SEC Filings

10-Q
RANGE RESOURCES CORP filed this Form 10-Q on 10/23/2018
Entire Document
 
rrc-10q_20180930.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

(Mark one)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

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: 001-12209

 

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

 

 

Delaware

 

34-1312571

(State or Other Jurisdiction of

Incorporation or Organization)

 

(IRS Employer

Identification No.)

 

100 Throckmorton Street, Suite 1200

Fort Worth, Texas

 

76102

(Address of Principal Executive Offices)

 

(Zip Code)

Registrant’s telephone number, including area code

(817) 870-2601

 

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

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

Yes      No  

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for shorter period that the registrant was required to submit such files).

Yes      No  

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

 

Large Accelerated Filer

 

Accelerated Filer

 

 

 

 

Non-Accelerated Filer

 

  

Smaller Reporting Company

 

 

 

 

Emerging Growth Company

 

 

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

 

 

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

Yes      No  

249,505,145 Common Shares were outstanding on October 19, 2018

 

 

 

 


RANGE RESOURCES CORPORATION

FORM 10-Q

Quarter Ended September 30, 2018

Unless the context otherwise indicates, all references in this report to “Range Resources,” “Range,” “we,” “us,” or “our” are to Range Resources Corporation and its directly and indirectly owned subsidiaries. For certain industry specific terms used in the Form 10-Q, please see “Glossary of Certain Defined Terms” in our 2017 Annual Report on Form 10-K.

TABLE OF CONTENTS

 

 

 

 

 

Page

PART I – FINANCIAL INFORMATION 

  

 

ITEM 1.

 

Financial Statements

  

3

 

 

   Consolidated Balance Sheets (Unaudited)

  

3

 

 

   Consolidated Statements of Operations (Unaudited)

  

4

 

 

   Consolidated Statements of Comprehensive Income (Loss) (Unaudited)

 

5

 

 

   Consolidated Statements of Cash Flows (Unaudited)

  

6

 

 

   Selected Notes to Consolidated Financial Statements (Unaudited)

  

7

ITEM 2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

  

30

ITEM 3.

 

Quantitative and Qualitative Disclosures about Market Risk

  

45

ITEM 4.

 

Controls and Procedures

  

48

PART II – OTHER INFORMATION

  

 

ITEM 1.

 

Legal Proceedings

  

48

ITEM 1A.

 

Risk Factors

  

48

ITEM 6.

 

Exhibits

  

49

 

 

 

 

 

SIGNATURES

  

50

 

 

2


PART I – FINANCIAL INFORMATION

 

ITEM 1. Financial Statements

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)

 

 

September 30,

 

 

December 31,

 

 

2018

 

 

2017

 

 

(Unaudited)

 

 

 

 

 

Assets

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

357

 

 

$

448

 

Accounts receivable, less allowance for doubtful accounts of $5,862 and $7,111

 

397,536

 

 

 

348,833

 

Derivative assets

 

103

 

 

 

58,607

 

Inventory and other

 

24,488

 

 

 

21,346

 

Total current assets

 

422,484

 

 

 

429,234

 

Derivative assets

 

1,114

 

 

 

273

 

Goodwill

 

1,641,197

 

 

 

1,641,197

 

Natural gas and oil properties, successful efforts method

 

13,643,196

 

 

 

13,216,453

 

Accumulated depletion and depreciation

 

(3,929,060

)

 

 

(3,649,716

)

 

 

9,714,136

 

 

 

9,566,737

 

Other property and equipment

 

112,404

 

 

 

114,361

 

Accumulated depreciation and amortization

 

(101,402

)

 

 

(99,695

)

 

 

11,002

 

 

 

14,666

 

Other assets

 

76,203

 

 

 

76,734

 

Total assets

$

11,866,136

 

 

$

11,728,841

 

 

 

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

$

225,874

 

 

$

343,871

 

Asset retirement obligations

 

6,327

 

 

 

6,327

 

Accrued liabilities

 

386,671

 

 

 

317,531

 

Accrued interest

 

37,739

 

 

 

43,511

 

Derivative liabilities

 

97,256

 

 

 

44,233

 

Total current liabilities

 

753,867

 

 

 

755,473

 

Bank debt

 

1,257,199

 

 

 

1,208,467

 

Senior notes

 

2,855,048

 

 

 

2,851,754

 

Senior subordinated notes

 

48,653

 

 

 

48,585

 

Deferred tax liabilities

 

731,723

 

 

 

693,356

 

Derivative liabilities

 

11,751

 

 

 

9,789

 

Deferred compensation liabilities

 

86,794

 

 

 

101,102

 

Asset retirement obligations and other liabilities

 

303,813

 

 

 

286,043

 

Total liabilities

 

6,048,848

 

 

 

5,954,569

 

Commitments and contingencies

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stockholders’ Equity

 

 

 

 

 

 

 

Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding

 

 

 

 

 

