expense
1,557

 
272

 
1,285

 
3,792

 
403

 
3,389

General and administrative
5,521

 
116

 
5,405

 
14,021

 
7,393

 
6,628

Depreciation, depletion and amortization
5,345

 
999

 
4,346

 
12,341

 
2,596

 
9,745

Amortization of intangible assets
408

 
408

 

 
1,224

 
748

 
476

Acquisition costs

 
1,484

 
(1,484
)
 

 
1,484

 
(1,484
)
        Other (income) expense
(194
)
 

 
(194
)
 
645

 

 
645

Total operating expenses
17,235

 
11,958

 
5,277

 
44,926

 
27,851

 
17,075

 
 
 
 
 
 
 
 
 
 
 
 
Operating income (loss)
$
21,531

 
$
(10,338
)
 
$
31,869

 
$
58,099

 
$
(24,771
)
 
$
82,870

 
 
 
 
 
 
 
 
 
 
 
 
Operating volumes:
 
 
 
 
 
 
 
 
 
 
 
Gathering volumes (MDth/d):
990

 
392

 
598

 
850

 
338

 
512

Compression volumes (MDth/d):
39

 
32

 
7

 
54

 
19

 
35

Water distribution volumes (MMgal):
227

 

 
227

 
575

 

 
575

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014
Total operating revenues. The $37.1 million increase in total operating revenues was mainly the result of the gathering and water service contracts between the exploration and production and midstream segments as well as an increase in third-party gathering volumes.
Midstream operation and maintenance. Midstream operation and maintenance expense for the third quarter of 2015 includes $2.7 million of expense relative to our fresh water distribution assets and $2.1 million of expense relative to our gathering assets. The $3.1 million increase in expense period-over-period was primarily due to additional contract labor for the maintenance of existing assets as well additional leases on compression equipment.
General and administrative. The $5.4 million increase in general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support our growth activities. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation and information technology projects to support our growth activities.
DD&A. The $4.3 million increase was mainly the result of an increase in midstream assets placed in service in the third quarter of 2015 as compared to the third quarter of 2014 and the related depreciation on those assets.
Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014
Total operating revenues. The $99.9 million increase in total operating revenues period-over-period was mainly the result of the gathering and water service contracts between the upstream and midstream segments as well as an increase in third-party gathering volumes.

47



Midstream operation and maintenance. Midstream operation and maintenance expense for 2015 includes $6.0 million of expense relative to our fresh water distribution assets and $5.0 million of expense relative to our gathering assets. The $7.4 million increase in expense period-over-period was primarily due to additional contract labor for the maintenance of existing assets as well additional leases on compression equipment.
General and administrative. The $6.6 million increase in general and administrative expense period-over-period was primarily attributable to costs associated with personnel to support our growth activities. Additionally, general and administrative expenses increased period-over-period as a result of the costs associated with our accounting system implementation and information technology projects to support our growth activities as well as additional costs incurred in connection with our obligations under Section 404 of the Sarbanes Oxley Act of 2002.
DD&A. The $9.7 million increase was mainly the result of an increase in midstream assets placed in service in 2015 as compared to 2014 and the related depreciation on those assets. Additionally, the increase was the result of a $0.8 million disposal of a water asset and the related write-off of the net book value of the asset in accordance with successful efforts accounting.
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 production online.
Cash Flow Provided by Operating Activities
Net cash provided by operating activities was $270.4 million for the nine months ended September 30, 2015, compared to $69.7 million of net cash provided by operating activities for the nine months ended September 30, 2014. The increase in operating cash flow was primarily due to increases in operating income including cash receipts on settled derivatives, which is consistent with increased production.
Cash Flow Used In Investing Activities
During the nine months ended September 30, 2015 cash flows used in investing activities consisted of $919.9 million for capital expenditures for property and equipment, while the $1,154.5 million of cash flows used in investing activities for the nine months ended September 30, 2014 primarily consisted of $642.4 million of capital expenditures for property and equipment and $523.7 million related to acquisition activity.
Capital expenditures for exploration and production were $638.5 million and $412.2 million for the nine months ended September 30, 2015 and 2014, respectively. The increase of $226.3 million was primarily attributable to the acquisition and development of our natural gas properties. In November, we revised our 2015 exploration and production capital expenditure budget from $680.0 million to $730.0 million.
Capital expenditures for midstream operations totaled $303.1 million and $230.2 million for the nine months ended September 30, 2015 and 2014, respectively. The increase of $73.0 million was attributable to the expansion of the Company’s midstream infrastructure. In November, we revised our 2015 midstream capital expenditure budget from $390.0 million to $500.0 million.
Cash Flow Provided By Financing Activities
Net cash provided by financing activities of $599.3 million during the nine months ended September 30, 2015 was primarily the result of the proceeds from our 2023 Notes offering (discussed below) and borrowings on the Midstream Holdings Revolving Credit Facility and the RMP Revolving Credit Facility, offset by distributions to the Partnership’s public unitholders.  Net cash provided by financing activities of $1,185.2 million during the nine months ended September 30, 2014 was primarily the result of proceeds from our 2022 Notes offering (discussed below), our IPO, and August 2014 equity offering (net of offering costs), which was offset by repayments of debt.

