Table of Contents

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 June 30, 2023
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: 001-08246
Image1.jpg
Southwestern Energy Company
(Exact name of registrant as specified in its charter)

Delaware

71-0205415

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

Form 10-Q

(Mark One)

[X]   Quarterly Report pursuant to Section 13 or 15(d) of the Securities

Exchange Act of 1934

For the quarterly period ended September 30, 2017

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:  001-08246

Picture 1

Southwestern Energy Company

(Exact name of registrant as specified in its charter)

Delaware

71-0205415

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

10000 Energy Drive
Spring, Texas 77389
(Address of principal executive offices)(Zip Code)

(832) 796-1000
(Registrant’s telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

10000 Energy Drive 

Spring, Texas

77389

(Address of principal executive offices)

(Zip Code)

(832) 796-1000

(Registrant’s telephone number, including area code)

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

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 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).  Yes ☒  No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Class

Outstanding as of October 24, 2017

Common Stock, Par Value $0.01

512,425,656

SWNNew York Stock Exchange

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 such 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 ☒
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
ClassOutstanding as of August 1, 2023
Common Stock, Par Value $0.011,101,463,052

Table of Contents

SOUTHWESTERN ENERGY COMPANY
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2023

SOUTHWESTERN

ENERGY COMPANY

INDEX TO FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2017

PART I – FINANCIAL INFORMATION

Page

3

4

3

4

4

5

5

6

6 
7

7

8

8

9

9
9
10
12
12
13
14
20
20
22
25
26
27
28
32
34

27

34

28

36

34

45

39

51

40

52

40

52

40

52

40

52

40

52

40

52

40

52

41

53


1
Table of Contents
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

All

This Quarterly Report on Form 10-Q (“Quarterly Report”) includes certain statements other than historical fact or present financial information,that may be deemed to be 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 or present financial information, that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for our future operations, are forward-looking statements.  Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance.  We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Quarterly Report on Form 10-Q identified by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “model,” “target” or similar words.

Statements may be forward-looking even in the absence of these particular words.

You should not place undue reliance on forward-looking statements.  They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. These forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

1

•the timing and extent of changes in market conditions and prices for natural gas, oil and natural gas liquids (“NGLs”) (including regional basis differentials) and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to the COVID-19 pandemic or other world health event;
•our ability to fund our planned capital investments;
•a change in our credit rating or adverse changes in interest rates;
•the extent to which lower commodity prices impact our ability to service or refinance our existing debt;
•the impact of volatility in the financial markets or other global economic factors, including any future development of the LNG market and the impact of COVID-19 or other diseases;
•geopolitical and business conditions in key regions of the world;
•difficulties in appropriately allocating capital and resources among our strategic opportunities;
•the timing and extent of our success in discovering, developing, producing, replacing and estimating reserves;
•our ability to maintain leases that may expire if production is not established or profitably maintained;
•our ability to meet natural gas delivery commitments and to utilize or monetize our firm transportation commitments;
•our ability to realize the expected benefits from acquisitions, including the Indigo and GEPH Mergers (each as defined below);
•our ability to transport our production to the most favorable markets or at all;
•availability and costs of personnel and of products and services provided by third parties;
•the impact of government regulation, including changes in law, the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation or regulation relating to hydraulic fracturing or other drilling and completion techniques, climate and over-the-counter derivatives;
•our ability to achieve, reach or otherwise meet initiatives, plans, or ambitions with respect to environmental, social and governance matters;
•the impact of the adverse outcome of any material litigation against us or judicial decisions that affect us or our industry generally;
•the effects of weather or power outages;
•increased competition;
•inflation rates;
•the financial impact of accounting regulations and critical accounting policies;
2

Table of Contents

·

the timing and extent of changes in market conditions and prices for natural gas, oil and Natural Gas Liquids (“NGLs”) (including regional basis differentials);

·

our ability to fund our planned capital investments;

·

a change in our credit rating;

•the comparative cost of alternative fuels;

·

the extent to which lower commodity prices impact our ability to service or refinance our existing debt;

•credit risk relating to the risk of loss as a result of non-performance by our counterparties, including as a result of financial or banking failures;

·

the impact of volatility in the financial markets or other global economic factors;

•our hedging strategy and results;

·

difficulties in appropriately allocating capital and resources among our strategic opportunities;

•our ability to obtain debt or equity financing on satisfactory terms; and

·

the timing and extent of our success in discovering, developing, producing and estimating reserves;

•any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”).

·

our ability to maintain leases that may expire if production is not established or profitably maintained;

·

our ability to realize the expected benefits from recent acquisitions;

·

our ability to transport our production to the most favorable markets or at all;

·

availability and costs of personnel and of products and services provided by third parties;

·

the impact of government regulation, including the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation relating to hydraulic fracturing, climate and over-the-counter derivatives;

·

the impact of the adverse outcome of any material litigation against us;

·

the effects of weather;

·

increased competition and regulation;

·

the financial impact of accounting regulations and critical accounting policies;

·

the comparative cost of alternative fuels;

·

credit risk relating to the risk of loss as a result of non-performance by our counterparties; and

·

any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”). 

Should one or more of the risks or uncertainties described above or elsewhere 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. We specifically disclaim all responsibility to update publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

Reserve engineering is a process of estimating underground accumulations of natural gas, oil and NGLs 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 would change the schedule of any further production and our development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, oil and NGLs that are ultimately recovered.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

2

3

Table of Contents

PART I – FINANCIAL INFORMATION

ITEM 1.FINANCIAL STATEMENTS.

STATEMENTS



 

 

 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



 

 

 

 

 

 

 

 

 

 

 



For the three months ended

 

For the nine months ended



September 30,

 

September 30,



2017

 

2016

 

2017

 

2016



(in millions, except share/per share amounts)

Operating Revenues:

 

 

 

 

 

 

 

 

 

 

 

Gas sales

$

394 

 

$

340 

 

$

1,368 

 

$

906 

Oil sales

 

27 

 

 

19 

 

 

73 

 

 

50 

NGL sales

 

55 

 

 

22 

 

 

132 

 

 

59 

Marketing

 

233 

 

 

237 

 

 

736 

 

 

631 

Gas gathering

 

28 

 

 

33 

 

 

85 

 

 

106 



 

737 

 

 

651 

 

 

2,394 

 

 

1,752 

Operating Costs and Expenses:

 

 

 

 

 

 

 

 

 

 

 

Marketing purchases

 

236 

 

 

234 

 

 

740 

 

 

627 

Operating expenses

 

170 

 

 

139 

 

 

481 

 

 

455 

General and administrative expenses

 

62 

 

 

61 

 

 

170 

 

 

171 

Restructuring charges

 

–  

 

 

2 

 

 

 –  

 

 

77 

Depreciation, depletion and amortization

 

135 

 

 

99 

 

 

364 

 

 

349 

Impairment of natural gas and oil properties

 

–  

 

 

817 

 

 

–  

 

 

2,321 

Taxes, other than income taxes

 

24 

 

 

24 

 

 

75 

 

 

69 



 

627 

 

 

1,376 

 

 

1,830 

 

 

4,069 

Operating Income (Loss)

 

110 

 

 

(725)

 

 

564 

 

 

(2,317)

Interest Expense:

 

 

 

 

 

 

 

 

 

 

 

Interest on debt

 

58 

 

 

59 

 

 

175 

 

 

168 

Other interest charges

 

2 

 

 

8 

 

 

7 

 

 

12 

Interest capitalized

 

(29)

 

 

(41)

 

 

(85)

 

 

(123)



 

31 

 

 

26 

 

 

97 

 

 

57 



 

 

 

 

 

 

 

 

 

 

 

Gain (Loss) on Derivatives

 

45 

 

 

71 

 

 

295 

 

 

(28)

Loss on Early Extinguishment of Debt

 

(59)

 

 

(51)

 

 

(70)

 

 

(51)

Other Income (Loss), Net

 

(2)

 

 

3 

 

 

6 

 

 

–  



 

 

 

 

 

 

 

 

 

 

 

Income (Loss) Before Income Taxes

 

63 

 

 

(728)

 

 

698 

 

 

(2,453)

Benefit for Income Taxes:

 

 

 

 

 

 

 

 

 

 

 

Current

 

(10)

 

 

–  

 

 

(10)

 

 

–  

Deferred

 

(4)

 

 

(20)

 

 

(4)

 

 

(20)



 

(14)

 

 

(20)

 

 

(14)

 

 

(20)

Net Income (Loss)

$

77 

 

$

(708)

 

$

712 

 

$

(2,433)

Mandatory convertible preferred stock dividend

 

27 

 

 

27 

 

 

81 

 

 

81 

Participating securities - mandatory convertible preferred stock

 

7 

 

 

–  

 

 

83 

 

 

–  

Net Income (Loss) Attributable to Common Stock

$

43 

 

$

(735)

 

$

548 

 

$

(2,514)



 

 

 

 

 

 

 

   

 

 

   

Earnings (Loss) Per Common Share:

 

 

 

 

 

 

 

 

 

 

 

Basic

$

0.09 

 

$

(1.52)

 

$

1.11 

 

$

(6.02)

Diluted

$

0.09 

 

$

(1.52)

 

$

1.10 

 

$

(6.02)



 

 

 

 

 

 

 

 

 

 

 

Weighted Average Common Shares Outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

499,812,926 

 

 

482,485,150 

 

 

496,458,435 

 

 

417,222,661 

Diluted

 

502,290,779 

 

 

482,485,150 

 

 

498,527,671 

 

 

417,222,661 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
For the three months ended June 30,For the six months ended
June 30,
(in millions, except share/per share amounts)2023202220232022
Operating Revenues:    
Gas sales$551 $2,485 $1,696 $4,177 
Oil sales92 138 187 249 
NGL sales153 310 354 582 
Marketing475 1,207 1,154 2,073 
Other(2)(2)(4)— 
1,269 4,138 3,387 7,081 
Operating Costs and Expenses:
Marketing purchases481 1,215 1,148 2,077 
Operating expenses418 402 836 783 
General and administrative expenses41 35 87 79 
Merger-related expenses— 2 — 27 
Depreciation, depletion and amortization328 288 641 563 
Taxes, other than income taxes58 65 126 122 
1,326 2,007 2,838 3,651 
Operating Income (Loss)(57)2,131 549 3,430 
Interest Expense:
Interest on debt60 73 123 141 
Other interest charges3 4 6 7 
Interest capitalized(29)(29)(59)(59)
34 48 70 89 
Gain (Loss) on Derivatives317 (879)1,718 (4,806)
Loss on Early Extinguishment of Debt— (4)(19)(6)
Other Loss, Net— (1)(1)(1)
Income (Loss) Before Income Taxes226 1,199 2,177 (1,472)
Provision (Benefit) for Income Taxes:
Current— 26 — 30 
Deferred(5)— 7 — 
(5)26 7 30 
Net Income (Loss)$231 $1,173 $2,170 $(1,502)
Earnings (Loss) Per Common Share:
Basic$0.21 $1.05 $1.97 $(1.35)
Diluted$0.21 $1.05 $1.97 $(1.35)
Weighted Average Common Shares Outstanding:
Basic1,101,167,082 1,116,175,758 1,100,725,127 1,115,456,855 
Diluted1,102,724,782 1,118,244,778 1,102,487,313 1,115,456,855 

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

3


4

Table of Contents



 

 

 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)



 

 

 

 

 

 

 

 

 

 

 



For the three months ended

 

For the nine months ended



September 30,

 

September 30,



2017

 

2016

 

2017

 

2016



(in millions)

Net income (loss)

$

77 

 

$

(708)

 

$

712 

 

$

(2,433)



 

 

 

 

 

 

 

 

 

 

 

Change in value of pension and other postretirement liabilities:

 

 

 

 

 

 

 

 

 

 

 

Amortization of prior service cost and net loss included in net periodic pension cost (1)

 

1 

 

 

1 

 

 

2 

 

 

1 

Net gain incurred in period  (1)

 

–  

 

 

1 

 

 

–  

 

 

5 



 

 

 

 

 

 

 

 

 

 

 

Change in currency translation adjustment

 

–  

 

 

–  

 

 

–  

 

 

3 



 

 

 

 

 

 

 

 

 

 

 

Comprehensive income (loss)

$

78 

 

$

(706)

 

$

714 

 

$

(2,424)

(1)

Net of tax for the three and nine months ended September  30, 2017 and 2016.

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Net income (loss)$231 $1,173 $2,170 $(1,502)
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net gain, including gain on settlements and curtailments included in net periodic pension cost (1)
— — 1 — 
Net actuarial loss incurred in period— — (2)— 
Net tax loss attributable to pension termination— — (14)— 
Total change in value of pension and postretirement liabilities— — (15)— 
Comprehensive income (loss)$231 $1,173 $2,155 $(1,502)
(1)Settlement adjustment was less than $1 million for the three and six months ended June 30, 2022.

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

4

5

Table of Contents



 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



 

 

 

 

 



September 30,

 

December 31,



2017

 

2016

ASSETS

(in millions)

Current assets:

 

 

 

 

 

Cash and cash equivalents

$

989 

 

$

1,423 

Accounts receivable, net

 

360 

 

 

363 

Derivative assets

 

91 

 

 

51 

Other current assets

 

36 

 

 

35 

Total current assets

 

1,476 

 

 

1,872 

Natural gas and oil properties, using the full cost method, including $1,919 million as of September 30, 2017 and $2,105 million as of December 31, 2016 excluded from amortization

 

23,575 

 

 

22,653 

Gathering systems

 

1,311 

 

 

1,299 

Other

 

568 

 

 

537 

Less: Accumulated depreciation, depletion and amortization

 

(19,904)

 

 

(19,534)

Total property and equipment, net

 

5,550 

 

 

4,955 

Other long-term assets

 

176 

 

 

249 

TOTAL ASSETS

$

7,202 

 

$

7,076 

LIABILITIES AND EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Short-term debt

$

40 

 

$

41 

Accounts payable

 

502 

 

 

473 

Taxes payable

 

55 

 

 

59 

Interest payable

 

21 

 

 

74 

Dividends payable

 

27 

 

 

27 

Derivative liabilities

 

97 

 

 

355 

Other current liabilities

 

42 

 

 

35 

Total current liabilities

 

784 

 

 

1,064 

Long-term debt

 

4,396 

 

 

4,612 

Pension and other postretirement liabilities

 

46 

 

 

49 

Other long-term liabilities

 

324 

 

 

434 

Total long-term liabilities

 

4,766 

 

 

5,095 

Commitments and contingencies (Note 10)

 

 

 

 

 

Equity:

 

 

 

 

 

Common stock, $0.01 par value;  1,250,000,000 shares authorized; issued 509,142,659 shares as of September 30, 2017 (does not include  3,346,703 shares issued on October 16, 2017 on account of a dividend declared on September 15, 2017) and 495,248,369 as of December 31, 2016

 

5 

 

 

5 

Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of September 30, 2017 and December 31, 2016, conversion in January 2018

 

–  

 

 

–  

Additional paid-in capital

 

4,698 

 

 

4,677 

Accumulated deficit

 

(3,013)

 

 

(3,725)

Accumulated other comprehensive loss

 