Common stock, $0.01 par, 475,000,000 shares authorized, 249,504,124 issued at

     September 30, 2018 and 248,144,397 issued at December 31, 2017

 

2,495

 

 

 

2,481

 

Common stock held in treasury, 10,067 shares at September 30, 2018 and 14,967

     shares at December 31, 2017

 

(404

)

 

 

(599

)

Additional paid-in capital

 

5,617,371

 

 

 

5,577,732

 

Accumulated other comprehensive loss

 

(1,124

)

 

 

(1,332

)

Retained earnings

 

198,950

 

 

 

195,990

 

Total stockholders’ equity

 

5,817,288

 

 

 

5,774,272

 

Total liabilities and stockholders’ equity

$

11,866,136

 

 

$

11,728,841

 

 

The accompanying notes are an integral part of these consolidated financial statements.

3


RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share data)

 

 

Three Months Ended September 30,

 

 

Nine Months Ended September 30,

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues and other income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGLs and oil sales

$

736,431

 

 

$

507,541

 

 

$

2,094,450

 

 

$

1,573,128

 

Derivative fair value (loss) income

 

(34,591

)

 

 

(88,426

)

 

 

(151,890

)

 

 

188,326

 

Brokered natural gas, marketing and other

 

109,385

 

 

 

63,117

 

 

 

267,448

 

 

 

170,544

 

Total revenues and other income

 

811,225

 

 

 

482,232

 

 

 

2,210,008

 

 

 

1,931,998

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Direct operating

 

30,926

 

 

 

36,888

 

 

 

104,136

 

 

 

96,331

 

Transportation, gathering, processing and compression

 

304,562

 

 

 

191,645

 

 

 

819,100

 

 

 

560,883

 

Production and ad valorem taxes

 

9,427

 

 

 

11,993

 

 

 

29,493

 

 

 

31,125

 

Brokered natural gas and marketing

 

116,080

 

 

 

59,773

 

 

 

274,421

 

 

 

169,180

 

Exploration

 

8,299

 

 

 

22,767

 

 

 

23,517

 

 

 

45,769

 

Abandonment and impairment of unproved properties

 

6,549

 

 

 

42,568

 

 

 

73,244

 

 

 

52,181

 

General and administrative

 

43,722

 

 

 

53,035

 

 

 

159,722

 

 

 

152,853

 

Termination costs

 

(336

)

 

 

(47

)

 

 

(373

)

 

 

4,049

 

Deferred compensation plan

 

223

 

 

 

(9,203

)

 

 

(559

)

 

 

(36,838

)

Interest

 

54,801

 

 

 

49,179

 

 

 

161,048

 

 

 

144,206

 

Depletion, depreciation and amortization

 

164,266

 

 

 

159,749

 

 

 

487,558

 

 

 

462,074

 

Impairment of proved properties

 

 

 

 

63,679

 

 

 

22,614

 

 

 

63,679

 

Loss (gain) on the sale of assets

 

30

 

 

 

(102

)

 

 

(149

)

 

 

(23,509

)

Total costs and expenses

 

738,549

 

 

 

681,924

 

 

 

2,153,772

 

 

 

1,721,983

 

Income (loss) before income taxes

 

72,676

 

 

 

(199,692

)

 

 

56,236

 

 

 

210,015

 

Income tax expense (benefit):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current

 

 

 

 

 

 

 

 

 

 

 

Deferred

 

24,137

 

 

 

(71,992

)

 

 

38,295

 

 

 

98,054

 

 

 

24,137

 

 

 

(71,992

)

 

 

38,295

 

 

 

98,054

 

Net income (loss)

$

48,539

 

 

$

(127,700

)

 

$

17,941

 

 

$

111,961

 

Net income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

0.19

 

 

$

(0.52

)

 

$

0.07

 

 

$

0.45

 

Diluted

$

0.19

 

 

$

(0.52

)

 

$

0.07

 

 

$

0.45

 

Dividends paid per common share

$

0.02

 

 

$

0.02

 

 

$

0.06

 

 

$

0.06

 

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

 

246,451

 

 

 

245,244

 

 

 

246,016

 

 

 

245,027

 

Diluted

 

247,166

 

 

 

245,244

 

 

 

246,879

 

 

 

245,280

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

4


RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)

 

Three Months Ended September 30,

 

 

Nine Months Ended September 30,

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

48,539

 

 

$

(127,700

)

 

$

17,941

 

 

$

111,961

 

Other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Postretirement benefits:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prior service cost

 

91

 

 

 

 

 

 

276

 

 

 

 

Income tax benefit

 

(22

)

 

 

 

 

 

(68

)

 

 

 

Total comprehensive income (loss)

$

48,608

 

 

$

(127,700

)

 

$

18,149

 

 

$

111,961

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

5


RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

 

 

Nine Months Ended September 30,

 

 

2018

 

 

2017

 

 

 

 

 

 

 

 