48



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. We used $301.8 million of the net proceeds to repay and retire the Second Lien Term Loan Facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million, and expect to use the remainder to fund our capital expenditure plan.
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 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 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 to the redemption date. Upon the occurrence of a Change of Control (as defined in the indenture governing the 2022 Notes), 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 to the date of purchase. 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 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. The Company used a portion of the net proceeds for general corporate purposes, including capital expenditures, and intends to use the remaining net proceeds for general corporate purposes, including capital expenditures.
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, 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 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 to the date of purchase. On and 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.
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) 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 our $300.0 million Senior Secured Revolving Credit Facility (the “Senior Secured Revolving Credit Facility”). In April 2014, we, as borrower, and Rice Drilling B, as predecessor borrower, amended and restated

49



the credit agreement governing the Senior Secured Revolving Credit Facility (as amended, the “Amended Credit Agreement”) to, among other things, assign all of Rice Drilling B’s rights and obligations under the Senior Secured Revolving Credit Facility to us, and we assumed all such rights and obligations as borrower under the Amended Credit Agreement.
As of September 30, 2015, the borrowing base under the Amended Credit Agreement governing the Senior Secured Revolving Credit Facility was $650.0 million and the sublimit for letters of credit was $175.0 million. The Company had zero borrowings outstanding and $125.4 million in letters of credit outstanding under its Amended Credit Agreement as of September 30, 2015, resulting in availability of $524.6 million. On October 30, 2015, a scheduled redetermination occurred as a result of which the borrowing base of the Senior Secured Revolving Credit Facility was increased from $650.0 million to $750.0 million and the sublimit for letters of credit increased from $175.0 million to $250.0 million. The next redetermination of the borrowing base is scheduled for April 1, 2016. The maturity date of the Senior Secured Revolving Credit Facility is January 29, 2019.
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 150 to 250 basis points, depending on the percentage of 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 50 to 150 basis points, depending on the percentage of borrowing base utilized.
The Amended Credit Agreement is secured by liens on at least 80% 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 Amended Credit Agreement is guaranteed by such restricted subsidiaries.
The Amended 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 Amended Credit Agreement to be immediately due and payable. We were in compliance with such covenants and ratios as of September 30, 2015.
Midstream Holdings Revolving Credit Facility
On December 22, 2014, Midstream Holdings entered into a revolving credit facility (“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 September 30, 2015, Midstream Holdings had $152.0 million borrowings outstanding and $0.1 million letters of credit under this facility. 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 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 general partner of RMP, or Rice Energy and its subsidiaries other than Midstream Holdings).
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 such covenants and ratios as of September 30, 2015.
RMP Revolving Credit Facility
On December 22, 2014, Rice Midstream OpCo entered into a revolving credit facility (the “RMP Revolving Credit Facility”) with RMP, Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount 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. As of September 30, 2015,

50



Rice Midstream OpCo had $72.0 million borrowings outstanding and no letters of credit under this facility. 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.
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 revolving credit facility, 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 175 to 275 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 75 to 175 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 35 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 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 such covenants and ratios as of September 30, 2015.
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 (A) the percentage of internally forecasted production (Column A) and (B) the lesser of (i) the percentage of proved reserve volumes (Column B) according to the table below and (ii) 140% of the monthly average production for the most recent period of three consecutive months.
Months next succeeding the time as of which compliance is measured
 
Column A
 
Column B
Months 1 through 12
 
85
%
 
75
%
Months 13 through 24
 
85
%
 
75
%
Months 25 through 36
 
85
%
 
75
%
Months 37 through 48
 
85
%
 
50
%
Months 49 through 60
 
85
%
 
50
%
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—4. Derivative Instruments and 5. Fair Value of Financial Instruments” included elsewhere in this Quarterly Report.
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 nine different counterparties. As of September 30, 2015, our contracts with Wells Fargo Bank N.A. and Bank of Montreal accounted for 32% and 26% of the net fair market value of our derivative assets, respectively. We believe Wells Fargo Bank N.A. and Bank of Montreal are acceptable credit risks. We are not required to provide credit support or collateral to Wells Fargo Bank N.A. or Bank