(37)

 

 

(39)

Common stock in treasury, 31,269  shares as of September 30, 2017 and December 31, 2016

 

(1)

 

 

(1)

Total equity

 

1,652 

 

 

917 

TOTAL LIABILITIES AND EQUITY

$

7,202 

 

$

7,076 



 

 

 

 

 

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

5

SOUTHWESTERNENERGY COMPANY AND SUBSIDIARIES

Table of Contents

CONSOLIDATED BALANCE SHEETS



 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



 

 

 

 

 



For the nine months ended



September 30,



2017

 

2016



(in millions)

Cash Flows From Operating Activities:

 

 

 

 

 

Net income (loss)

$

712 

 

$

(2,433)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

364 

 

 

349 

Impairment of natural gas and oil properties

 

–  

 

 

2,321 

Amortization of debt issuance costs

 

7 

 

 

12 

Deferred income taxes

 

(4)

 

 

(20)

(Gain) loss on derivatives, unsettled

 

(350)

 

 

48 

Stock-based compensation

 

19 

 

 

24 

Restructuring charges

 

–  

 

 

30 

Loss on early extinguishment of debt

 

70 

 

 

51 

Other

 

(2)

 

 

5 

Change in assets and liabilities:

 

 

 

 

 

Accounts receivable

 

3 

 

 

53 

Accounts payable

 

16 

 

 

(72)

Taxes payable

 

(3)

 

 

(17)

Interest payable

 

(28)

 

 

(14)

Other assets and liabilities

 

(15)

 

 

−  

Net cash provided by operating activities

 

789 

 

 

337 



 

 

 

 

 

Cash Flows From Investing Activities:

 

 

 

 

 

Capital investments

 

(943)

 

 

(391)

Proceeds from sale of property and equipment

 

17 

 

 

434 

Other

 

5 

 

 

 –  

Net cash provided by (used in) investing activities

 

(921)

 

 

43 



 

 

 

 

 

Cash Flows From Financing Activities:

 

 

 

 

 

Payments on short-term debt

 

(287)

 

 

(1)

Payments on long-term debt

 

(1,139)

 

 

(1,175)

Payments on revolving credit facility

 

–  

 

 

(3,268)

Borrowings under revolving credit facility

 

–  

 

 

3,152 

Payments on commercial paper

 

–  

 

 

(242)

Borrowings under commercial paper

 

–  

 

 

242 

Change in bank drafts outstanding

 

–  

 

 

(19)

Proceeds from issuance of long-term debt

 

1,150 

 

 

1,191 

Debt issuance costs

 

(18)

 

 

(17)

Proceeds from issuance of common stock

 

 –  

 

 

1,247 

Preferred stock dividend

 

(8)

 

 

(27)

Other

 

–  

 

 

(4)

Net cash provided by (used in) financing activities

 

(302)

 

 

1,079 



 

 

 

 

 

Increase (decrease) in cash and cash equivalents

 

(434)

 

 

1,459 

Cash and cash equivalents at beginning of year

 

1,423 

 

 

15 

Cash and cash equivalents at end of period

$

989 

 

$

1,474 
(Unaudited)
June 30, 2023December 31, 2022
ASSETS(in millions)
Current assets:  
Cash and cash equivalents$25 $50 
Accounts receivable, net598 1,401 
Derivative assets423 145 
Other current assets74 68 
Total current assets1,120 1,664 
Natural gas and oil properties, using the full cost method, including $2,163 million as of June 30, 2023 and $2,217 million as of December 31, 2022 excluded from amortization36,899 35,763 
Other545 527 
Less: Accumulated depreciation, depletion and amortization(26,039)(25,387)
Total property and equipment, net11,405 10,903 
Operating lease assets168 177 
Long-term derivative assets205 72 
Deferred tax assets— — 
Other long-term assets103 110 
Total long-term assets476 359 
TOTAL ASSETS$13,001 $12,926 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable$1,381 $1,835 
Taxes payable116 136 
Interest payable77 86 
Derivative liabilities270 1,317 
Current operating lease liabilities44 42 
Other current liabilities22 65 
Total current liabilities1,910 3,481 
Long-term debt4,036 4,392 
Long-term operating lease liabilities121 133 
Long-term derivative liabilities205 378 
Other long-term liabilities240 218 
Total long-term liabilities4,602 5,121 
Commitments and contingencies (Note 11)
Equity:
Common stock, $0.01 par value; 2,500,000,000 shares authorized; issued 1,163,077,745 shares as of June 30, 2023 and 1,161,545,588 shares as of December 31, 202212 12 
Additional paid-in capital7,182 7,172 
Accumulated deficit(369)(2,539)
Accumulated other comprehensive income (loss)(9)6 
Common stock in treasury, 61,614,693 shares as of June 30, 2023 and December 31, 2022(327)(327)
Total equity6,489 4,324 
TOTAL LIABILITIES AND EQUITY$13,001 $12,926 


The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

6

Table of Contents



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Common Stock

 

Preferred Stock

 

Additional

 

 

 

 

Accumulated Other

 

Common

 

 

 



Shares

 

 

 

 

Shares

 

Paid-In

 

Accumulated

 

Comprehensive

 

Stock in

 

 

 



Issued

 

Amount

 

Issued

 

Capital

 

Deficit (1)

 

Income (Loss)

 

Treasury

 

Total



(in millions, except share amounts)

Balance at December 31, 2016

495,248,369 

 

$

5 

 

1,725,000 

 

$

4,677 

 

$

(3,725)

 

$

(39)

 

$

(1)

 

$

917 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

–  

 

 

–  

 

–  

 

 

–  

 

 

712 

 

 

–  

 

 

–  

 

 

712 

Other comprehensive income

–  

 

 

–  

 

–  

 

 

–  

 

 

–  

 

 

2 

 

 

–  

 

 

2 

Total comprehensive income

–  

 

 

–  

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

714 

Stock-based compensation

–  

 

 

–  

 

–  

 

 

29 

 

 

–  

 

 

–  

 

 

–  

 

 

29 

Preferred stock dividend (2)

9,445,013 

 

 

–  

 

–  

 

 

(8)

 

 

–  

 

 

–  

 

 

–  

 

 

(8)

Issuance of restricted stock

5,036,122 

 

 

–  

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Cancellation of restricted stock

(609,130)

 

 

–  

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Performance units vested

121,208 

 

 

–  

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Tax withholding – stock compensation

(98,995)

 

 

–  

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Issuance of stock awards

72 

 

 

–  

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Balance at September 30, 2017

509,142,659 

 

$

5 

 

1,725,000 

 

$

4,698 

 

$

(3,013)

 

$

(37)

 

$

(1)

 

$

1,652 

(1)

Includes a net cumulative-effect adjustment of  $59 million related to the recognition of previously unrecognized windfall tax benefits resulting from the adoption of ASU 2016-09 as of the beginning of 2017.  This adjustment increased net deferred tax assets and the related income tax valuation allowance by the same amount.

SOUTHWESTERNENERGY COMPANY AND SUBSIDIARIES

(2)

Does not include  3,346,703 shares issued on October 16, 2017 and distributed to holders of the Company's mandatory convertible preferred stock.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)
For the six months ended June 30,
(in millions)20232022
Cash Flows From Operating Activities:  
Net income (loss)$2,170 $(1,502)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization641 563 
Amortization of debt issuance costs4 6 
Deferred income taxes7 — 
(Gain) loss on derivatives, unsettled(1,631)2,510 
Stock-based compensation5 3 
Loss on early extinguishment of debt19 6 
Other2 2 
Change in assets and liabilities:
Accounts receivable803 (621)
Accounts payable(363)433 
Taxes payable(20)4 
Interest payable(5)7 
Inventories(25)(5)
Other assets and liabilities(45)(7)
Net cash provided by operating activities1,562 1,399 
Cash Flows From Investing Activities:
Capital investments(1,286)(1,050)
Proceeds from sale of property and equipment123 1 
Net cash used in investing activities(1,163)(1,049)
Cash Flows From Financing Activities:
Payments on current portion of long-term debt— (204)
Payments on long-term debt(437)(71)
Payments on revolving credit facility(1,946)(5,564)
Borrowings under revolving credit facility2,006 5,510 
Change in bank drafts outstanding(43)29 
Proceeds from exercise of common stock options— 7 
Purchase of treasury stock— (20)
Debt issuance/amendment costs— (11)
Cash paid for tax withholding(4)(4)
Net cash used in financing activities(424)(328)
Increase (decrease) in cash and cash equivalents(25)22 
Cash and cash equivalents at beginning of year50 28 
Cash and cash equivalents at end of period$25 $50 

The accompanying notes are an integral part of these

unaudited condensed consolidated financial statements.

7

Table of Contents

SOUTHWESTERN ENERGYENERGY COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
Common StockAdditional
Paid-In
Capital		Accumulated
Deficit		Accumulated Other
Comprehensive
Income (Loss)		Common Stock in TreasuryTotal
Shares
Issued		AmountSharesAmount
(in millions, except share amounts)
Balance at December 31, 20221,161,545,588 $12 $7,172 $(2,539)$6 61,614,693 $(327)$4,324 
Comprehensive income:
Net income— — — 1,939 — — — 1,939 
Other comprehensive loss— — — — (15)— — (15)
Total comprehensive income— — — — — — — 1,924 
Stock-based compensation— — 2 — — — — 2 
Restricted units vested1,999,039 — 8 — — — — 8 
Tax withholding – stock compensation(662,163)— (4)— — — — (4)
Balance at March 31, 20231,162,882,464 $12 $7,178 $(600)$(9)61,614,693 $(327)$6,254 
Comprehensive income:
Net income— — — 231 — — — 231 
Other comprehensive income— — — — — — — — 
Total comprehensive income— — — — — — — 231 
Stock-based compensation— — 4 — — — — 4 
Issuance of restricted stock188,382 — — — — — — — 
Restricted units vested9,968 — — — — — — — 
Tax withholding – stock compensation(3,069)— — — — — — — 
Balance at June 30, 20231,163,077,745 $12 $7,182 $(369)$(9)61,614,693 $(327)$6,489 
Common StockAdditional
Paid-In
Capital		Accumulated
Deficit		Accumulated Other
Comprehensive
Income (Loss)		Common Stock in TreasuryTotal
Shares
Issued		AmountSharesAmount
(in millions, except share amounts)
Balance at December 31, 20211,158,672,666 $12 $7,150 $(4,388)$(25)44,353,224 $(202)$2,547 
Comprehensive loss:
Net loss— — — (2,675)— — — (2,675)
Other comprehensive income— — — — — — — — 
Total comprehensive loss— — — — — — — (2,675)
Stock-based compensation— — 1 — — — — 1 
Performance units vested2,499,860 — 12 — — — — 12 
Tax withholding – stock compensation(721,070)— (4)— — — — (4)
Balance at March 31, 20221,160,451,456 $12 $7,159 $(7,063)$(25)44,353,224 $(202)$(119)
Comprehensive income:
Net income— — —1,173 — — — 1,173 
Other comprehensive income— — — — — — — — 
Total comprehensive income— — — — — — — 1,173 
Stock-based compensation— — 2 — — — — 2 
Exercise of stock options893,312 — 7 — — — — 7 
Issuance of restricted stock115,608 — — — — — — — 
Restricted stock units vested21,981 — — — — — — — 
Treasury stock— — — — — 2,815,541 (20)(20)
Issuance of common stock79 — — — — — — — 
Tax withholding – stock compensation(7,014)— — — — — — — 
Balance at June 30, 20221,161,475,422 $12 $7,168 $(5,890)$(25)47,168,765 $(222)$1,043 

The accompanying notes are an integral part of these consolidated financial statements.
8
Table of Contents
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)BASIS OF PRESENTATION

PRESENTATION

Nature of Operations
Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGLNGLs development, exploration development and production (“E&P”). The Company is also focused on creating and capturing additional value through its natural gas gathering and marketing businessesbusiness (“Midstream Services”Marketing”). Southwestern conducts most of its businessesbusiness through subsidiaries and operates principally in two segments: E&P and Midstream Services.

Marketing.

E&P. Southwestern’s primary business is the development and production of natural gas as well as associated NGLs and oil, with ongoing operations focused on unconventional natural gas and oil reservoirs located in Pennsylvania, West Virginia, Ohio and Louisiana. The Company’s operations in Pennsylvania, West Virginia and Ohio, herein referred to as “Appalachia,” are primarily focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. The Company’s operations in Louisiana, herein referred to as “Haynesville,” are primarily focused on the Haynesville and Bossier natural gas reservoirs (“Haynesville and Bossier Shales”). The Company also operates drilling rigs and provides certain oilfield products and services that serve the Company’s E&P operations through vertical integration.
Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in its E&P operations.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report.
Principles of Consolidation
The Company believes the disclosures made are adequate to make the information presented not misleading.

The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 20162022 (“20162022 Annual Report”).

The Company’s significant accounting policies, which have been reviewed and approved by the Audit Committee of the Company’s Boardboard of Directors,directors (the “Board”), are summarized in Note 1 in the Notes to the Consolidated Financial Statements included in the Company’s 20162022 Annual Report.