 

Operating activities:

 

 

 

 

 

 

 

Net income

$

17,941

 

 

$

111,961

 

Adjustments to reconcile net income to net cash provided from operating activities:

 

 

 

 

 

 

 

Deferred income tax expense

 

38,295

 

 

 

98,054

 

Depletion, depreciation and amortization and impairment

 

510,172

 

 

 

525,753

 

Exploration dry hole costs

 

4

 

 

 

9,166

 

Abandonment and impairment of unproved properties

 

73,244

 

 

 

52,181

 

Derivative fair value loss (income)

 

151,890

 

 

 

(188,326

)

Cash settlements on derivative financial instruments

 

(40,272

)

 

 

16,062

 

Allowance for bad debts

 

(1,250

)

 

 

1,050

 

Amortization of deferred financing costs and other

 

4,163

 

 

 

4,184

 

Deferred and stock-based compensation

 

41,252

 

 

 

3,937

 

Gain on the sale of assets

 

(149

)

 

 

(23,509

)

Changes in working capital:

 

 

 

 

 

 

 

Accounts receivable

 

(49,713

)

 

 

(39,694

)

Inventory and other

 

(822

)

 

 

(1,504

)

Accounts payable

 

(6,529

)

 

 

44,715

 

Accrued liabilities and other

 

36,721

 

 

 

(13,498

)

Net cash provided from operating activities

 

774,947

 

 

 

600,532

 

Investing activities:

 

 

 

 

 

 

 

Additions to natural gas and oil properties

 

(781,554

)

 

 

(771,067

)

Additions to field service assets

 

(1,230

)

 

 

(4,687

)

Acreage purchases

 

(50,461

)

 

 

(46,967

)

Proceeds from disposal of assets

 

24,339

 

 

 

27,583

 

Purchases of marketable securities held by the deferred compensation plan

 

(34,953

)

 

 

(25,410

)

Proceeds from the sales of marketable securities held by the deferred compensation plan

 

37,311

 

 

 

28,755

 

Net cash used in investing activities

 

(806,548

)

 

 

(791,793

)

Financing activities:

 

 

 

 

 

 

 

Borrowings on credit facilities

 

1,602,000

 

 

 

1,486,000

 

Repayments on credit facilities

 

(1,547,000

)

 

 

(1,282,000

)

Repayment of senior notes

 

 

 

 

(500

)

Dividends paid

 

(14,950

)

 

 

(14,876

)

Debt issuance costs

 

(8,257

)

 

 

(247

)

Taxes paid for shares withheld

 

(3,143

)

 

 

(6,971

)

Change in cash overdrafts

 

(5,653

)

 

 

5,588

 

Proceeds from the sales of common stock held by the deferred compensation plan

 

8,513

 

 

 

4,482

 

Net cash provided from financing activities

 

31,510

 

 

 

191,476

 

(Decrease) increase in cash and cash equivalents

 

(91

)

 

 

215

 

Cash and cash equivalents at beginning of period

 

448

 

 

 

314

 

Cash and cash equivalents at end of period

$

357

 

 

$

529

 

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

6


RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

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

(2) BASIS OF PRESENTATION

These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for fair presentation of the results for the periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for complete financial statements.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Range Resources Corporation 2017 Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”) on February 28, 2018. The results of operations for the third quarter and the nine months ended September 30, 2018 are not necessarily indicative of the results to be expected for the full year.

Inventory. As of September 30, 2018, we had $9.1 million of material and supplies inventory compared to $12.1 million at December 31, 2017. Material and supplies inventory consists of primarily tubular goods and equipment used in our operations and is stated at lower of specific cost of each inventory item or net realized value, on a first-in, first-out basis. At September 30, 2018, we also had commodity inventory of $1.5 million compared to $508,000 at December 31, 2017. Commodity inventory as of September 30, 2018 consists of NGLs held in storage or as line fill in pipelines.

Unproved Properties. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. In certain circumstances, our future plans to develop acreage may accelerate our impairment.

(3) NEW ACCOUNTING STANDARDS

Not Yet Adopted

Lease Accounting Standard

In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use asset and lease liability for all leases with terms of more than twelve months. Classification of leases as either a finance or operating lease will determine the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements. This standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. We are evaluating each of our lease arrangements and are currently enhancing our systems to track and calculate additional information necessary for adoption of this standard. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position and financial disclosures, in addition to developing any control changes necessary. While we have yet to finalize the impact this standards update will have on our consolidated financial statements, we believe the adoption will likely increase our recorded assets and liabilities related to our leases.

We will adopt this new standards update in first quarter 2019 using a modified retrospective approach and will recognize a right of use asset and lease liability on the adoption date. We plan to apply practical expedients provided in the standards update that allow, among other things, not to reassess contracts that commenced prior to the adoption. We also anticipate to elect a policy not to recognize right of use assets and lease liabilities related to short-term leases.