51



of Montreal under current contracts, nor are they required to provide credit support or collateral to us. As of September 30, 2015 and December 31, 2014, we did not have any past due receivables from counterparties.
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 2014 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.  Given the rapid decline in the market prices of natural gas, NGLs, and oil that occurred during the fourth quarter of 2014 and sustained depressed market prices during 2015, we have compared estimated undiscounted future cash flows using strip pricing for our proved properties to the carrying value of those properties.  Because estimated undiscounted future cash flows have exceeded the associated carrying values of proved properties at the end of each quarter, pursuant to generally accepted accounting principles for successful efforts accounting, it has not been necessary for us to estimate the fair value of the properties, nor have any impairment losses been realized during the three or nine month period ended September 30, 2015. Current future commodity prices continue to support the recoverability of our proved properties; however, we are unable to predict commodity prices with any greater precision than the futures market. Further reductions in commodity prices within the futures market could trigger an impairment of proved natural gas properties in the future.
We also expect that the decrease in commodity prices has caused the pre-tax PV-10 of the estimated cash flows from our reserves, based upon average yearly prices computed using SEC rules, to decrease substantially as compared to amounts reflected as of December 31, 2014.  We do not believe that the current commodity pricing environment will have a material effect on our proved reserve quantities at December 31, 2015 compared to our proved reserve quantities at December 31, 2014.
Off-Balance Sheet Arrangements
Currently, we do 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—7. Commitments and Contingencies” for a description of our commitments and contingencies.


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Item 3. 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, NGLs, and oil production. Realized pricing is primarily driven by market prices applicable to our U.S. natural gas and oil production. Pricing for natural gas, NGLs, and oil 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, NGLs, and oil production to mitigate the potential negative impact on our cash flow.
Our financial hedging activities are intended to support natural gas, NGLs, and oil prices at targeted levels and to manage our exposure to natural gas, NGLs, and oil 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 September 30, 2015, 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, 2022. Our commodity hedge position as of September 30, 2015 is summarized in Note 4 to our condensed consolidated financial statements included elsewhere in the Quarterly Report. Our financial hedging activities are intended to support natural gas, NGLs and oil 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 31, 2022, 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 September 30, 2015, we had zero borrowings and approximately $125.4 million in letters of credit outstanding under our Senior Secured Revolving Credit Facility. As of September 30, 2015, we had availability under our Senior Secured Revolving Credit Facility of approximately $524.6 million and a borrowing base of $650.0 million. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 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 50 to 150 basis points, depending on the percentage of our borrowing base utilized.
As of September 30, 2015, Rice Midstream Holdings had $152.0 million of borrowings and $0.1 million letters of credit outstanding under the Midstream Holdings Revolving Credit Facility. Under the revolving credit facility, Rice 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.

53



The average annual interest rate incurred on the Midstream Holdings Revolving Credit Facility during the nine months ended September 30, 2015 was approximately 2.5%.  A 1.0% increase in the applicable average interest rates for the nine months ended September 30, 2015 would have resulted in an estimated $0.5 million increase in interest expense.
As of September 30, 2015, Rice Midstream OpCo had $72.0 million of borrowings and no letters of credit outstanding under the RMP Revolving Credit Facility. Under the RMP Revolving Credit Facility, Rice Midstream OpCo may elect to borrow in Eurodollars or at the base rate. Eurodollar loans will bear interest at a rate per annum equal to the applicable LIBOR Rate plus an applicable margin ranging from 175 to 275 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 75 to 175 basis points, depending on the leverage ratio then in effect.
The average annual interest rate incurred on the RMP Revolving Credit Facility during the nine months ended September 30, 2015 was approximately 1.9%.  A 1.0% increase in the applicable average interest rates for the nine months ended September 30, 2015 would have resulted in a $0.2 million estimated increase in interest expense.
As of September 30, 2015, 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 ($133.1 million as of September 30, 2015) and the sale of our natural gas production ($84.2 million in receivables as of September 30, 2015), 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 three 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.

54



Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2015. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2015.
Changes in Internal Control over Financial Reporting
During the quarter ended June 30, 2015, we completed the implementation of a new accounting application. We took the necessary steps to monitor and maintain appropriate internal controls during this period of change, including procedures to preserve the integrity of the data converted during the application implementation. Additionally, we provided training related to this application to individuals using the application to carry out their job responsibilities. We believe the new application will enhance our internal controls over financial reporting due to enhanced automation and integration of related processes. The application change was not undertaken in response to any deficiencies in our internal control over financial reporting.
During the quarter ended September 30, 2015, we completed the design and documentation of internal control processes and procedures relating to the new application and modules to supplement and complement existing internal control over certain respective job areas. Testing of the controls related to the new application and accounting functions is ongoing and is included in the scope of our assessment of our internal control over financial reporting for 2015, which will be completed in conjunction with the filing of our Annual Report on Form 10-K for the year ending December 31, 2015. We will continue to monitor controls through and around the application to provide reasonable assurance that controls are effective, and, as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reporting.
There were no other changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(t) under the Exchange Act) during our most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