(2) ACQUISITIONS
GEP Haynesville, LLC Merger
On November 3, 2021, Southwestern entered into an Agreement and Plan of Merger with Mustang Acquisition Company, LLC (“Mustang”), GEP Haynesville, LLC (“GEPH”) and GEPH Unitholder Rep, LLC (the “GEPH Merger Agreement”). Pursuant to the terms of the GEPH Merger Agreement, GEPH merged with and into Mustang, a subsidiary of Southwestern, and became a wholly-owned subsidiary of Southwestern (the “GEPH Merger”). The GEPH Merger closed on December 31, 2021 and expanded the Company’s operations in the Haynesville.
Indigo Natural Resources Merger
On June 1, 2021, Southwestern entered into an Agreement and Plan of Merger with Ikon Acquisition Company, LLC (“Ikon”), Indigo Natural Resources LLC (“Indigo”) and Ibis Unitholder Representative LLC (the “Indigo Merger Agreement”). Pursuant to the terms of the Indigo Merger Agreement, Indigo merged with and into Ikon, a subsidiary of Southwestern, and became a wholly-owned subsidiary of Southwestern (the “Indigo Merger”). On August 27, 2021, Southwestern’s stockholders voted to approve the Indigo Merger and the transaction closed on September 1, 2021. The Indigo Merger established Southwestern’s natural gas operations in the Haynesville and Bossier Shales in Louisiana.
9
Table of Contents
Merger-Related Expenses
The Company did not incur merger-related expenses during the three and six months ended June 30, 2023. The following table summarizes the merger-related expenses incurred during the three and six months ended June 30, 2022:
For the three months ended June 30, 2022For the six months ended June 30, 2022
(in millions)Indigo MergerGEPH MergerTotalIndigo MergerGEPH MergerTotal
Transition services$— $— $— $— $18 $18 
Professional fees (bank, legal, consulting)— — — — 1 1 
Contract buyouts, terminations and transfers1 — 1 1 2 3 
Due diligence and environmental— 1 1 1 1 2 
Employee-related— — — — 1 1 
Other— — — — 2 2 
Total merger-related expenses$1 $1 $2 $2 $25 $27 

(3)REVENUERECOGNITION
Revenues from Contracts with Customers
Natural gas and liquids.  Natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to a market index with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions in the geographic areas in which the Company operates. Under the Company’s sales contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. There is no significant financing component to the Company’s revenues as payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.
The Company records revenue from its natural gas and liquids production in the amount of its net revenue interest in sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes.
Marketing.  The Company, through its marketing affiliate, generally markets natural gas, oil and NGLs for its affiliated E&P companies as well as other joint owners who choose to market with the Company. In addition, the Company markets some products purchased from third parties. Marketing revenues for natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to market indices with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions. Under the Company’s marketing contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. Customers are invoiced and revenues are recorded each month as natural gas, oil and NGLs are delivered, and payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date.  As a result, the Company recognizes revenue in the amount for which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.
10
Table of Contents
Disaggregation of Revenues
The Company presents a disaggregation of E&P revenues by product on the consolidated statements of operations net of intersegment revenues. The following table reconciles operating revenues as presented on the consolidated statements of operations to the operating revenues by segment:
(in millions)E&PMarketingIntersegment
Revenues		Total
Three months ended June 30, 2023
Gas sales$535 $— $16 $551 
Oil sales91 — 1 92 
NGL sales153 — — 153 
Marketing— 1,231 (756)475 
Other (1)
(2)— — (2)
Total$777 $1,231 $(739)$1,269 
(in millions)
Three months ended June 30, 2022
Gas sales$2,485 $— $— $2,485 
Oil sales136 — 2 138 
NGL sales310 — — 310 
Marketing— 4,023 (2,816)1,207 
Other (1)
(2)— — (2)
Total$2,929 $4,023 $(2,814)$4,138 
(in millions)E&PMarketingIntersegment
Revenues		Total
Six months ended June 30, 2023
Gas sales$1,671 $— $25 $1,696 
Oil sales185 — 2 187 
NGL sales354 — — 354 
Marketing— 3,272 (2,118)1,154 
Other (1)
(4)— — (4)
Total$2,206 $3,272 $(2,091)$3,387 
(in millions)
Six months ended June 30, 2022
Gas sales$4,175 $— $2 $4,177 
Oil sales246 — 3 249 
NGL sales582 — — 582 
Marketing— 6,778 (4,705)2,073 
Total$5,003 $6,778 $(4,700)$7,081 
(1)For the three and sixmonths ended June 30, 2023 and the three months ended June 30, 2022, other E&P revenues consists primarily of losses on purchaser imbalances associated with natural gas and certain NGLs.
Associated E&P revenues are also disaggregated for analysis on a geographic basis by the core areas in which the Company operates, which are primarily Appalachia and Haynesville.
For the three months
ended June 30,		For the six months
ended June 30,
(in millions)2023202220232022
Appalachia$468 $1,776 $1,391 $3,097 
Haynesville309 1,153 815 1,906 
Total$777 $2,929 $2,206 $5,003 
11
Table of Contents
Receivables from Contracts with Customers
The following table reconciles the Company’s receivables from contracts with customers to consolidated accounts receivable as presented on the consolidated balance sheet:
(in millions)June 30, 2023December 31, 2022
Receivables from contracts with customers$467 $1,313 
Other accounts receivable131 88 
Total accounts receivable$598 $1,401 
Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for both the six months ended June 30, 2023 and year ended December 31, 2022. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.
(4)CASHAND CASH EQUIVALENTS

The following table presents a summary of cash and cash equivalents as of SeptemberJune 30, 20172023 and December 31, 2016:

2022:

 

 

 

 

 

 

 

 

 

 

September 30,

 

December 31,

2017

 

2016

(in millions)

(in millions)(in millions)June 30, 2023December 31, 2022

Cash

$

259 

 

$

254 Cash$— $49 

Marketable securities (1)

 

680 

 

 

1,169 
Marketable securities (1)
25 1 

Other cash equivalents (2)

 

50 

 

 

−  

Total cash and cash equivalents

$

989 

 

$

1,423 
TotalTotal$25 $50 

(1)

Consists of government stable value money market funds.

(2)

Consists of time deposits.

(3) REDUCTION IN WORKFORCE

In January 2016, the Company announced a 40% workforce reduction as a result(1)Typically consists of lower anticipated drilling activity.  This reduction was substantially completed in the first quarter of 2016.  In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016.

The following table presents a summary of the restructuring charges for the three and nine months ended September 30, 2016:



 

 

 

 

 

 



 

For the three

months ended

 

For the nine

months ended



 

September 30, 2016

 

September 30, 2016



 

(in millions)

Severance (including payroll taxes) (1)

 

$

 –  

 

$

44 

Stock-based compensation (2)

 

 

 –  

 

 

24 

Pension and other postretirement benefits (3)

 

 

2 

 

 

5 

Other benefits

 

 

−  

 

 

3 

Outplacement services, other

 

 

−  

 

 

1 

Total restructuring charges (4)

 

$

2 

 

$

77 

8

Table of Contents

government stable value money market funds.

(1)

Includes $1 million related to executive management restructuring for the nine months ended September 30, 2016.

(2)

Includes $3 million related to executive management restructuring for the nine months ended September 30, 2016.

(3)

Includes non-cash charges related to the curtailment and settlement of the pension and other postretirement benefit plans.  See Note 11 for additional details regarding the Company’s pension and other postretirement benefit plans.

(4)

Total restructuring charges were $2 million for the Company’s E&P segment for the three months ended September 30, 2016.  For the nine months ended September 30, 2016, restructuring charges were $74 million and $3 million for the Company’s E&P and Midstream Services segments, respectively.

Severance payments and other separation costs related to restructuring were substantially completed by the end of 2016.

(4)(5) NATURAL GASGAS AND OIL PROPERTIES

The Company utilizes the full cost method of accounting for costs related to the development, exploration development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities, are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves.

The Company had no hedge positions that were designated for hedge accounting as of June 30, 2023. Prices used to calculate the ceiling value of reserves were as follows:

June 30, 2023June 30, 2022
Natural gas (per MMBtu)
$4.76 $5.13 
Oil (per Bbl)
$82.82 $85.78 
NGLs (per Bbl)
$25.45 $36.96 
Using the average quoted price from the first day of each month from the previous 12 monthsprices above, adjusted for Henry Hub natural gas of  $3.00 per MMBtu, West Texas Intermediate oil of $46.27 per barrel and NGLs of $12.47  per barrel, adjusted formarket differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at SeptemberJune 30, 2017. The Company had no hedge positions that were designated for hedge accounting as of September 30, 2017.2023. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future non-cash ceiling test impairments.

Usingimpairments to the Company’s natural gas and oil properties. Should market prices continue below the average quoted price from the first day of each month from the previous 12 months, for Henry Hub natural gasas was the case in the second quarter of $2.28 per MMBtu, West Texas Intermediate oil of $38.17 per barrel and NGLs of $6.46 per barrel, adjusted for differentials,2023, such impairments may occur in upcoming quarters.

In June 2023, the net book value of the Company’s United StatesCompany sold non-core natural gas and oil properties resulted in Appalachia for approximately $123 million in cash, subject to customary post-closing adjustments. The cash proceeds were used to pay down the Company’s revolving credit facility and were recorded as a non-cash ceiling test impairmentreduction to its natural gas and oil properties.
12
Table of $817 million for the three months ended September 30, 2016.  The Company had no hedge positions that were designated for hedge accounting as of September 30, 2016.  In the first and second quarters of 2016, the Company recognized non-cash ceiling test impairments of $1,034 million and $470 million, respectively. 

(5) EARNContentsINGS

(6) EARNINGSPER SHARE

Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during the reportable period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock, performancerestricted stock units and the assumed conversion of mandatory convertible preferred stock.performance units. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise or contingent issuance of certain securities.

In July 2016,June 2022, the Company completed an underwritten public offering of 98,900,000repurchased approximately 2.8 million shares of its outstanding common stock with an offering price to the public of $13.00 per share.  Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses.  The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018.  The remaining proceeds of the offering have been used for general corporate purposes.

9

Table of Contents

The depositary shares issued in January 2015 entitles the holderpursuant to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights.  Unless converted earlierpreviously announced share repurchase program at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weightedan average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date.  The total potential shares of common stock resulting from the conversion will range from 63,829,830 to 74,999,895 shares.

The mandatory convertible preferred stock has the non-forfeitable right to participate on an as-converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security.  Accordingly, it is included in the computation of basic and diluted earnings$7.10 per share pursuant to the two-class method.  In the calculationfor a total cost of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

On September 15, 2017, the Company declared its quarterly dividend, payable to holders of the mandatory convertible preferred stock, and announced that it would pay the quarterly dividend in stock, in lieu of cash, to the extent permitted by the certificate of designations for the Series B preferred stock. The Company issued 3,346,703 shares of common stock on October 16, 2017 in partial payment for the dividend, the remaining $7.9 million paid in cash.

approximately $20 million.

The following table presents the computation of earnings per share for the three and ninesix months ended SeptemberJune 30, 20172023 and 2016:

2022:

 

 

 

 

 

 

 

 

 

 

 

For the three months ended

 

For the nine months ended

For the three months ended June 30,For the six months ended June 30,

September 30,

 

September 30,

2017

 

2016

 

2017

 

2016

(in millions, except share/per share amounts)

(in millions, except share/per share amounts)(in millions, except share/per share amounts)2023202220232022

Net income (loss)

$

77 

 

$

(708)

 

$

712 

 

$

(2,433)Net income (loss)$231 $1,173 $2,170 $(1,502)

Mandatory convertible preferred stock dividend

 

27 

 

 

27 

 

 

81 

 

 

81 

Participating securities - mandatory convertible preferred stock

 

7 

 

 

–  

 

 

83 

 

 

–  

Net income (loss) attributable to common stock

$

43 

 

$

(735)

 

$

548 

 

$

(2,514)

 

 

 

 

 

 

 

 

 

 

 

Number of common shares:

 

 

 

 

 

 

 

 

 

 

 

Number of common shares:

Weighted average outstanding

 

499,812,926 

 

 

482,485,150 

 

 

496,458,435 

 

 

417,222,661 Weighted average outstanding1,101,167,082 1,116,175,758 1,100,725,127 1,115,456,855 

Issued upon assumed exercise of outstanding stock options

 

–  

 

 

–  

 

 

−  

 

 

–  

Issued upon assumed exercise of outstanding stock options— — — — 

Effect of issuance of non-vested restricted common stock

 

1,202,585 

 

 

–  

 

 

883,512 

 

 

–  

Effect of issuance of non-vested restricted common stock834,120 755,235 812,008 — 
Effect of issuance of non-vested restricted unitsEffect of issuance of non-vested restricted units723,580 1,226,632 950,178 — 

Effect of issuance of non-vested performance units

 

1,275,268 

 

 

–  

 

 

1,185,724 

 

 

–  

Effect of issuance of non-vested performance units— 87,153 — — 

Effect of issuance of mandatory convertible preferred stock

 

–  

 

 

–  

 

 

–  

 

 

–  

Weighted average and potential dilutive outstanding

 

502,290,779 

 

 

482,485,150 

 

 

498,527,671 

 

 

417,222,661 Weighted average and potential dilutive outstanding1,102,724,782 1,118,244,778 1,102,487,313 1,115,456,855 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per common shareEarnings (loss) per common share

Basic

$

0.09 

 

$

(1.52)

 

$

1.11 

 

$

(6.02)Basic$0.21 $1.05 $1.97 $(1.35)

Diluted

$

0.09 

 

$

(1.52)

 

$

1.10 

 

$

(6.02)Diluted$0.21 $1.05 $1.97 $(1.35)

The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the three and ninesix months ended SeptemberJune 30, 20172023 and 2016,2022, as they would have had an antidilutive effect:



 

 

 

 

 

 

 



For the three months ended

 

For the nine months ended



September 30,

 

September 30,



2017

 

2016

 

2017

 

2016

Unvested stock options

180,932 

 

3,409,596 

 

60,973 

 

3,714,095 

Unvested share-based payment

5,703,086 

 

599,372 

 

5,356,166 

 

993,576 

Performance units

1,036,422 

 

935,330 

 

1,036,422 

 

762,171 

Mandatory convertible preferred stock

74,999,895 

 

74,999,895 

 

74,999,895 

 

74,999,895 

Total

81,920,335 

 

79,944,193 

 

81,453,456 

 

80,469,737 
For the three months ended June 30,For the six months ended June 30,
2023202220232022
Unexercised stock options820,138 2,502,614 843,100 2,724,319 
Unvested restricted common stock66,970 40,971 33,670 783,729 
Restricted units1,403,519 786,061 2,191,937 2,127,795 
Performance units752,512 — 540,478 1,223,158 
Total3,043,139 3,329,646 3,609,185 6,859,001 

10


13

Table of Contents

(6)

(7) DERIVATIVES ANDAND RISK MANAGEMENT

The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of SeptemberJune 30, 20172023 and December 31, 2016,June 30, 2022, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, putoptions (calls and call options,puts), index swaps and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:

Fixed price swaps

TheIf the Company sells a fixed price swap, the Company receives a fixed price for the contract, and pays a floating market price to the counterparty.

Purchased put options

The  If the Company purchases put options based on an indexa fixed price from the counterparty by payment of a cash premium.  If the index price is lower than the put’s strike price at the time of settlement,swap, the Company receives from the counterparty such difference between the index price and the purchased put strike price.  If thea floating market price settles abovefor the put’s strikecontract and pays a fixed price no payment is due from either party.

to the counterparty.

Two-way costless collars

Arrangements that contain a fixed floor price (purchased(“purchased put option)option”) and a fixed ceiling price (sold(“sold call option)option”) based on an index price which, in aggregate, have no net cost.  At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price.

Three-way costless collars

Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price which,that, in aggregate, have no net cost.  At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.

Basis swaps

Arrangements that guarantee a price differential for natural gas from a specified delivery point.  TheIf the Company sells a basis swap, the Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

  If the Company purchases a basis swap, the Company pays the counterparty if the price differential is greater than the stated terms of the contract and receives a payment from the counterparty if the price differential is less than the stated terms of the contract.

Sold call options

Options (Calls and Puts)The Company purchases and sells call options in exchange for premiums.  If the Company purchases a premium.  Ifcall option, the Company receives from the counterparty the excess (if any) of the market price exceedsover the strike price of the call option at the time of settlement, the Company pays the counterparty such excess on sold call options. Ifbut if the market price settlesis below the call’s strike price, no payment is due from either party.

  If the Company sells a call option, the Company pays the counterparty the excess (if any) of the market price over the strike price of the call option at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party. If the Company purchases a put option, the Company receives from the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party. If the Company sells a put option, the Company pays the counterparty the excess (if any) of the strike price over the market price of the put option at the time of settlement, but if the market price is above the put’s strike price, no payment is due from either party.

Index swaps

Natural gas index swaps are used to manage the Company’s exposure to volatility in daily cash market pricing. When the Company sells an index swap, the Company pays an amount equal to the average of the daily index price for a given month at a specified location and receives a first of month index price based on the same location.
14
Table of Contents
Interest rate swaps

Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.