Financial Instruments – Credit Losses

In June 2016, an accounting standards update was issued that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standards update requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standards update is effective for us in first quarter 2020 and will be adopted on a modified retrospective basis through a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting

7


standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position and financial disclosures.

Fair Value Measurement

In August 2018, an accounting standards update was issued which provides additional disclosure requirements for fair value measurements. This new standards update eliminates the requirement to disclose transfers between Level 1 and Level 2 of the fair value hierarchy and provides for additional disclosures for Level 3 fair value measurements. This new standards update is effective for us in first quarter 2020 and will be adopted on a prospective or retrospective basis depending on the changes that apply. We are evaluating the provisions of this standards update and assessing the impact, if any, it may have on our financial disclosures.

Recently Adopted

Pension Accounting Standard

In March 2017, an accounting standards update was issued which provides additional guidance on the presentation of net benefit cost in the statement of operations. Employers will present the service cost component of net periodic benefit cost in the same consolidated results of operations line item as other employee compensation costs arising from services rendered during the period. This new standards update was effective for annual reporting periods in first quarter 2018 and must be applied retrospectively. We adopted this standards update in first quarter 2018. The adoption did not impact our consolidated results of operations, financial position, cash flows or disclosures. We had no service cost recorded prior to 2018 due to the implementation of our postretirement benefit plan at the end of 2017. In 2018, our service cost is recorded in general and administrative expense.

Modification of Share – Based Awards

In May 2017, an accounting standards update was issued which clarifies what constitutes a modification of a share-based award. This standards update is intended to provide clarity and reduce both diversity in practice and cost and complexity to a change to the terms or conditions of a share-based payment award. We adopted this standards update in first quarter 2018. The adoption of this standard did not have a material impact on our consolidated financial position or results of operations.

Revenue Recognition Standard

In May 2014, an accounting standards update was issued that superseded the existing revenue recognition requirements. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. This standard was effective for us in first quarter 2018 and we adopted the new standards using the modified retrospective method to all open contracts as of January 1, 2018. Our implementation of this standard did not result in a cumulative-effect adjustment on date of adoption; however, our financial statement presentation related to revenue received from certain gas processing contracts changed. Based on previous accounting guidance, certain of our gas processing contracts were reported in revenue at the net price (net of processing costs) we receive. Upon adoption of this accounting standards update, these contracts are now reported as a gross price received at a delivery point and separate transportation, marketing and processing expense. The impact of adoption of the new revenue recognition standard on our current period results is as follows (in thousands):

 

Three Months Ended September 30, 2018

As Reported

 

 

Previous Revenue

Recognition Method

 

 

 

 

 

 

 

 

 

 

$

 

 

 

$ Per mcfe

 

 

 

$

 

 

 

$ Per

mcfe

 

 

 

Increase

 

 

 

$ Per

mcfe

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGLs and oil sales

$

736,431

 

 

$

3.53

 

 

$

688,684

 

 

$

3.30

 

 

$

47,747

 

 

$

0.23

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation, gathering, processing and compression

$

304,562

 

 

$

1.46

 

 

$

256,815

 

 

$

1.23

 

 

$

47,747

 

 

$

0.23

 

Net income

$

48,539

 

 

 

 

 

 

$

48,539

 

 

 

 

 

 

$

 

 

 

 

 

 

 

Nine Months Ended September 30, 2018

As Reported

 

 

Previous Revenue

Recognition Method

 

 

 

 

 

 

 

 

 

$

 

 

 

$ Per

mcfe

 

 

 

$

 

 

 

$ Per

mcfe

 

 

 

Increase

 

 

 

$ Per

mcfe

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas, NGLs and oil sales

$

2,094,450

 

 

$

3.45

 

 

$

1,966,731

 

 

$

3.24

 

 

$

127,719

 

 

$

0.21

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Transportation, gathering, processing and compression

$

819,100

 

 

$

1.35

 

 

$

691,381

 

 

$

1.14

 

 

$

127,719

 

 

$

0.21

Net income

$

17,941

 

 

 

 

 

 

$

17,941

 

 

 

 

 

 

$

 

 

 

 

8


Changes to natural gas, NGLs and oil sales and transportation, gathering, processing, and compression expenses is due to the conclusion that we represent the role of principal in a certain gas processing and marketing agreement with a midstream entity in accordance with the new accounting standard. This represents a change from our previous conclusion utilizing the principal versus agent indication that we acted as the agent in that agreement. As a result, we were required to modify our presentation to present revenue on a gross basis for amounts expected to be received from third-party customers through the marketing process, with expenses incurred prior to control of the products transferring to the midstream entity at the tailgate of the plant presented as transportation, gathering, processing and compression expense.

Goodwill Standard

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

Inventory Standard

In July 2015, an accounting standards update was issued that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in first quarter 2017 and was applied prospectively. Adoption of this standard did not have an impact on our consolidated results of operations, financial position or cash flows.