55



PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The Company is party to various legal and/or regulatory proceedings from time to time 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 the Company determines 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.
Environmental Proceedings
In September 2015, the Company received a Notice of Proposed Assessment from the Pennsylvania Department of Environmental Protection (“DEP”) of proposed civil penalties related to seven Notices of Violations (“NOVs”) received in 2015 under the Clean Streams Law, the 2012 Oil and Gas Act, and the Solid Waste Management Act. Prior to and since receiving the NOVs, the Company has cooperated with the DEP and in certain cases remediated the affected areas under the NOVs. While resolution of the NOVs may result in monetary sanctions of more than $100,000, the Company does not expect the penalties, individually or in the aggregate, to have a material impact on its financial results.
Item 1A. Risk Factors
Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
There have been no material changes in our risk factors from those described in our 2014 Annual Report. For a discussion of our potential risks and uncertainties, see the information in “Item 1A. Risk Factors” in our 2014 Annual Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Unregistered sales of securities. There were no sales of unregistered equity securities during the period covered by this report.
Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended September 30, 2015:
Period
 
Total Number of Shares Withheld (1)
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
July 1 - July 31, 2015
 
220

 
$
19.32

 

 

August 1, August 31, 2015
 

 

 

 

September 1 - September 30, 2015
 
728

 
20.08

 

 

    Total
 
948

 
$
19.90

 

 

(1)
All shares withheld during the third quarter of 2015 were used to offset tax withholding obligations that occur upon the vesting of restricted stock units and delivery of common stock under the terms of the Company’s long-term incentive plan.
Item 6. Exhibits
Exhibit Number

Exhibit
3.1
 
Amended and Restated Certificate of Incorporation of Rice Energy Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.2
 
Amended and Restated Bylaws of Rice Energy Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.1
 
Fifth Amendment to Third Amended and Restated Credit Agreement and Amendment to Limited Consent and Second Amendment, dated as of July 17, 2015, among Rice Energy Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on July 21, 2015).
31.1*

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**

Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**

Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*

XBRL Instance Document.
101.SCH*

XBRL Schema Document.
101.CAL*
 
XBRL Calculation Linkbase Document.
101.DEF*
 
XBRL Definition Linkbase Document.
101.LAB*
 
XBRL Labels Linkbase Document.
101.PRE*
 
XBRL Presentation Linkbase Document.
    
*
Filed herewith.
**
Filed herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Quarterly Report on Form 10-Q and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”), or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Exchange Act of 1933, as amended, except to the extent that the registrant specifically incorporates it by reference.

56



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, thereunto duly authorized.
 
 
 
RICE ENERGY INC.
 
 
 
 
Date:
November 5, 2015
By:
/s/ Daniel J. Rice IV
 
 
 
Daniel J. Rice IV
 
 
 
Director, Chief Executive Officer
 
 
 
(Principal Executive Officer)
 
 
 
 
Date:
November 5, 2015
By:
/s/ Grayson T. Lisenby
 
 
 
Grayson T. Lisenby
 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
(Principal Financial Officer)


57



EXHIBIT INDEX
Exhibit Number
 
Exhibit
3.1
 
Amended and Restated Certificate of Incorporation of Rice Energy Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.2
 
Amended and Restated Bylaws of Rice Energy Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.1
 
Fifth Amendment to Third Amended and Restated Credit Agreement and Amendment to Limited Consent and Second Amendment, dated as of July 17, 2015, among Rice Energy Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on July 21, 2015).
31.1*
 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**
 
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
 
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*
 
XBRL Instance Document.
101.SCH*
 
XBRL Schema Document.
101.CAL*
 
XBRL Calculation Linkbase Document.
101.DEF*
 
XBRL Definition Linkbase Document.
101.LAB*
 
XBRL Labels Linkbase Document.
101.PRE*
 
XBRL Presentation Linkbase Document.
*
Filed herewith.
**
Filed herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Quarterly Report on Form 10-Q and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”), or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Exchange Act of 1933, as amended, except to the extent that the registrant specifically incorporates it by reference.





58



GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
“Barrel” or “Bbl.” 42 U.S. gallons measured at 60 degrees Fahrenheit.
Btu.” One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree of Fahrenheit.
Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
DD&A.” Depreciation, depletion, amortization and accretion.
Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
“MBbls.” One thousand barrels.
Mcf.” One thousand cubic feet of natural gas.
Mcfe.” One thousand cubic feet of natural gas equivalent, determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate of natural gas liquids.
“MDth/d.” One thousand dekatherms per day.
“MMBbls.” One million barrels.
MMBtu.” One million Btu.
MMGal.” One million gallons.
MMcf.” One million cubic feet of natural gas.
MMcfe.” One million cubic feet of natural gas equivalent, determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate of natural gas liquids.
NGLs.” Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
NYMEX.” The New York Mercantile Exchange.
Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reserves.” The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

59



Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

60