11

Table of Contents

The Company utilizescontracts with counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company closelyactively monitors the credit ratings of these counterparties.  Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates of these counterparties where applicable.  However, there can be no assurance that a counterparty will be able to meet its obligations to the Company.

 The Company presents its derivatives position on a gross basis and does not net the asset and liability positions.

The following table providestables provide information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The table presentstables present the notional amount, in Bcf, the weighted average contract prices and the fair value by expected maturity dates as of SeptemberJune 30, 2017:



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

Weighted Average Price per MMBtu

 

 

 



Volume (Bcf)

 

Swaps

 

Sold Puts

 

Purchased Puts

 

Sold Calls

 

Basis Differential

 

Fair Value at September 30, 2017 (in millions)

Financial protection on production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swaps

73 

 

$

3.06 

 

$

–  

 

$

–  

 

$

–  

 

$

 –  

 

$

1 

Two-way costless-collars

31 

 

 

–  

 

 

–  

 

 

2.96 

 

 

3.38 

 

 

–  

 

 

1 

Three-way costless-collars

34 

 

 

–  

 

 

2.29 

 

 

2.97 

 

 

3.30 

 

 

–  

 

 

–  

Total

138 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

2 

2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed price swaps

178 

 

$

3.02 

 

$

–  

 

$

–  

 

$

–  

 

$

–  

 

$

(4)

Two-way costless-collars

23 

 

 

–  

 

 

–  

 

 

2.97 

 

 

3.56 

 

 

–  

 

 

(1)

Three-way costless-collars

272 

 

 

–  

 

 

2.40 

 

 

2.97 

 

 

3.37 

 

 

–  

 

 

7 

Total

473 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

2 

2019

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way costless-collars

108 

 

$

–  

 

$

2.50 

 

$

2.95 

 

$

3.32 

 

$

–  

 

$

(1)

Total

108 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(1)



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basis Swaps

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017

32 

 

$

–  

 

$

–  

 

$

–  

 

$

–  

 

$

(0.95)

 

$

12 

2018

25 

 

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

(0.63)

 

 

(16)

Total

57 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(4)



 

 

 

 

 

 

 

 



 

 

Weighted Average Price per MMBtu

 

 

 

 



Volume (Bcf)

 

Sold Calls

 

Fair Value at September 30, 2017 (in millions)

 

Call options

 

 

 

 

 

 

 

 

2017

21 

 

$

3.68 

 

$

–  

(1)

2018

63 

 

 

3.50 

 

 

(9)

 

2019

52 

 

 

3.50 

 

 

(8)

 

2020

32 

 

 

3.75 

 

 

(5)

 

Total

168 

 

 

 

 

$

(22)

 

2023:

(1)

Excludes $2 million in premiums paid related to certain call options recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statements of operations.

Financial Protection on Production
 Weighted Average Price per MMBtu 
Volume (Bcf)
SwapsSold PutsPurchased PutsSold CallsBasis Differential
Fair Value at
June 30, 2023
(in millions)
Natural Gas       
2023       
Fixed price swaps348 $3.25 $— $— $— $— $91 
Two-way costless collars78 — — 2.83 3.21 — 4 
Three-way costless collars95 — 2.08 2.50 2.91 — (28)
Total521 $67 
2024
Fixed price swaps528 $3.54 $— $— $— $— $12 
Two-way costless collars44 — — 3.07 3.53 — (10)
Three-way costless collars11 — 2.25 2.80 3.54 — (7)
Total583 $(5)
2025
Two-way costless collars73 $— $— $3.50 $5.40 $— $10 
Three-way costless collars106 — 2.50 3.75 5.69 — 15 
Total179 $25 
Basis Swaps
2023146 $— $— $— $— $(0.62)$68 
202446 — — — — (0.71)8 
20259 — — — — (0.64)3 
Total201 $79 

12

15

Table of Contents

The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) are summarized below as of September


Volume
(MBbls)
Weighted Average Strike Price per Bbl
Fair Value at
June 30, 2023
(in millions)
SwapsSold PutsPurchased PutsSold Calls
Oil
2023
Fixed price swaps1,466 $67.34 $— $— $— $(4)
Two-way costless collars294 — — 70.00 80.58 1 
Three-way costless collars582 — 34.36 46.05 55.96 (9)
Total2,342 $(12)
2024
Fixed price swaps1,571 $71.06 $— $— $— $3 
Two-way costless collars146 — — 70.00 78.25 — 
Total1,717 $3 
2025
Fixed price swaps41 $77.66 $— $— $— $— 
Ethane
2023
Fixed price swaps4,499 $11.01 $— $— $— $4 
2024
Fixed price swaps1,305 $10.81 $— $— $— $— 
Propane   
2023   
Fixed price swaps3,601 $32.19 $— $— $— $28 
2024
Fixed price swaps1,460 $33.29 $— $— $— $11 
Normal Butane
2023
Fixed price swaps396 $40.96 $— $— $— $5 
2024
Fixed price swaps329 $40.74 $— $— $— $3 
Natural Gasoline
2023
Fixed price swaps342 $63.74 $— $— $— $4 
2024
Fixed price swaps329 $64.37 $— $— $— $3 
Other Derivative Contracts
Volume
(Bcf)
Weighted Average Strike Price per MMBtu
Fair Value at
June 30, 2023
(in millions)
Call Options – Natural Gas (Net)
202325 $2.96 $(11)
202482 6.56 (15)
202573 7.00 (15)
202673 7.00 (20)
Total253 $(61)
At June 30, 2017 and December 31, 2016:



 

 

 

 

 

 

 

 



 

Derivative Assets



 

Balance Sheet Classification

 

Fair Value



 

 

 

September 30,  2017

 

December 31, 2016



 

 

(in millions)

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

Fixed price swaps

 

Derivative assets

 

$

12 

 

$

–  

Two-way costless collars

 

Derivative assets

 

 

7 

 

 

8 

Three-way costless collars

 

Derivative assets

 

 

50 

 

 

11 

Basis swaps

 

Derivative assets

 

 

19 

 

 

32 

Call options

 

Derivative assets

 

 

1 

 

 

–  

Fixed price swaps

 

Other long-term assets

 

 

1 

 

 

1 

Two-way costless collars

 

Other long-term assets

 

 

–  

 

 

2 

Three-way costless collars

 

Other long-term assets

 

 

56 

 

 

100 

Basis swaps

 

Other long-term assets

 

 

–  

 

 

1 

Total derivative assets

 

 

 

$

146 

(1)

$

155 



 

 



 

Derivative Liabilities



 

Balance Sheet Classification

 

Fair Value



 

 

 

September 30,  2017

 

December 31, 2016



 

 

 

(in millions)

Derivatives not designated as hedging instruments:

 

 

 

 

 

 

 

 

Fixed price swaps

 

Derivative liabilities

 

$

14 

 

$

175 

Two-way costless collars

 

Derivative liabilities

 

 

7 

 

 

49 

Three-way costless collars

 

Derivative liabilities

 

 

44 

 

 

70 

Basis swaps

 

Derivative liabilities

 

 

23 

 

 

13 

Call options

 

Derivative liabilities

 

 

8 

 

 

46 

Interest rate swaps

 

Derivative liabilities

 

 

1 

 

 

2 

Fixed price swaps

 

Other long-term liabilities

 

 

2 

 

 

3 

Two-way costless collars

 

Other long-term liabilities

 

 

–  

 

 

9 

Three-way costless collars

 

Other long-term liabilities

 

 

56 

 

 

122 

Basis swaps

 

Other long-term liabilities

 

 

–  

 

 

5 

Call options

 

Other long-term liabilities

 

 

15 

 

 

35 

Interest rate swaps

 

Other long-term liabilities

 

 

1 

 

 

1 

Total derivative liabilities

 

 

 

$

171 

 

$

530 

(1)

Excludes $2  million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.  As certain call options settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the unaudited condensed consolidated statements of operations.

At September 30, 2017,2023, the net fair value of the Company’s financial instruments was a $153 million asset, which included net reduction of the asset of $1 million related to natural gas was a  $23 million liability.  The netnon-performance risk. See Note 9 for additional details regarding the Company’s fair value measurements of the Company’s interest rate swaps was a  $2 million liability asits derivatives position.

16
Table of September 30, 2017.  The Company had ethane fixed price swaps with an immaterial fair value as of September 30, 2017.

Derivative Contracts Not Designated for Hedge Accounting

Contents

As of SeptemberJune 30, 2017,2023, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the unaudited condensed consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statementsstatement of operations reflects the gains and losses on both settled and unsettled derivatives.  The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period. Only the settled gains and losses are included in the Company’s realized commodity price calculations.

The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates.  The interest rate swaps have a notional amount of $170 million and expire in June 2020.  The Company did not designate the interest rate swaps for hedge accounting treatment.  Changes in the fair valuebalance sheet classification of the interest rate swapsassets and liabilities related to derivative financial instruments are included in gain (loss) on derivatives on the unaudited condensed consolidated statementssummarized below as of operations.

June 30, 2023 and December 31, 2022:

13

Derivative Assets    
Fair Value
(in millions)Balance Sheet ClassificationJune 30, 2023 December 31, 2022
Derivatives not designated as hedging instruments: 
Fixed price swaps – natural gasDerivative assets$207 $— 
Fixed price swaps – oilDerivative assets4 — 
Fixed price swaps – ethaneDerivative assets6 4 
Fixed price swaps – propaneDerivative assets37 9 
Fixed price swaps – normal butaneDerivative assets6 1 
Fixed price swaps – natural gasolineDerivative assets5 1 
Two-way costless collars – natural gasDerivative assets64 47 
Two-way costless collars – oilDerivative assets3 — 
Three-way costless collars – natural gasDerivative assets14 18 
Three-way costless collars – oilDerivative assets— 1 
Basis swaps – natural gasDerivative assets73 64 
Put options – natural gasDerivative assets5 — 
Fixed price swaps – natural gasOther long-term assets69 28 
Fixed price swaps – oilOther long-term assets2 1 
Fixed price swaps – ethaneOther long-term assets— 1 
Fixed price swaps – propaneOther long-term assets2 1 
Fixed price swaps – normal butaneOther long-term assets2 — 
Fixed price swaps – natural gasolineOther long-term assets2 — 
Two-way costless collars – natural gasOther long-term assets48 18 
Three-way costless collars – natural gasOther long-term assets71 3 
Basis swaps – natural gasOther long-term assets11 17 
Put options – natural gasOther long-term assets— 4 
Total derivative assets $631 $218 
17

Table of Contents

Derivative Liabilities   
Fair Value
(in millions)Balance Sheet ClassificationJune 30, 2023December 31, 2022
Derivatives not designated as hedging instruments: 
Fixed price swaps – natural gasDerivative liabilities$105 $581 
Fixed price swaps – oilDerivative liabilities7 20 
Fixed price swaps – ethaneDerivative liabilities2 1 
Fixed price swaps – natural gasolineDerivative liabilities— 1 
Two-way costless collars – natural gasDerivative liabilities64 235 
Two-way costless collars – oilDerivative liabilities2 — 
Three-way costless collars – natural gasDerivative liabilities49 311 
Three-way costless collars – oilDerivative liabilities9 31 
Basis swaps – natural gasDerivative liabilities5 69 
Call options – natural gasDerivative liabilities23 70 
Put options – natural gasDerivative liabilities5 — 
Fixed price swaps – natural gasLong-term derivative liabilities68 281 
Fixed price swaps – oilLong-term derivative liabilities— 4 
Two-way costless collars – natural gasLong-term derivative liabilities44 56 
Three-way costless collars – natural gasLong-term derivative liabilities56 20 
Basis swap – natural gasLong-term derivative liabilities— 1 
Call options – natural gasLong-term derivative liabilities38 18 
Total derivative liabilities $477 $1,699 
Net Derivative Position
June 30, 2023December 31, 2022
(in millions)
Net current derivative asset (liability)$153 $(1,174)
Net long-term derivative asset (liability)1 (307)
Non-performance risk adjustment(1)3 
Net total derivative asset (liability)$153 $(1,478)

18
Table of Contents
The following tables summarize the before-tax effect of fixed price swaps, purchased put options, two-way costless collars, three-way costless collars, basis swaps, call options and interest rate swaps not designated for hedge accountingthe Company’s derivative instruments on the unaudited condensed consolidated statements of operations for the three and ninesix months ended SeptemberJune 30, 20172023 and 2016:



 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

Gain (Loss) on Derivatives, Unsettled

Recognized in Earnings



 

Consolidated Statements of Operations

 

For the three months ended

 

For the nine months ended



 

Classification of Gain (Loss)

 

September 30,

 

September 30,

Derivative Instrument

 

on Derivatives, Unsettled

 

2017

 

2016

 

2017

 

2016



 

 

 

(in millions)

Fixed price swaps (1)

 

Gain (Loss) on Derivatives

 

$

(2)

 

$

23 

 

$

174 

 

$

(17)

Two-way costless collars

 

Gain (Loss) on Derivatives

 

 

3 

 

 

5 

 

 

48 

 

 

 –  

Three-way costless collars

 

Gain (Loss) on Derivatives

 

 

(1)

 

 

1 

 

 

87 

 

 

(1)

Basis swaps

 

Gain (Loss) on Derivatives

 

 

24 

 

 

31 

 

 

(19)

 

 

27 

Call options

 

Gain (Loss) on Derivatives

 

 

6 

 

 

21 

 

 

59 

 

 

(54)

Interest rate swaps

 

Gain (Loss) on Derivatives

 

 

1 

 

 

–  

 

 

1 

 

 

(3)

Total gain (loss) on unsettled derivatives

 

$

31 

 

$

81 

 

$

350 

 

$

(48)



 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

Gain (Loss) on Derivatives, Settled (2)



 

 

 

Recognized in Earnings



 

Consolidated Statements of Operations

 

For the three months ended

 

For the nine months ended



 

Classification of Gain (Loss)

 

September 30,

 

September 30,

Derivative Instrument

 

on Derivatives, Settled

 

2017

 

2016

 

2017

 

2016



 

 

 

(in millions)

Fixed price swaps (1)

 

Gain (Loss) on Derivatives

 

$

7 

 

$

(9)

 

$

(18)

 

$

7 

Purchased put options

 

Gain (Loss) on Derivatives

 

 

 –  

 

 

−  

 

 

–  

 

 

11 

Two-way costless collars

 

Gain (Loss) on Derivatives

 

 

 –  

 

 

−  

 

 

(3)

 

 

−  

Three-way costless collars

 

Gain (Loss) on Derivatives

 

 

1 

 

 

−  

 

 

(4)

 

 

−  

Basis swaps

 

Gain (Loss) on Derivatives

 

 

9 

 

 

−  

 

 

(21)

 

 

4 

Call options

 

Gain (Loss) on Derivatives

 

 

 –  

 

 

−  

 

 

(6)

 

 

−  

Interest rate swaps

 

Gain (Loss) on Derivatives

 

 

 –  

 

 

(1)

 

 

–  

 

 

(2)

Total gain (loss) on settled derivatives (3) (4)

 

$

17 

 

$

(10)

 

$

(52)

 

$

20 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total gain (loss) on derivatives (4)

 

$

48 

 

$

71 

 

$

298 

 

$

(28)
2022:

(1)

Includes the Company’s fixed price swaps on natural gas and ethane.  As of September 30, 2017, the amount of unsettled and settled fixed price swaps related to ethane was immaterial.