Classification in the Statement of Cash Flows

In August 2016, an accounting standards update was issued that clarifies how entities classify certain cash receipts and cash payments on the statement of cash flows. The guidance is effective for us in first quarter 2018 and should be applied retrospectively with early adoption permitted. We adopted this new standard in fourth quarter 2017 on a retrospective basis. Adoption of this standard did not have an impact on our consolidated cash flow statement presentation.

Definition of a Business

In January 2017, an accounting standards update was issued which clarifies the definition of a business. This new standard is effective for us in first quarter 2018 with early adoption permitted. We adopted this new standard in fourth quarter 2017. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

(4) DISPOSITIONS

We recognized a pretax net loss on the sale of assets of $30,000 in third quarter 2018 compared to a pretax net gain of $102,000 in the same period of the prior year and a pretax net gain on the sale of assets of $149,000 in first nine months 2018 compared to a pretax net gain on the sale of assets of $23.5 million in first nine months 2017.

2018 Fourth Quarter Disposition Announcement

On October 15, 2018, we announced the simultaneous signing and closing of an agreement to sell a proportionately reduced 1% royalty on all our current Washington County, Pennsylvania leases for $300.0 million in proceeds. The transaction is subject to customary terms and conditions.

2018 Dispositions

Northern Oklahoma. In third quarter 2018, we sold properties in Northern Oklahoma for proceeds of $23.3 million and we recorded a net loss of $39,000 related to this sale, after closing adjustments.

Other. In third quarter 2018, we sold miscellaneous inventory and other assets for proceeds of $673,000, resulting in a pretax gain of $9,000. In first six months 2018, we sold miscellaneous inventory and other assets for proceeds of $366,000 resulting in a pretax gain of $179,000.

2017 Dispositions

Western Oklahoma. In first nine months 2017, we sold properties in Western Oklahoma for proceeds of $26.0 million and we recorded a gain of $22.1 million related to this sale, after closing adjustments and transaction fees.

Other. In third quarter 2017, we sold miscellaneous inventory and other assets for proceeds of $295,000, resulting in a pretax gain of $102,000. In first six months 2017, we sold miscellaneous unproved property, inventory and other assets for proceeds of $1.3 million resulting in a pretax gain of $1.3 million. 

9


(5) REVENUES FROM CONTRACTS WITH CUSTOMERS

Revenue Recognition

Natural gas, NGLs and oil sales revenues are generally recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. See a more detailed summary of our product types below.

Natural Gas and NGLs Sales

Under our gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction. For those contracts that we have concluded that we are the principal, the ultimate third party is our customer and we recognize revenue on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Alternatively, for those contracts that we have concluded that we are the agent, the midstream processing entity is our customer and we recognize revenue based on the net amount of the proceeds received from the midstream processing entity.

In certain natural gas processing agreements, we may elect to take our residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product on our own. Through the marketing process, we deliver product to the ultimate third party purchaser at a contractually agreed upon delivery point and receive a specified index price from the purchaser. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing and compression expense.

Oil Sales

Our oil sales contracts are generally structured in one of the following ways:

 

We sell oil production at the wellhead and collect an agreed upon index price, net of transportation incurred by the purchaser (that is, a netback arrangement). In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

 

 

We deliver oil to the purchaser at a contractually agreed upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third party costs are recorded as transportation, gathering, processing and compression expense.

 

Brokered Natural Gas, Marketing and Other

We realize brokered margins as a result of buying natural gas or NGLs utilizing separate purchase transactions, generally with separate counterparties and subsequently selling that natural gas or NGLs under our existing contracts to fulfill our contract commitments or utilizing existing infrastructure contracts to economically utilize available capacity. In these arrangements, we take control of the natural gas purchased prior to delivery of that gas under our existing gas contracts with a separate counterparty. Revenues and expenses related to brokering natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Our net brokered margin was a loss of $6.7 million in third quarter 2018 and a loss of $7.0 million in first nine months 2018.

10


Disaggregation of Revenue

We have identified three material revenue streams in our business: natural gas sales, NGLs sales and oil sales. Brokered revenue attributable to each product sales type is included here because the volume of product that we purchase is subsequently sold to separate counterparties in accordance with existing sales contracts under which we also sell our production. Revenue attributable to each of our identified revenue streams is disaggregated below (in thousands):

 

 

 

Three Months Ended

September 30, 2018

 

 

 

Nine Months Ended

September 30, 2018

 

Natural gas sales (a)

$

500,194

 

 

$

1,449,148

 

NGLs sales (b)

 

278,410

 

 

 

706,673

 

Oil sales

 

67,212

 

 

 

206,077

 

Total

$

845,816

 

 

$

2,361,898

 

(a)

Natural gas sales revenue reported above for the third quarter includes $105.8 million of brokered revenues and $3.7 million of marketing revenue. The nine months includes $255.1 million of brokered revenues and $11.4 million of marketing revenue.