(2)

Unsettled Gain (Loss) on Derivatives Recognized in Earnings
Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, UnsettledFor the three months ended June 30,For the six months ended June 30,
Derivative Instrument2023202220232022
(in millions)
Fixed price swaps – natural gasGain (Loss) on Derivatives$(24)$339 937 (1,514)
Fixed price swaps – oilGain (Loss) on Derivatives10 19 22 (34)
Fixed price swaps – ethaneGain (Loss) on Derivatives(9)(6)— (27)
Fixed price swaps – propaneGain (Loss) on Derivatives28 56 29 7 
Fixed price swaps – normal butaneGain (Loss) on Derivatives6 20 7 — 
Fixed price swaps – natural gasolineGain (Loss) on Derivatives6 29 7 1 
Two-way costless collars – natural gasGain (Loss) on Derivatives(11)9 230 (333)
Two-way costless collars – oilGain (Loss) on Derivatives1 — 1 — 
Two-way costless collars – ethaneGain (Loss) on Derivatives— — — 1 
Three-way costless collars – natural gasGain (Loss) on Derivatives27 230 290 (494)
Three-way costless collars – oilGain (Loss) on Derivatives9 5 21 (28)
Three-way costless collars – propaneGain (Loss) on Derivatives— 3 — 1 
Basis swaps – natural gasGain (Loss) on Derivatives98 (28)68 8 
Call options – natural gasGain (Loss) on Derivatives(34)43 27 (106)
Put options – natural gasGain (Loss) on Derivatives— — (4)— 
Purchased fixed price swap – natural gas storageGain (Loss) on Derivatives— (1)— — 
Fixed price swap – natural gas storageGain (Loss) on Derivatives— — — 1 
Interest rate swapsGain (Loss) on Derivatives— — — (2)
Total gain (loss) on unsettled derivatives$107 $718 $1,635 $(2,519)
Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
Consolidated Statement of Operations Classification of Gain (Loss) on Derivatives, SettledFor the three months ended June 30,For the six months ended June 30,
Derivative Instrument2023202220232022
(in millions)
Fixed price swaps – natural gasGain (Loss) on Derivatives$160 $(870)$115 $(1,167)
Fixed price swaps – oilGain (Loss) on Derivatives(3)(41)(7)(74)
Fixed price swaps – ethaneGain (Loss) on Derivatives5 (19)6 (27)
Fixed price swaps – propaneGain (Loss) on Derivatives11 (34)12 (75)
Fixed price swaps – normal butaneGain (Loss) on Derivatives1 (12)1 (26)
Fixed price swaps – natural gasolineGain (Loss) on Derivatives1 (17)1 (36)
Two-way costless collars – natural gasGain (Loss) on Derivatives31 (130)31 (234)
Two-way costless collars – ethaneGain (Loss) on Derivatives— — — (1)
Three-way costless collars – natural gasGain (Loss) on Derivatives17 (396)(16)(517)
Three-way costless collars – oilGain (Loss) on Derivatives(6)(18)(13)(31)
Three-way costless collars – propaneGain (Loss) on Derivatives— (1)— (3)
Basis swaps – natural gasGain (Loss) on Derivatives(7)23 (36)24 
Index swaps – natural gasGain (Loss) on Derivatives— — — (1)
Call options – natural gasGain (Loss) on Derivatives— (87)(7)(126)
Purchased fixed price swaps – natural gasGain (Loss) on Derivatives— 1 — 1 
Fixed price swaps – natural gas storageGain (Loss) on Derivatives— — — (3)
Total gain (loss) on settled derivatives$210 $(1,601)$87 $(2,296)
Total gain (loss) on derivatives (2)
$317 $(879)$1,718 $(4,806)

(1)The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.

(3)

Excluding interest rate swaps and settled ethane fixed price swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas price. Settled ethane fixed price swaps are included, along with NGL sales revenues, in the calculation of the Company’s realized NGL price.

(4)

Excludes $3 million amortization of premiums paid related to certain call options for the three and nine months ended September 30, 2017, which is included in gain (loss) on derivatives on the condensed consolidated statements of operations.

Derivative Contracts Designated for Hedge Accounting

All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value, other than transactions for which normal purchase/normal sale is applied.  Certain criteria must be satisfied in order for derivative financial instruments to be designated for hedge accounting.  Unrealized gains and losses related to unsettled derivativeson positions that have been designated for hedge accounting treatment are recorded in either earnings or as a component of other comprehensive income until settled.  Insettled within the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in gas sales revenues.  As of September 30, 2017 and 2016, the Company had no positions designated for hedge accounting treatment.  

period.

14

19

Table of Contents

(7) RECLASSIFICATIONS

(2)Total gain (loss) on derivatives includes non-performance risk adjustments of $4 million in gains for the three months ended June 30, 2022 and $4 million in losses and $9 million in gains for the six months ended June 30, 2023 and June 30, 2022, respectively.
Total Gain (Loss) on Derivatives Recognized in Earnings
For the three months ended June 30,For the six months ended June 30,
2023202220232022
(in millions)
Total gain (loss) on unsettled derivatives$107 $718 $1,635 $(2,519)
Total gain (loss) on settled derivatives210 (1,601)87 (2,296)
Non-performance risk adjustment— 4 (4)9 
Total gain (loss) on derivatives$317 $(879)$1,718 $(4,806)
(8)RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects for the ninesix months ended SeptemberJune 30, 2017:

2023:



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 



 

Pension and Other Postretirement

 

 

Foreign Currency

 

 

Total



 

(in millions)

Beginning balance, December 31, 2016

 

$

(19)

 

 

$

(20)

 

 

$

(39)

Other comprehensive income before reclassifications

 

 

–  

 

 

 

–  

 

 

 

 –  

Amounts reclassified from other comprehensive income (1)

 

 

2 

 

 

 

–  

 

 

 

2 

Net current-period other comprehensive income

 

 

2 

 

 

 

–  

 

 

 

2 

Ending balance, September 30, 2017

 

$

(17)

 

 

$

(20)

 

 

$

(37)
(in millions)Pension and Other PostretirementForeign CurrencyTotal
Beginning balance December 31, 2022$20 $(14)$6 
Other comprehensive income before reclassifications1 — 1 
Amounts reclassified from other comprehensive income (1)
(16)— (16)
Net current-period other comprehensive loss(15)— (15)
Ending balance June 30, 2023$5 $(14)$(9)

(1)     See separate table below for details about these reclassifications.

1

Details about Accumulated Other Comprehensive Income

Affected Line Item in the Consolidated Statement of Operations

Amount Reclassified from Accumulated Other Comprehensive Income

For the nine months ended
September 30, 2017

(in millions)

Pension and other postretirement:

Amortization of prior service cost and net loss (1)

General and administrative expenses

$

2 

Provision for income taxes

–  

Net income (loss)

$

2 

Total reclassifications for the period

Net income (loss)

$

2 

(1)     See Note 11 for additional details regardingIncludes a $2 million actuarial loss and a $14 million net tax loss attributable to the Company’s pension plan termination.

(9) FAIR VALUE MEASUREMENTS
Assets and other postretirement benefit plans.

(8) FAIR VALUE MEASUREMENTS

liabilities measured at fair value on a recurring basis

The carrying amounts and estimated fair values of the Company’s financial instruments as of SeptemberJune 30, 20172023 and December 31, 20162022 were as follows:



 

 

 

 

 

 

 

 

 

 

 



September 30, 2017

 

December 31, 2016



Carrying

 

Fair

 

Carrying

 

Fair



Amount

 

Value

 

Amount

 

Value



(in millions)

Cash and cash equivalents

$

989 

 

$

989 

 

$

1,423 

 

$

1,423 

2015 term loan due December 2020

 

 –  

 

 

 –  

 

 

327 

 

 

327 

2016 term loan due December 2020 (1)

 

1,191 

 

 

1,191 

 

 

1,191 

 

 

1,191 

Senior notes

 

3,282 

 

 

3,317 

 

 

3,166 

 

 

3,182 

Derivative instruments, net (2)

 

(25)

 

 

(25)

 

 

(375)

 

 

(375)

(1)

The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.  As of September 30, 2017, the Company has redeemed $758 million principal amount outstanding of the 2020 senior notes.

(2)

Excludes $2 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

June 30, 2023 December 31, 2022
(in millions)Carrying
Amount		Fair
Value		Carrying
Amount		Fair
Value
Cash and cash equivalents$25 $25 $50 $50 
2022 revolving credit facility due April 2027310 310 250 250 
Senior notes (1)
3,743 3,507 4,164 3,847 
Derivative instruments, net153 153 (1,478)(1,478)

The carrying values of cash

(1)Excludes unamortized debt issuance costs and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities on the unaudited condensed consolidated balance sheets approximate fair value because of their short-term nature.  For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:

Debt:  The fair values of the Company’s senior notes were based on the market value of the Company’s publicly traded debt as determined based on the yield of the Company’s senior notes.

The carrying values of the borrowings under the Company’s term loan facilities and unsecured revolving credit facility approximate fair value because the interest rate is variable and reflective of market rates.  The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy. 

discounts.

15

Table of Contents

Derivative Instruments:  The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties.  The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.

The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

Level 1 valuations - Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

Level 2 valuations - Consist of quoted market information for the calculation of fair market value.

Level 3 valuations - Consist of internal estimates and have the lowest priority.

The carrying values of cash and cash equivalents, including marketable securities, accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:
Debt: The fair values of the Company’s senior notes are based on the market value of the Company’s publicly traded debt as determined based on the market prices of the Company’s senior notes. The fair values of the Company’s senior notes are considered to be a Level 1 measurement as these are actively traded in the market. The carrying value of the borrowings under the Company’s 2022 credit facility (as defined in Note 10 below), to the extent utilized, approximates fair value because the
20
Table of Contents
interest rates are variable and reflective of market rates. The Company considers the fair value of its 2022 credit facility to be a Level 1 measurement on the fair value hierarchy.
Derivative Instruments: The Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates for a similar duration of each outstanding position, volatility factors and non-performance risk. Non-performance risk considers the effect of the Company’s credit standing on the fair value of derivative liabilities and the effect of counterparty credit standing on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The Company’s net derivative position was a net asset as of June 30, 2023 and a net liability as of December 31, 2022. As of June 30, 2023 and December 31, 2022, the impact of the non-performance risk on the fair value of the Company’s net derivative position resulted in a reduction to the net asset of $1 million and a reduction to the net liability of $3 million, respectively.
The Company has classified its derivativesderivative instruments into these levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the NYMEXNew York Mercantile Exchange (“NYMEX”) futures index.index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizedutilizes discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of SeptemberJune 30, 20172023 and December 31, 2022 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company had no interest rate swaps as of June 30, 2023 or December 31, 2022.
The Company’s call options, purchasedand put options, two-way costless collars and three-way costless collars (Level 3)2) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX and OPIS futures index, interest rates, volatility and credit worthiness.  The Company’s basis swaps (Level 3) are estimated using third-party calculations based upon forward commodity price curves.

Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis.  An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.

The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves.
Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):



 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 



 

September 30, 2017



 

Fair Value Measurements Using:

 

 

 



 

Quoted Prices in Active Markets (Level 1)

 

Significant Other Observable Inputs (Level 2)

 

Significant Unobservable Inputs (Level 3)

 

Assets (Liabilities) at Fair Value

Fixed price swap assets 

 

$

–  

 

$

13 

 

$

–  

 

$

13 

Two-way costless collars assets

 

 

–  

 

 

–  

 

 

7 

 

 

7 

Three-way costless collars assets

 

 

–  

 

 

–  

 

 

106 

 

 

106 

Basis swap assets

 

 

–  

 

 

–  

 

 

19 

 

 

19 

Call option assets (1)

 

 

–  

 

 

–  

 

 

1 

 

 

1 

Fixed price swap liabilities

 

 

–  

 

 

(16)

 

 

–  

 

 

(16)

Two-way costless collars liabilities

 

 

–  

 

 

–  

 

 

(7)

 

 

(7)

Three-way costless collars liabilities

 

 

–  

 

 

–  

 

 

(100)

 

 

(100)

Basis swap liabilities

 

 

–  

 

 

–  

 

 

(23)

 

 

(23)

Call option liabilities

 

 

–  

 

 

–  

 

 

(23)

 

 

(23)

Interest rate swap liabilities

 

 

–  

 

 

(2)

 

 

–  

 

 

(2)

Total

 

$

–  

 

$

(5)

 

$

(20)

 

$

(25)
below:

(1)

Excludes $2 million in premiums paid related to certain call options currently recognized as a component of derivative assets within current assets on the unaudited condensed consolidated balance sheet.

June 30, 2023
Fair Value Measurements Using: 
(in millions)Quoted Prices in Active Markets (Level 1)Significant Other Observable Inputs (Level 2)Significant Unobservable Inputs (Level 3)Assets (Liabilities) at Fair Value
Assets  
Fixed price swaps$— $342 $— $342 
Two-way costless collars— 115 — 115 
Three-way costless collars— 85 — 85 
Basis swaps— 84 — 84 
Put options— 5 — 5 
Liabilities
Fixed price swaps— (182)— (182)
Two-way costless collars— (110)— (110)
Three-way costless collars— (114)— (114)
Basis swaps— (5)— (5)
Call options— (61)— (61)
Put options— (5)— (5)
Total (1)
$— $154 $— $154 

16

(1)Excludes a net reduction to the asset fair value of $1 million related to estimated non-performance risk.
21

Table of Contents



 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 



 

December 31, 2016



 

Fair Value Measurements Using:

 

 

 



 

Quoted Prices in Active Markets (Level 1)

 

Significant Other Observable Inputs (Level 2)

 

Significant Unobservable Inputs (Level 3)

 

Assets (Liabilities) at Fair Value

Fixed price swap assets

 

$

–  

 

$

1 

 

$

–  

 

$

1 

Two-way costless collars assets

 

 

–  

 

 

–  

 

 

10 

 

 

10 

Three-way costless collars assets

 

 

–  

 

 

–  

 

 

111 

 

 

111 

Basis swap assets

 

 

–  

 

 

–  

 

 

33 

 

 

33 

Fixed price swap liabilities

 

 

–  

 

 

(178)

 

 

–  

 

 

(178)

Two-way costless collars liabilities

 

 

–  

 

 

–  

 

 

(58)

 

 

(58)

Three-way costless collars liabilities

 

 

–  

 

 

–  

 

 

(192)

 

 

(192)

Basis swap liabilities

 

 

–  

 

 

–  

 

 

(18)

 

 

(18)

Call option liabilities

 

 

–  

 

 

–  

 

 

(81)

 

 

(81)

Interest rate swap liabilities

 

 

–  

 

 

(3)

 

 

–  

 

 

(3)

Total

 

$

–  

 

$

(180)

 

$

(195)

 

$

(375)

The table below presents reconciliations for

December 31, 2022
Fair Value Measurements Using: 
(in millions)Quoted Prices in Active Markets (Level 1)Significant Other Observable Inputs (Level 2)Significant Unobservable Inputs (Level 3)Assets (Liabilities) at Fair Value
Assets   
Fixed price swaps$— $46 $— $46 
Two-way costless collars— 65 — 65 
Three-way costless collars— 22 — 22 
Basis swaps— 81 — 81 
Purchase Put - Natural Gas— 4 — 4 
Liabilities
Fixed price swaps— (888)— (888)
Two-way costless collars— (291)— (291)
Three-way costless collars— (362)— (362)
Basis swaps— (70)— (70)
Call options— (88)— (88)
Total (1)
$— $(1,481)$— $(1,481)
(1)Excludes a net reduction to the change in netliability fair value of derivative assets and liabilities measured at$3 million related to estimated non-performance risk.
See Note 13 for a discussion of the fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and nine months ended September 30, 2017 and 2016.  The fair valuesmeasurement of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters.  Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would have used as of September 30, 2017 and 2016.

pension plan assets.



 

 

 

 

 

 

 

 

 

 

 

 



 

For the three months ended

 

For the nine months ended



 

September 30,

 

September 30,



 

2017

 

2016

 

2017

 

2016



 

(in millions)

 

(in millions)

Balance at beginning of period

 

$

(52)

 

$

(83)

 

$

(195)

 

$

3 

Total gains (losses):

 

 

   

 

 

 

 

 

 

 

 

 

Included in earnings

 

 

42 

 

 

58 

 

 

141 

 

 

(13)

Settlements

 

 

(10)

 

 

–  

 

 

34 

 

 

(15)

Transfers into/out of Level 3

 

 

–  

 

 

–  

 

 

–  

 

 

–  

Balance at end of period

 

$

(20)

 

$

(25)

 

$

(20)

 

$

(25)

Change in gains (losses) included in earnings relating to derivatives still held as of September 30

 

$

32 

 

$

58 

 

$

175 

 

$

(28)

(9) DEBT

(10) DEBT
The components of debt as of SeptemberJune 30, 20172023 and December 31, 20162022 consisted of the following:



 

 

 

 

 

 

 

 

 

 

 

 



 

September 30, 2017



 

Debt Instrument

 

Unamortized Issuance Expense

 

Unamortized Debt Discount

 

Total



 

 

(in millions)

Short-term debt:

 

 

 

 

 

 

 

 

 

 

 

 

7.35% Senior Notes due October 2017 (1)

 

$

15 

 

$

–  

 

$

–  

 

$

15 

7.125% Senior Notes due October 2017 (1)

 

 

25 

 

 

–  

 

 

–  

 

 

25 

Total short-term debt

 

$

40 

 

$

–  

 

$

–  

 

$

40 



 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

 

 

 

 

 

 

 

Variable rate (3.700% at September 30, 2017) 2016 term loan, due December 2020 (2)

 

 

1,191 

 

 

(8)

 

 

–  

 

 

1,183 

4.05% Senior Notes due January 2020 (3) (4)

 

 

92 

 

 

–  

 

 

–  

 

 

92 

4.10% Senior Notes due March 2022

 

 

1,000 

 

 

(4)

 

 

 –  

 

 

996 

4.95% Senior Notes due January 2025 (3)

 

 

1,000 

 

 

(6)

 

 

(2)

 

 

992 

7.50% Senior Notes due April 2026

 

 

650 

 

 

(10)

 

 

–  

 

 

640 

7.75% Senior Notes due October 2027

 

 

500 

 

 

(7)

 

 

–  

 

 

493 

Total long-term debt

 

$

4,433 

 

$

(35)

 

$

(2)

 

$

4,396 



 

 

 

 

 

 

 

 

 

 

 

 

Total debt

 

$

4,473 

 

$

(35)

 

$

(2)

 

$

4,436 
June 30, 2023
(in millions)Debt InstrumentUnamortized Issuance ExpenseUnamortized Debt Premium/DiscountTotal
Variable rate (6.90% at June 30, 2023)
2022 revolving credit facility, due April 2027
$310 $— (1)$— $310 
4.95% Senior Notes due January 2025 (2)
389 (1)— 388 
8.375% Senior Notes due September 2028304 (3)— 301 
5.375% Senior Notes due February 2029700 (5)20 715 
5.375% Senior Notes due March 20301,200 (14)— 1,186 
4.75% Senior Notes due February 20321,150 (14)— 1,136 
Total debt$4,053 $(37)$20 $4,036 
December 31, 2022
(in millions)Debt InstrumentUnamortized Issuance ExpenseUnamortized Debt Premium/DiscountTotal
Variable rate (6.15% at December 31, 2022) 2022 revolving credit facility, due April 2027$250 $— (1)$— $250 
4.95% Senior Notes due January 2025 (2)
389 (1)— 388 
7.75% Senior Notes due October 2027421 (3)— 418 
8.375% Senior Notes due September 2028304 (3)— 301 
5.375% Senior Notes due February 2029700 (5)22 717 
5.375% Senior Notes due March 20301,200 (16)— 1,184 
4.75% Senior Notes due February 20321,150 (16)— 1,134 
Total debt$4,414 $(44)$22 $4,392 

17

(1)At June 30, 2023 and December 31, 2022, unamortized issuance expense of $17 million and $19 million, respectively, associated with the 2022 credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheets.
22

Table of Contents



 

 

 

 

 

 

 

 

 

 

 

 



 

December 31, 2016



 

Debt Instrument

 

Unamortized Issuance Expense

 

Unamortized Debt Discount

 

Total



 

 

(in millions)

Short-term debt:

 

 

 

 

 

 

 

 

 

 

 

 

7.35% Senior Notes due October 2017 (1)

 

$

15 

 

$

–  

 

$

–  

 

$

15 

7.125% Senior Notes due October 2017 (1)

 

 

25 

 

 

–  

 

 

–  

 

 

25 

7.15% Senior Notes due June 2018 (4)

 

 

1 

 

 

–  

 

 

–  

 

 

1 

Total short-term debt

 

$

41 

 

$

–  

 

$

–  

 

$

41 



 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt:

 

 

 

 

 

 

 

 

 

 

 

 

Variable rate (3.220% at December 31, 2016) 2015 term loan, due December 2020 (4)

 

 

327 

 

 

(2)

 

 

–  

 

 

325 

Variable rate (3.220% at December 31, 2016) 2016 term loan, due December 2020 (2)

 

 

1,191 

 

 

(10)

 

 

–  

 

 

1,181 

3.30% Senior Notes due January 2018 (3) (4)

 

 

38 

 

 

–  

 

 

–  

 

 

38 

7.50% Senior Notes due February 2018 (4)

 

 

212 

 

 

–  

 

 

–  

 

 

212 

7.15% Senior Notes due June 2018 (4)

 

 

25 

 

 

–  

 

 

–  

 

 

25 

4.05% Senior Notes due January 2020 (3) (4)

 

 

850 

 

 

(5)

 

 

–  

 

 

845 

4.10% Senior Notes due March 2022

 

 

1,000 

 

 

(4)

 

 

(1)

 

 

995 

4.95% Senior Notes due January 2025 (3)

 

 

1,000 

 

 

(7)

 

 

(2)

 

 

991 

Total long-term debt

 

$

4,643 

 

$

(28)

 

$

(3)

 

$

4,612 



 

 

 

 

 

 

 

 

 

 

 

 

Total debt

 

$

4,684 

 

$

(28)

 

$

(3)

 

$

4,653 

(1)

Subsequent to September 30, 2017, the Company repaid $15 million and $25 million of its outstanding 7.35% and 7.125% Senior Notes, respectively, due October 2017.

(2)

The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced $765 million of its outstanding senior notes due in January 2020.  As of September 30, 2017, the Company has redeemed $758 million principal amount of the 2020 senior notes.

(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company’s bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company’s bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment date. The first coupon payment to the bondholders at the higher interest rate was paid in January 2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022.

(3)

In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing the interest rates by 175 basis points effective July 2016.  As a result of the downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes.

The following is a summary of scheduled debt maturities by year as of June 30, 2023:

(4)

In the first nine months of 2017, the Company repurchased $38 million principal amount of its outstanding 3.30% Senior Notes due January 2018, $212 million principal amount of its outstanding 7.50% Senior Notes due February 2018, $26 million principal amount of its outstanding 7.15% Senior Notes due June 2018,  $327 million principal amount of its outstanding 2015 Term Loan due December 2020 and $758 million principal amount of its outstanding 4.05% Senior Notes due January 2020.  The Company recognized a $70 million loss on the extinguishment of debt.

(in millions)
2023$— 
2024— 
2025389 
2026— 
2027310 
Thereafter3,354 
$4,053 

Credit Facilities
2022 Credit Facility
On April 8, 2022, the Company entered into an Amended and Restated Credit Agreement that replaces its previous credit facility with a group of banks, that as amended, has a maturity date of April 2027 (the “2022 credit facility”). As of June 30, 2023, the 2022 credit facility has an aggregate maximum revolving credit amount and borrowing base of $3.5 billion and elected five-year revolving commitments of $2.0 billion (the “Five-Year Tranche”). The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is secured by substantially all of the assets owned by the Company and its subsidiaries. On April 5, 2023, the Company’s borrowing base was reaffirmed at $3.5 billion and the Five-Year Tranche was reaffirmed at $2.0 billion and has a maturity date of April 8, 2027.
Effective August 4, 2022, the Company elected to temporarily increase commitments under the 2022 credit facility by $500 million (the “Short-Term Tranche”) as a temporary working capital liquidity resource. The Company had no borrowings under the Short-Term Tranche which expired on April 30, 2023 and was not renewed.
The Company may utilize the 2022 credit facility in the form of loans and letters of credit. Loans under the Five-Year Tranche of the 2022 credit facility are subject to varying rates of interest based on whether the loan is a Secured Overnight Financing Rate (“SOFR”) loan or an alternate base rate loan. Term SOFR loans bear interest at term SOFR plus an applicable rate ranging from 1.75% to 2.75% based on the Company’s utilization of the Five-Year Tranche of the 2022 credit facility, plus a 0.10% credit spread adjustment. Base rate loans bear interest at a base rate per year equal to the greatest of: (i) the prime rate; (ii) the federal funds effective rate plus 0.50%; and (iii) the adjusted term SOFR rate for a one-month interest period plus 1.00%, plus an applicable margin ranging from 0.75% to 1.75%, depending on the percentage of the commitments utilized. Commitment fees on unused commitment amounts under the Five-Year Tranche of the 2022 credit facility range between 0.375% to 0.50%, depending on the percentage of the commitments utilized.
The 2022 credit facility contains customary representations and warranties and covenants including, among others, the following:
•A prohibition against incurring debt, subject to permitted exceptions;
•A restriction on creating liens on assets, subject to permitted exceptions;
•Restrictions on mergers and asset dispositions;
•Restrictions on use of proceeds, investments, declaring dividends, repurchasing junior debt, transactions with affiliates, or change of principal business; and
•Maintenance of the following financial covenants, commencing with the fiscal quarter ended March 31, 2022:
1.Minimum current ratio of not less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused commitments under the credit agreement, but excluding non-cash
23
Table of Contents
derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt).
2.Maximum total net leverage ratio of not greater than, with respect to the prior four fiscal quarters ending on or after March 31, 2022, 4.00 to 1.00.  Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters.  EBITDAX, as defined in the credit agreement governing the Company’s 2022 credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs. 
The 2022 credit facility contains customary events of default that include, among other things, the failure to comply with the financial covenants described above, non-payment of principal, interest or fees, violation of covenants, inaccuracy of representations and warranties, bankruptcy and insolvency events, material judgments and cross-defaults to material indebtedness. If an event of default occurs and is continuing, all amounts outstanding under the 2022 credit facility may become immediately due and payable. As of June 30, 2023, the Company was in compliance with all of the covenants of the credit agreement in all material respects.
Currently, each United States domestic subsidiary of the Company for which the Company owns 100% of its equity guarantees the 2022 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that becomes a guarantor of the 2022 credit facility also must become a guarantor of each of the Company’s senior notes.
Certain features of the facility depend on whether Southwestern has obtained any of the following ratings:
•An unsecured long-term debt credit rating (an “Index Debt Rating”) of BBB- or higher with S&P;
•An Index Debt Rating of Baa3 or higher with Moody’s; or
•An Index Debt Rating of BBB- or higher with Fitch (each of the foregoing an “Investment Grade Rating”).
Upon receiving one Investment Grade Rating from either S&P or Moody’s and delivering a certification to the administrative agent (the period beginning at such time, an “Interim Investment Grade Period”), amongst other changes, the following occurs:
•The Guarantors may be released from their guarantees;
•The collateral under the facility will be released;
•The facility will no longer be subject to a borrowing base; and
•Certain title and collateral-related covenants will no longer be applicable.
During the Interim Investment Grade Period, the Company will be required to maintain compliance with the existing financial covenants as well as a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to the Company’s total indebtedness as of such date of not less than 1.50 to 1.00 (“PV-9 Coverage Ratio”). In addition, during an Interim Investment Grade Period or Investment Grade Period (as defined below), term SOFR loans will bear interest at term SOFR plus an applicable rate ranging from 1.25% to 1.875%, depending on the Company’s Index Debt Rating (as defined in the 2022 credit facility), plus an additional 0.10% credit spread adjustment. Base rate loans will bear interest at the base rate described above plus an applicable rate ranging from 0.25% to 0.875%, depending on the Company’s Index Debt Rating. During an Interim Investment Grade Period or Investment Grade Period (defined below), the commitment fee on unused commitment amounts under the facility will range from 0.15% to 0.275%, depending on the Company’s Index Debt Rating.
The Interim Investment Grade Period will end, and the facility will revert to its characteristics prior to the Interim Investment Grade Period, including being guaranteed by the Guarantors, being secured by collateral and being subject to a borrowing base, having applicable margins and commitment fee determined based on percentage of commitments utilized, as well as limited to compliance with the leverage ratio and current ratio financial covenants but not the PV-9 Coverage Ratio if both of the following are achieved during the Interim Investment Grade Period:
•An Index Debt Rating from Moody’s that is Ba2 or lower; and
•An Index Debt Rating from S&P that is BB or lower.
Upon receiving two Investment Grade Ratings from S&P, Moody’s, or Fitch (such period following, an “Investment Grade Period”), certain restrictive covenants fall away or become more permissive. Upon Investment Grade Period, the leverage ratio and current ratio financial covenants and PV-9 Coverage Ratio will no longer be effective, and the Company will be required to
24
Table of Contents
maintain compliance with a total indebtedness to capitalization ratio, which is the ratio of the Company’s total indebtedness to the sum of total indebtedness plus stockholders’ equity, not to exceed 65%.
As of June 30, 2023, the Company had $25 million in letters of credit and $310 million in borrowings outstanding under the 2022 credit facility. The Company currently does not anticipate being required to supply a materially greater amount of letters of credit under its existing contracts.
Senior Notes

In January 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.30% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of its 4.05% senior notes due 2020 (the “2020 Notes”) and $1.0 billion aggregate principal amount of its 4.95% senior notesSenior Notes due 2025 (the “2025 Notes” together with the 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses.. The interest ratesrate on the 2025 Notes areis determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. In February and June 2016, Moody’s andEffective in July 2018, the interest rate for the 2025 Notes was 6.20%, reflecting a net downgrade in the Company’s bond ratings since their issuance. On April 7, 2020, S&P downgraded the Notes,Company’s bond rating to BB-, which had the effect of increasing the interest rates by 175 basis points effective July 2016.  As a result of these downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% forrate on the 2025 Notes.  InNotes to 6.45% following the event of future downgrades, the coupons for this series of notes are capped at 5.30%,  6.05% and 6.95%, respectively.July 23, 2020 interest payment due date. The first coupon payment to the 2025 Notes bondholders at the higher interest ratesrate was paid in January 2017. 