(b)

NGLs sales revenue reported above for the third quarter includes ($153,000) of brokered revenues and for nine months includes $880,000 of brokered revenues.

Principal versus Agent

We engage in various types of transactions in which midstream entities process our wet gas and, in some scenarios, subsequently market the resulting NGLs and residue gas to third-party customers on our behalf. These types of transactions require judgment to determine whether we are the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient allowed in the new revenue accounting standard that exempts us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have also utilized the practical expedient that states that we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Currently, our product sales that have a contractual term greater than one year have no long-term fixed consideration.

Contract Balances

Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $354.4 million at September 30, 2018 and $305.7 million at December 31, 2017.

Prior−Period Performance Obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas and NGLs sales may be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. We have internal controls in place for our estimation process and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three months and the nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

11


(6) INCOME TAXES

Income tax expense (benefit) was as follows (in thousands):

 

 

Three Months Ended

September 30,

 

 

 

Nine Months Ended

September 30,

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

 

2017

 

Income tax expense (benefit)

$

24,137

 

 

$

(71,992

)

 

$

38,295

 

 

$

98,054

 

Effective tax rate

 

33.2

%

 

 

36.1

%

 

 

68.1

%

 

 

46.7

%

 

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For third quarter and first nine months ended 2018 and 2017, our overall effective tax rate was different than the federal statutory rate due primarily to state income taxes (including adjustments to state income tax valuation allowances), equity compensation and other tax items which are detailed below (in thousands).

 

 

Three Months Ended

September 30,

 

 

 

Nine Months Ended

September 30,

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

 

2017

 

Total income (loss) before income taxes

$

72,676

 

 

$

(199,692

)

 

$

56,236

 

 

$

210,015

 

U.S. federal statutory rate

 

21

%

 

 

35

%

 

 

21

%

 

 

35

%

Total tax expense (benefit) at statutory rate

 

15,262

 

 

 

(69,892

)

 

 

11,810

 

 

 

73,505

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

State and local income taxes, net of federal benefit

 

2,691

 

 

 

(6,537

)

 

 

3,439

 

 

 

6,591

 

Non-deductible executive compensation

 

48

 

 

 

296

 

 

 

601

 

 

 

436

 

Equity compensation

 

6

 

 

 

56

 

 

 

2,146

 

 

 

4,808

 

Change in valuation allowances:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal net operating loss carryforwards & other

 

 

 

 

69

 

 

 

 

 

 

3,487

 

State net operating loss carryforwards & other

 

5,558

 

 

 

4,286

 

 

 

19,194

 

 

 

10,498

 

Rabbi trust and other

 

100

 

 

 

(508

)

 

 

1,499

 

 

 

(1,561

)

Permanent differences and other

 

472

 

 

 

238

 

 

 

(394

)

 

 

290

 

Total expense (benefit) for income taxes

$

24,137

 

 

$

(71,992

)

 

$

38,295

 

 

$

98,054

 

Effective tax rate

 

33.2

%

 

 

36.1

%

 

 

68.1

%

 

 

46.7

%

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. The law significantly reformed the Internal Revenue Code of 1986, as amended. The reduction in the corporate tax rate required a one-time revaluation of certain tax related assets and liabilities to reflect their value at the lower corporate tax rate of 21%. Due to the complexities involved in the accounting for the enactment of the new law, the SEC Staff Accounting Bulletin (“SAB”) 118 allowed a provisional estimate for the year ended December 31, 2017, which we made. As of September 30, 2018, we have not made any material adjustments to our provisional estimate at year-end 2017. We have made a reasonable estimate of the effect on our deferred tax balances. We will continue to analyze the impact of the new law and additional impacts will be recorded as they are identified during the measurement period provided for in SAB 118.

(7) INCOME (LOSS) PER COMMON SHARE

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

12


 

 

 

Three Months Ended

September 30,

 

 

 

Nine Months Ended

September 30,

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

 

2017

 

Net income (loss), as reported

$

48,539

 

 

$

(127,700

)

 

$

17,941

 

 

$

111,961

 

Participating earnings (a)

 

(590

)

 

 

(58

)

 

 

(224

)

 

 

(1,251

)

Basic net income (loss) attributed to common shareholders

 

47,949

 

 

 

(127,758

)

 

 

17,717

 

 

 

110,710

 

Reallocation of participating earnings (a)

 

2

 

 

 

 

 

 

 

 

 

1

 

Diluted net income (loss) attributed to common shareholders

$

47,951

 

 

$

(127,758

)

 

$

17,717

 

 

$

110,711

 

Net income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic

$

0.19

 

 

$

(0.52

)

 

$

0.07

 

 

$

0.45

 

Diluted

$

0.19

 

 

$

(0.52

)

 

$

0.07

 

 

$

0.45

 

(a)

Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

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

 

 

 

Three Months Ended

September 30,

 

 

 