During2021. On September 1, 2021, S&P upgraded the Company’s bond rating to BB, and on January 6, 2022, S&P further upgraded the Company’s bond rating to BB+, which decreased the interest rate on the 2025 Notes to 5.95% beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022.

In the first half of 2017,2022, the Company redeemed or repurchased (i) $38the remaining outstanding principal balance of $201 million principal amountof its 4.10% Senior Notes due 2022, $46 million of its 8.375% Senior Notes due 2028 and $19 million of its 7.75% Senior Notes due 2027 for a total of $272 million, and recognized a $6 million loss on debt extinguishment.
On February 26, 2023, the Company redeemed all of its outstanding 2018 Notes, (ii) $212 million principal amount of its outstanding 7.50%7.75% Senior Notes due February 2018 and (iii) $26 million2027 (the “2027 Notes”) at a redemption price equal to 103.875% of the outstanding principal amount plus accrued interest of its outstanding 7.15% Senior Notes due June 2018, and$13 million for a total payment of $450 million. The Company recognized an $11a $19 million loss on the extinguishment of debt.

In September 2017,debt, which included the Company completed a public offeringwrite-off of $650$3 million aggregate principal amount of its 7.50% senior notes due 2026 (the “2026 Notes”) and $500 million aggregate principal amount of its 7.75% senior notes due 2027 (the “2027 Notes”), with net proceeds from the offering totaling approximately $1.1 billion after underwritingin related unamortized debt discounts and offering expenses.  Both seriesdebt issuance costs. The Company funded the redemption of senior notes were sold to the public at face value.  The proceeds from this

18

Table of Contents

offering were used to purchase $7582027 Notes using approximately $316 million of the Company’s 2020 Notes in a tender offer and to repay the outstanding balance of $327 million on the Company’s 2015 Term Loan.  The Company recognized a loss on extinguishment of debt of $59 million, which included $53 million of premiums paid.

2016 Credit Facility

In June 2016, the Company reduced its existing $2.0 billion unsecured revolving credit facility to $66 million and entered into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new $743 million unsecured revolving credit facility, which matures in December 2020.  The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due January 2020.  In September 2017, the Company used a portion of the proceeds from the September 2017 debt offering to settle a tender offer by purchasing an aggregate principal amount of approximately $758 million of its outstanding senior notes due in January 2020.    The $1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay down the previous revolving credit facility balance in its entirety.  As of September 30, 2017, there were no borrowings under either revolving credit facility; however, $323 million in letters of credit was outstanding against the 2016 revolving credit facility. 

Loans under the 2016 credit agreement are subject to varying rates of interest based on whether the loan is a Eurodollar loan or an alternate base rate loan.  Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR plus applicable margins ranging from 1.750% to 2.500%.  Alternate base rate loans bear interest at the alternate base rate plus the applicable margin ranging from 0.750% to 1.500%.  The interest rates on the term loan and revolving credit facility are determined based upon the Company’s public debt ratings and was 250  basis points over LIBOR as of September 30, 2017.

The 2016 term loan and revolving credit facility contain financial covenants that impose certain restrictions on the Company.  In September 2017, the Company amended its 2016 credit agreement to reflect the following:

(i) increase the minimum interest coverage ratio to 2.00x commencing with the fiscal quarter ended June 30, 2017 and continued over the life of the 2016 Credit Agreement;

(ii) modify the minimum liquidity covenant such that either (1) if leverage is less than 4.00x or if the 2016 revolving credit facility has been terminated, there is no minimum liquidity covenant, or (2) the Company can elect to replace the minimum liquidity covenant with a maximum leverage ratio of no more than 5.50x for the fiscal quarters ending September 30, 2017 and December 31, 2017,  5.00x for the fiscal quarters ending March 31, 2018 and June 30, 2018 and 4.50x thereafter; and

(iii) modify the mandatory prepayment and commitment reduction provisions to permit the Company to retain the first $500.0 million of net cash proceeds from asset sales that would have otherwise been required to prepay amounts outstanding under the 2016 revolving credit facility and/or reduce commitments under the 2016 revolving credit facility.

In September of 2017, substantially all of the proceeds of the 2026 and 2027 notes issuance were applied to repay existing debt.

As of September 30, 2017, the Company has not elected to replace the minimum liquidity covenant with a maximum leverage covenant.  Therefore, under the amended credit agreement, should the leverage ratio exceed 4.0x, the Company would be subject to a minimum liquidity requirement of $300 million.  The financial covenant with respect to the maximum leverage ratio consists of total debt divided by EBITDAX.  The financial covenant with respect to minimum interest coverage consists of EBITDAX divided by consolidated interest expense.  EBITDAX, as defined in the Company’s 2016 credit agreement, excludes the effects of interest expense, income taxes, depreciation, depletion and amortization, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.  Collateral for the secured term loan is principally the Company’s E&P properties in the Fayetteville Shale area, the equity of its subsidiaries and cash and marketable securities on hand and the credit agreement requires a minimum collateral coverage ratioapproximately $134 million of 1.50x for the 2016 secured term loan.  This collateral also may support all or a part of revolving credit extensions depending on restrictions in the Company’s senior notes indentures.

19

Table of Contents

As of September 30, 2017, the Company was in compliance with all of the covenants of this credit agreement.  Although the Company does not anticipate any violations of the financial covenants, its ability to comply with these covenants is dependent upon the success of its exploration and development program and upon factors beyond the Company’s control, such as the market prices for natural gas, oil and NGLs.

2013 Credit Facility

In December 2013, the Company entered into a credit agreement that exchanged its previous revolving credit facility.  Under this revolving credit facility, the Company originally had a borrowing capacity of $2.0 billion.  The revolving credit facility was unsecured and was not guaranteed by any subsidiaries.  In June 2016, this credit facility was substantially exchanged for a new credit facility comprised of a $1,191 million secured term loan and a new $743 million revolving credit facility.  The borrowing capacity of the original 2013 credit agreement was reduced from $2.0 billion to $66 million, remains unsecured and the maturity remains December 2018.  As of September 30, 2017, there were no borrowings under this facility.

The existing unsecured 2013 revolving credit facility includes a financial covenant under which the Company may not have total debt in excess of 60% of its total adjusted book capital.  This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and the Company’s pension and other postretirement liabilities.  At September 30, 2017, debt constituted 32% of the Company’s adjusted book capital.

2015 Term Loan 

In November 2015, the Company entered into a $750 million unsecured three-year term loan credit agreement with various lenders that was utilized to repay borrowings under the revolving2022 credit facility.  In 2016, the Company repaid $423 million of the $750 million unsecured term loan  from a portion of the net proceeds of the July 2016 equity offering along with proceeds received from a non-core asset sale.  In September 2017, the remaining outstanding balance of $327 million was repaid, and the 2015 Term Loan was terminated.

(10) COMMITMENTS

(11) COMMITMENTS AND CONTINGENCIES

Operating Commitments and Contingencies

As of SeptemberJune 30, 2017,2023, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $8.9$9.8 billion, $3.7$1.4 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. Southwestern EnergyThe Company also had guarantee obligations of up to $832$839 million of that total amount. As of SeptemberJune 30, 2017,2023, future payments under non-cancelable firm transportation and gathering agreements were as follows:



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Payments Due by Period



Total

 

Less than 1 Year

 

1 to 3 Years

 

3 to 5 Years

 

5 to 8 Years

 

More than 8 Years



 

(in millions)

Infrastructure currently in service

$

5,136 

 

$

196 

 

$

1,105 

 

$

524 

 

$

1,492 

 

$

1,819 

Pending regulatory approval and/or construction (1)

 

3,722 

 

 

432 

 

 

458 

 

 

702 

 

 

114 

 

 

2,016 

  Total transportation charges

$

8,858 

 

$

628 

 

$

1,563 

 

$

1,226 

 

$

1,606 

 

$

3,835 

(1)

Based on the estimated in-service dates as of September  30, 2017.

Payments Due by Period
(in millions)TotalLess than 1
Year		1 to 3 Years3 to 5 Years5 to 8 YearsMore than 8
Years
Infrastructure currently in service$8,441 $970 $1,888 $1,696 $1,798 $2,089 
Pending regulatory approval and/or construction (1) 
1,363 61 242 276 362 422 
Total transportation charges$9,804 $1,031 $2,130 $1,972 $2,160 $2,511 

Environmental

(1)Based on estimated in-service dates as of June 30, 2023.
Environmental Risk

The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position, or results of operations or cash flows of the Company.

Litiga

25
Table of Contentstion

Litigation
The Company is subject to various litigation, claims and proceedings, thatmost of which have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, and

20

Table of Contents

pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for such itemslitigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. ManagementAs of June 30, 2023, the Company does not currently have any material amounts accrued related to litigation matters, including the case discussed below. For any matters not accrued for, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible, but, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on the Company’s results of operations or cash flows, for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.

Arkansas Royalty

Bryant Litigation

In

As discussed in Note 2, on September 1, 2021, the Company completed its merger with Indigo, resulting in the assumption of Indigo’s existing litigation.
On June 2017,12, 2018, a collection of 51 individuals and entities filed a lawsuit against fifteen oil and gas company defendants, including Indigo, in Louisiana state court claiming damages arising out of current and historical development and production activity on certain acreage located in DeSoto Parish, Louisiana. The plaintiffs, who claim to own the jury returned a verdictproperties at issue, assert that Indigo’s actions and the actions of other current operators conducting development and production activity, combined with the improper plugging and abandoning of legacy wells by former operators, have caused environmental contamination to their properties. Among other things, the plaintiffs contend that the defendants’ conduct resulted in favorthe migration of natural gas, along with oilfield contaminants, into the Carrizo-Wilcox aquifer system underlying certain portions of DeSoto Parish. The plaintiffs assert claims based in tort, breach of contract and for violations of the Company on all countsLouisiana Civil and Mineral Codes, and they seek injunctive relief and monetary damages in Smith v. SEECO, Inc. et al.,an unspecified amount, including punitive damages.
On September 13, 2018, Indigo filed a class actionvariety of exceptions in response to the plaintiffs’ petition in this matter. Since the initial filing, supplemental petitions have been filed joining additional individuals and entities as plaintiffs in the United States District Courtmatter. On September 29, 2020, plaintiffs filed their fourth supplemental and amending petition in response to the court’s order ruling that plaintiffs’ claims were improperly vague and failed to identify with reasonable specificity the defendants’ allegedly wrongful conduct. Indigo and the majority of the other defendants filed several exceptions to plaintiffs’ fourth amended petition challenging the sufficiency of plaintiffs’ allegations and seeking dismissal of certain claims. On February 18, 2021, plaintiffs filed a fifth supplemental and amending petition, which seeks to augment the claims of select plaintiffs. On October 11, 2021, a sixth supplemental petition was filed which seeks to add the Company as a party to the litigation which the Company has opposed. Plaintiffs later filed seventh and eighth supplemental petitions naming additional defendants. Fact discovery for the Eastern District of Arkansas.  case is ongoing.
The plaintiff had alleged that the Company had underpaid lessors of lands in Arkansas by deducting from royalty payments costs for gathering, transportation and compressionpresence of natural gas in excessa localized area of whatthe Carrizo-Wilcox aquifer system in DeSoto Parish is permittedcurrently the subject of a regulatory investigation by the relevant leasesLouisiana Office of Conservation (“Conservation”), and asserted claims for, among other things, breach of contract, fraud, civil conspiracy, unjust enrichment and violation of certain Arkansas statutes.  Following the verdict, the court entered judgment in favor of the Company on all claims.is cooperating and coordinating with Conservation in that investigation. The plaintiff has moved for a new trial, and the court has not yet ruled on that motion.

Conservation matter number is EMER18-003.

The plaintiff class in Smith comprises the vast majority of lessors of lands in Arkansas for which leases permit deductions for these types of costs.  Most of the remaining lessors are named plaintiffs or members of classes in other pending lawsuits.   In particular, two actions on behalf of certified classes of only Arkansas residents pending in state courts in Arkansas (one is set for trial during the third quarter of 2018; the otherCompany does not have a trial date) and three cases (all currently stayed) that were filed in Arkansas state court on behalf of a total of 248 individually named plaintiffs, two of which have been removed to federal court, have been assigned to the same court that held the Smith trial.  Management believes that, as the Smith jury concluded, the deductions from royalty payments were calculated in accordance with the leases.  The Company currently does not anticipate that these other cases are likelyexpect this matter to have a material adverse effectimpact on theits financial position, results of operations, financial position or cash flows of the Company.

or liquidity.

Indemnifications

The Company provideshas provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings. In the case of assets.  Theseasset dispositions, these indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. The Company likewise obtains indemnification for future matters when it sells assets, although there is no assurance the buyer will be capable of performing those obligations.  In the case of equity offerings, these indemnifications typically relate to claims asserted against underwriters in connection with an offering. No material liabilities have been recognized in connection with these indemnifications.

(11) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS

The Company maintains defined pension and postretirement benefit plans, which cover substantially all of the Company’s employees. Net periodic pension costs include the following components for the three and nine months ended September 30, 2017 and 2016:  



 

 

 

 

 

 

 

 

 

 

 

 



 

Pension Benefits



 

For the three months ended

 

For the nine months ended



 

September 30,

 

September 30,



 

2017

 

2016

 

2017

 

2016



 

(in millions)

Service cost

 

$

2 

 

$

3 

 

$

7 

 

$

9 

Interest cost

 

 

2 

 

 

1 

 

 

4 

 

 

4 

Expected return on plan assets

 

 

(1)

 

 

(2)

 

 

(4)

 

 

(5)

Amortization of prior service cost

 

 

 –  

 

 

−  

 

 

−  

 

 

−  

Amortization of net loss

 

 

 –  

 

 

 –  

 

 

1 

 

 

1 

Curtailment loss

 

 

−  

 

 

 –  

 

 

−  

 

 

1 

Settlement loss

 

 

−  

 

 

2 

 

 

−  

 

 

10 

Net periodic benefit cost

 

$

3 

 

$

4 

 

$

8 

 

$

20 

The Company’s other postretirement benefit plan had a net periodic benefit cost of $1 million for the three months ended September 30,  2017 and 2016 and a net periodic benefit cost (gain) of  $2 million and ($4) million for the nine months ended September 30, 2017 and 2016, respectively.  Included in the net periodic benefit cost for the nine months ended September 30, 2016 is a curtailment gain of $6 million, which more than offset the other components of net periodic benefit cost. 