Nine Months Ended

September 30,

 

 

2018

 

 

 

2017

 

 

 

2018

 

 

 

2017

 

Weighted average common shares outstanding – basic

 

246,451

 

 

 

245,244

 

 

 

246,016

 

 

 

245,027

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Director and employee PSUs and RSUs

 

715

 

 

 

 

 

 

863

 

 

 

253

 

Weighted average common shares outstanding – diluted

 

247,166

 

 

 

245,244

 

 

 

246,879

 

 

 

245,280

 

 

Weighted average common shares outstanding-basic for third quarter 2018 excludes 3.0 million shares of restricted stock held in our deferred compensation plan compared to 2.9 million shares in third quarter 2017 (although all awards are issued and outstanding upon grant). Weighted average common shares outstanding-basic for first nine months 2018 excludes 3.1 million shares of restricted stock compared to 2.8 million for first nine months 2017. For third quarter 2018, equity grants of 506,000 and for first nine months 2018, equity grants of 755,000 were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of our common shares and would be anti-dilutive to the computations. Due to our net loss in third quarter 2017, all outstanding equity grants have been excluded from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations. For first nine months 2017, equity grants of 1.1 million were outstanding but not included in the computation of diluted net income per share because the grant prices were greater than the average market price of our common shares and would be anti-dilutive to the computations. For purposes of calculating diluted weighted average common shares, non-vested restricted stock and performance based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period.

(8) Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)

 

 

September 30,
2018

 

 

December 31,
2017

 

 

 

(in thousands)

 

Natural gas and oil properties:

 

 

 

 

 

 

 

 

Properties subject to depletion

 

$

11,041,412

 

 

$

10,572,453

 

Unproved properties

 

 

2,601,784

 

 

 

2,644,000

 

Total

 

 

13,643,196

 

 

 

13,216,453

 

Accumulated depreciation, depletion and amortization

 

 

(3,929,060

)

 

 

(3,649,716

)

Net capitalized costs

 

$

9,714,136

 

 

$

9,566,737

 

(a)

Includes capitalized asset retirement costs and the associated accumulated amortization.

13


(9) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at September 30, 2018 is shown parenthetically). No interest was capitalized during the three months or nine months ended September 30, 2018 or the year ended December 31, 2017 (in thousands).

 

 

September 30,

2018

 

 

 

December 31,

2017

 

Bank debt (3.9%)

$

1,266,000

 

 

$

1,211,000

 

Senior notes:

 

 

 

 

 

 

 

4.875% senior notes due 2025

 

750,000

 

 

 

750,000

 

5.00% senior notes due 2023

 

741,531

 

 

 

741,531

 

5.00% senior notes due 2022

 

580,032

 

 

 

580,032

 

5.75% senior notes due 2021

 

475,952

 

 

 

475,952

 

5.875% senior notes due 2022

 

329,244

 

 

 

329,244

 

Other senior notes due 2022

 

590

 

 

 

590

 

Total senior notes

 

2,877,349

 

 

 

2,877,349

 

Senior subordinated notes:

 

 

 

 

 

 

 

5.00% senior subordinated notes due 2023

 

7,712

 

 

 

7,712

 

5.00% senior subordinated notes due 2022

 

19,054

 

 

 

19,054

 

5.75% senior subordinated notes due 2021

 

22,214

 

 

 

22,214

 

Total senior subordinated notes

 

48,980

 

 

 

48,980

 

Total debt

 

4,192,329

 

 

 

4,137,329

 

Unamortized premium

 

5,070

 

 

 

6,027

 

Unamortized debt issuance costs

 

(36,499

)

 

 

(34,550

)

Total debt net of debt issuance costs

$

4,160,900

 

 

$

4,108,806

 

Bank Debt

In April 2018, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets and has a maturity date of April 13, 2023. The bank credit facility provides for a maximum facility amount of $4.0 billion and an initial borrowing base of $3.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually by May and for event-driven unscheduled redeterminations. As of September 30, 2018, our bank group was composed of twenty-seven financial institutions with no one bank holding more than 5.8% of the total facility. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. On September 30, 2018, bank commitments total $2.0 billion and the outstanding balance under our bank credit facility was $1.3 billion, before deducting debt issuance costs. Additionally, we had $281.4 million of undrawn letters of credit leaving $452.6 million of committed borrowing capacity available under the facility. During a non-investment grade period, borrowings under the bank credit facility can either be at the alternate base rate (“ABR,” as defined in the bank credit facility agreement) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit facility agreement) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. The weighted average interest rate was 3.9% for third quarter 2018 compared to 2.8% for third quarter 2017. The weighted average interest rate was 3.7% for first nine months 2018 compared to 2.6% for first nine months 2017. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At September 30, 2018, the commitment fee was 0.35% and the interest rate margin was 1.75% on our LIBOR loans and 0.75% on our base rate loans.

14


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

Senior Notes

In September 2016, in conjunction with the acquisition of Memorial Resource Development Corp. (the “MRD Merger”), we issued $329.2 million senior unsecured 5.875% notes due 2022 (the “5.875% Notes”). In addition, we also completed a debt exchange offer to exchange senior subordinated notes for the following senior notes (in thousands):

 

 

Principal Amount

5.00% senior notes due 2023

$

741,531

5.00% senior notes due 2022

$

580,032

5.75% senior notes due 2021

$

475,952

 

 

 

All of the notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). On October 5, 2017, the 5.875% Notes, the 5.00% senior notes due 2023, the 5.00% senior notes due 2022 and the 5.75% senior notes due 2021 (collectively, the “Old Notes”) were exchanged for an equal principal amount of registered notes pursuant to an effective registration statement on Form S-4 filed with the SEC on August 9, 2017 under the Securities Act (the “New Notes”). The New Notes are identical to the Old Notes except the New Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any.

Senior Subordinated Notes

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

Guarantees

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

 

in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or

 

 

if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture.

 

15


Debt Covenants

Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the bank credit facility agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the bank credit facility agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at September 30, 2018.

(10) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well lives. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the nine months ended September 30, 2018 is as follows (in thousands):

 

 

 

  

Nine Months

Ended

September 30,

 2018

 

Beginning of period

  

$

276,855

 

Liabilities incurred

  

 

2,668

 

Disposition of wells

 

 

(8,665

)

Acquisitions

 

 

13,438

 

Liabilities settled

 

 

(3,803

)

Accretion expense

  

 

12,132

 

Change in estimate

  

 

4,347

 

End of period

  

 

296,972

 

Less current portion

  

 

(6,327

)

Long-term asset retirement obligations

  

$

290,645

 

Accretion expense is recognized as a component of depreciation, depletion and amortization expense in the accompanying consolidated statements of operations. Acquisitions include an increase in our interest in certain properties in Northwest Pennsylvania.

16


(11) DERIVATIVE ACTIVITIES

We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We utilize commodity swaps, collars, calls or swaptions to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. The fair value of our derivative contracts, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price, generally the New York Mercantile Exchange (“NYMEX”) for natural gas and crude oil or Mont Belvieu for NGLs, approximated a net loss of $104.8 million at September 30, 2018. These contracts expire monthly through December 2020. The following table sets forth our commodity-based derivative volumes by year as of September 30, 2018, excluding our basis and freight swaps which are discussed separately below:

 

Period

  

Contract Type

  

Volume Hedged

  

Weighted
Average Hedge Price

Natural Gas

  

 

  

 

  

 

 

 

2018

 

Swaps

 

1,193,370 Mmbtu/day

 

 

$ 2.96

 

2019

 

Swaps

 

594,589 Mmbtu/day

 

 

$ 2.82

 

2018

 

Calls

 

70,000 Mmbtu/day

 

 

$ 3.10 (1)

 

2018

 

Swaptions

 

160,000 Mmbtu/day

 

 

$ 3.07 (2)

 

2019

 

Swaptions

 

298,014 Mmbtu/day

 

 

$ 2.86 (2)

 

2020

 

Swaptions

 

10,000 Mmbtu/day

 

 

$ 2.75 (2)

 

 

 

 

 

 

 

 

 

 

Crude Oil

  

 

  

 

  

 

 

 

2018

 

Swaps

 

8,500 bbls/day

 

 

$ 53.20

 

2019

 

Swaps

 

7,000 bbls/day

 

 

$ 55.26

 

2020

 

Swaps

 

1,500 bbls/day

 

 

$ 60.63

 

2019

 

Collars

 

1,000 bbls/day

 

 

$ 63.00 − $ 73.03

 

 

 

 

 

 

 

 

 

 

NGLs (C3-Propane)

  

 

  

 

  

 

 

 

2018

 

Swaps

 

11,668 bbls/day

 

 

$ 0.74/gallon

 

January – June 2019

 

Swaps

 

7,500 bbls/day

 

 

$ 0.92/gallon

 

2018

 

Collars

 

5,000 bbls/day

 

 

$ 0.95 − $ 1.04

 

January – March 2019

 

Collars

 

6,500 bbls/day

 

 

$ 0.92 − $1.02

 

 

 

 

 

 

 

 

 

 

NGLs (NC4-Normal Butane)

  

 

  

 

  

 

 

 

2018

 

Swaps

 

5,500 bbls/day

 

 

$ 0.91/gallon

 

January – March 2019

 

Swaps

 

2,250 bbls/day

 

 

$ 1.22/gallon

 

 

 

 

 

 

 

 

 

 

NGLs (C5-Natural Gasoline)

  

 

  

 

  

 

 

 

2018

 

Swaps

 

5,402 bbls/day

 

 

$ 1.24/gallon

 

2019

 

Swaps

 

2,178 bbls/day

 

 

$ 1.42/gallon