21

Table of Contents

As of September 30, 2017, the Company has contributed $11 million to the pension and other postretirement benefit plans in 2017.  The Company expects to contribute an additional $3 million to its pension plan during the remainder of 2017.  The Company recognized a liability of  $32 million and $14 million related to its pension and other postretirement benefits, respectively, as of September 30, 2017, compared to a liability of $36 million and $13 million as of December 31, 2016.  The Company updated the discount rate currently used in the measurement of the benefit obligation of the pension plan and other postretirement benefits plan to 4.20% in the second quarter of 2016.  The Company used a discount rate of 4.60% during the first quarter of 2016 for the measurement of the benefit obligation of both the pension and other postretirement benefit plans.    In January 2016, the Company initiated a reduction in workforce that was substantially completed by the end of the first quarter of 2016.  The impact of the workforce reduction on the Company’s pension and other postretirement benefit costs was not recognized until subsequent quarters in 2016 due to the delayed timing of actuarial data available. 

The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the Non-Qualified Plan.  Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are presented as treasury stock and totaled 10,652 shares at September 30, 2017, compared to 31,269 shares at December 31, 2016.

(12) STOCK-BASED COMPENSATION

The Company recognized the following amounts in employee stock-based compensation costs for the three and nine months ended September 30, 2017 and 2016:



 

 

 

 

 

 

 

 

 

 

 

 



 

For the three months ended

 

For the nine months ended



 

September 30,

 

September 30,



 

2017

 

2016

 

2017

 

2016



 

(in millions)

Stock-based compensation cost – expensed (1)

 

$

7 

 

$

6 

 

$

19 

 

$

43 

Stock-based compensation cost – capitalized

 

$

2 

 

$

2 

 

$

10 

 

$

7 
INCOME TAXES

(1)

Includes $16 million and $3 million related to the reduction in workforce and executive management restructuring, respectively, for the nine months ended September 30, 2016.

In January 2016, the Company announced a 40% workforce reduction that was substantially completed by the end of March 2016.  In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016.  Affected employees were offered a severance package that included, if applicable, amendments to certain outstanding equity awards that modified forfeiture provisions on separation from the Company.  As a result, certain unvested stock-based equity awards became fully vested at the time of separation.  These shares were revalued and recognized immediately as a component of restructuring charges on the Company’s unaudited condensed consolidated statements of operations.  The unvested portion of equity-based performance units was forfeited upon separation from the Company.

As of September 30, 2017, there was $67 million of total unrecognized compensation cost related to the Company’s unvested stock option grants, restricted stock grants and performance units.  This cost is expected to be recognized over a weighted-average period of  3 years.

Stock Options

The following table summarizes stock option activity for the nine months ended September 30, 2017 and provides information for options outstanding and options exercisable as of September 30, 2017:



 

 

 

 

 



 

Number

 

Weighted Average



 

of Options

 

Exercise Price



 

(in thousands)

 

(per share)

Outstanding at December 31, 2016

 

 

5,416 

 

$

23.46 

Granted

 

 

1,604 

 

 

8.00 

Exercised

 

 

–  

 

 

–  

Forfeited or expired

 

 

(725)

 

 

17.92 

Outstanding at September 30, 2017

 

 

6,295 

 

 

20.16 

Exercisable at September 30, 2017

 

 

3,336 

 

$

29.37 

22

Table of Contents

Restricted Stock

The following table summarizes restricted stock activity for the nine months ended September 30, 2017 and provides information for unvested shares as of September 30, 2017:  



 

 

 

 

 

 



 

Number

 

 

Weighted Average



 

of Shares

 

 

Fair Value



 

(in thousands)

 

 

(per share)

Unvested shares at December 31, 2016

 

 

3,321 

 

$

 

11.85 

Granted

 

 

5,036 

 

 

 

8.39 

Vested

 

 

(247)

 

 

 

9.40 

Forfeited

 

 

(609)

 

 

 

10.16 

Unvested shares at September 30, 2017

 

 

7,501 

 

$

 

9.68 

Equity-Classified Performance Units

The following table summarizes performance unit activity for the nine months ended September 30, 2017 and provides information for unvested units as of September 30, 2017.  The performance units awarded in 2014 included a market condition based on relative Total Shareholder Return (“TSR”) and a performance condition based on the Company's Present Value Index (“PVI”), collectively the “Performance Measures.”  The fair value of the TSR market condition is based on a Monte Carlo model and the fair value of the PVI performance condition is based on economic analysis for each investment opportunity based upon the expected present value added for each dollar to be invested.  The total fair value of the performance units is amortized to compensation expense on a straight line basis over the vesting period of the award. The performance unit awards granted in 2015, 2016 and during the first nine months of 2017 include a market condition based exclusively on TSR.  The grant date fair value is calculated using the applicable Performance Measures and the closing price of the Company’s common stock at the grant date.



 

 

 

 

 



 

Number

 

Weighted Average



 

of Units (1)

 

Fair Value



 

(in thousands)

 

(per share)

Unvested units at December 31, 2016

 

 

719 

 

$

11.46 

Granted

 

 

1,197 

 

 

10.47 

Vested

 

 

(42)

 

 

5.94 

Forfeited

 

 

(472)

 

 

9.74 

Unvested units at September 30, 2017

 

 

1,402 

 

$

10.78 

(1)

These amounts reflect the number of performance units granted in thousands.  The actual payout of shares may range from a minimum of zero shares to a maximum of two shares per unit contingent upon the actual performance against the Performance Measures. The performance units have a three-year vesting term and the actual disbursement of shares, if any, is determined during the first quarter following the end of the three-year vesting period.

Liability-Classified Performance Units

Prior to 2013, certain employees were awarded performance units which vested equally over three years and which were settled in cash.  The payout of these units was based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goals.  At the end of each performance period, the value of the vested performance units, if any, would be paid in cash.  In the first quarter of 2016, the Company completed the final payout with respect to these performance units.

(13) SEGMENT INFORMATION

The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids.  The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes and through gathering fees associated with the transportation of natural gas to market.

Summarized financial information for the Company’s reportable segments is shown in the following table.  The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 2016 Annual Report. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs.  Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, loss on early extinguishment of debt and other income (loss).  The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items.

23

Table of Contents



 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 



Exploration and Production

 

Midstream Services

 

Other

 

Total



(in millions)

Three months ended September 30, 2017:

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

$

475 

 

$

262 

 

$

–  

 

$

737 

Intersegment revenues

 

(5)

 

 

472 

 

 

–  

 

 

467 

Depreciation, depletion and amortization expense

 

120 

 

 

15 

 

 

–  

 

 

135 

Operating income

 

64 

 

 

46 

 

 

–  

 

 

110 

Interest expense (1)

 

31 

 

 

–  

 

 

–  

 

 

31 

Gain on derivatives

 

45 

 

 

–  

 

 

–  

 

 

45 

Loss on early extinguishment of debt

 

–  

 

 

–  

 

 

(59)

 

 

(59)

Other income (loss), net

 

1 

 

 

(3)

 

 

–  

 

 

(2)

Benefit for income taxes (1)

 

(14)

 

 

–  

 

 

–  

 

 

(14)

Assets

 

4,842 

 

 

1,240 

 

 

1,120 

(2)

 

7,202 

Capital investments (3)

 

320 

 

 

9 

 

 

2 

 

 

331 



 

 

 

 

 

 

 

 

 

 

 

Three months ended September 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

$

381 

 

$

270 

 

$

–  

 

$

651 

Intersegment revenues

 

(3)

 

 

412 

 

 

–  

 

 

409 

Depreciation, depletion and amortization expense

 

83 

 

 

16 

 

 

–  

 

 

99 

Impairment of natural gas and oil properties

 

817 

 

 

–  

 

 

–  

 

 

817 

Operating income (loss)

 

(777)

(4)

 

52 

 

 

–  

 

 

(725)

Interest expense (1)

 

26 

 

 

 –  

 

 

–  

 

 

26 

Gain on derivatives

 

71 

 

 

–  

 

 

–  

 

 

71 

Loss on early extinguishment of debt

 

–  

 

 

–  

 

 

(51)

 

 

(51)

Other income, net

 

2 

 

 

1 

 

 

 –  

 

 

3 

Benefit for income taxes (1)

 

(20)

 

 

–  

 

 

–  

 

 

(20)

Assets

 

4,015 

 

 

1,253 

 

 

1,622 

(2)

 

6,890 

Capital investments (3)

 

179 

 

 

1 

 

 

 –  

 

 

180 



 

 

 

 

 

 

 

 

 

 

 



Exploration and Production

 

Midstream Services

 

Other

 

Total



(in millions)

Nine months ended September 30, 2017:

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

$

1,572 

 

$

822 

 

$

–  

 

$

2,394 

Intersegment revenues

 

(13)

 

 

1,592 

 

 

–  

 

 

1,579 

Depreciation, depletion and amortization expense

 

317 

 

 

47 

 

 

–  

 

 

364 

Operating income

 

435 

 

 

129 

 

 

–  

 

 

564 

Interest expense (1)

 

97 

 

 

–  

 

 

–  

 

 

97 

Gain on derivatives

 

295 

 

 

–  

 

 

–  

 

 

295 

Loss on early extinguishment of debt

 

–  

 

 

–  

 

 

(70)

 

 

(70)

Other income, net

 

5 

 

 

1 

 

 

 –  

 

 

6 

Benefit for income taxes(1)

 

(14)

 

 

–  

 

 

–  

 

 

(14)

Assets

 

4,842 

 

 

1,240 

 

 

1,120 

(2)

 

7,202 

Capital investments (3)

 

921 

 

 

21 

 

 

4 

 

 

946 



 

 

 

 

 

 

 

 

 

 

 

Nine months ended September 30, 2016:

 

 

 

 

 

 

 

 

 

 

 

Revenues from external customers

$

1,015 

 

$

737 

 

$

–  

 

$

1,752 

Intersegment revenues

 

(17)

 

 

1,125 

 

 

–  

 

 

1,108 

Depreciation, depletion and amortization expense

 

300 

 

 

49 

 

 

–  

 

 

349 

Impairment of natural gas and oil properties

 

2,321 

 

 

–  

 

 

–  

 

 

2,321 

Operating income (loss)

 

(2,486)

(4)

 

169 

(5)

 

–  

 

 

(2,317)

Interest expense (1)

 

56 

 

 

1 

 

 

–  

 

 

57 

Loss on derivatives

 

(27)

 

 

(1)

 

 

–  

 

 

(28)

Loss on early extinguishment of debt

 

–  

 

 

–  

 

 

(51)

 

 

(51)

Other income (loss), net

 

3 

 

 

(2)

 

 

(1)

 

 

 –  

Benefit for income taxes

 

(20)

 

 

–  

 

 

–  

 

 

(20)

Assets

 

4,015 

 

 

1,253 

 

 

1,622 

(2)

 

6,890 

Capital investments (3)

 

372 

 

 

3 

 

 

1 

 

 

376 

(1)

Interest expense and the benefit for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.

(2)

Other assets represent corporate assets not allocated to segments and assets for non-reportable segments.  At September 30, 2017 and 2016, other assets includes approximately $989 million and $1.5 billion in cash and cash equivalents, respectively.

24

Table of Contents

(3)

Capital investments includes a decrease of $2 million and an increase of $27 million for the three months ended September 30, 2017 and 2016, respectively, and decreases of $13 million and $24 million for the nine months ended September 30, 2017 and 2016, respectively, relating to the change in capital accruals between periods.

(4)

Operating income (loss) for the E&P segment includes $2 million and $74 million related to restructuring charges for the three and nine months ended September 30, 2016, respectively.

(5)

Operating income (loss) for the Midstream services segment includes $3 million related to restructuring charges for the nine months ended September 30, 2016.

Included in intersegment revenues of the Midstream Services segment are $422 million and $355 million for the three months ended September 30, 2017 and 2016, respectively and $1,436 million and $941 million for the nine months ended September 30, 2017 and 2016, respectively, for marketing of the Company’s E&P sales.  Corporate assets include cash and cash equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments.  

(14)  INCOME TAXES

The Company’s effective tax rate was approximately (21%)(2)% and (2%)0% for the three and ninesix months ended SeptemberJune 30, 2017,2023, respectively, and 3% and 1% for the same periods in 2016, respectively.  The income tax benefits recognized in the third quarter of 2017 resulted from an expected alternative minimum tax refund along with the expiration of a portion of the Company’s uncertain tax provision.  The low effective tax rates are primarily as a result of the existencerelease of a valuation allowance.allowances against the Company’s U.S. deferred tax assets throughout 2023. A valuation allowance for deferred tax assets, including net operating losses (“NOLs”), is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood,

26
Table of Contents
the Company uses estimates and judgment regarding future taxable income and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

The

For the year ended December 31, 2022, the Company maintained a full valuation allowance against its net deferred tax asset position at September 30, 2017assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2022, primarily due to the write-downsimpairments of proved oil and gas properties recognized in 2020. As of the carryingfirst quarter of 2023, the Company sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence such as forecasted income, the Company concluded that $523 million of its federal and state deferred tax assets were more likely than not to be realized and plan to release this portion of the valuation allowance in 2023. Accordingly, during the six months ended June 30, 2023, the Company recognized $504 million of deferred income tax expense related to recording its tax provision which was partially offset by $497 million of tax benefit attributable to the release of the valuation allowance. The remaining valuation allowance will be released during subsequent quarters during 2023. The Company expects to keep a valuation allowance of $66 million related to NOLs in jurisdictions in which it no longer operates and against the portion of its federal and state deferred tax assets such as capital losses and interest carryovers, which may expire before being fully utilized due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied.
Due to the issuance of common stock associated with the Indigo Merger, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available. At June 30, 2023, the Company had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion expire between 2035 and 2037 and $1 billion have an indefinite carryforward life. The Company currently estimates that approximately $2 billion of these federal NOLs will expire before they are able to be used and accordingly, no value has been ascribed to these NOLs on the Company’s balance sheet. If a subsequent ownership change were to occur as a result of future transactions in the Company’s common stock, the Company’s use of remaining U.S. tax attributes may be further limited.
The Inflation Reduction Act of 2022 (the “IRA”) was enacted on August 16, 2022 and may impact how the U.S. taxes certain large corporations. The IRA imposes a 15% alternative minimum tax on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. The Company does not expect to be impacted by this alternative minimum tax during 2023. The Company will continue to monitor updates to the IRA and the impact it will have on the Company’s consolidated financial statements.
(13) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS
Prior to January 1, 2021, substantially all of the Company’s employees were covered by the defined benefit pension plan, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation (the “Plan”). As part of an ongoing effort to reduce costs, the Company elected to freeze the Plan effective January 1, 2021. Employees that were participants in the Plan prior to January 1, 2021 continued to receive the interest component of the Plan but no longer received the service component. On September 13, 2021, the Compensation Committee of the Board approved terminating the Plan, effective December 31, 2021. This decision, among other benefits, will provide Plan participants quicker access to, and greater flexibility in, the management of participants’ respective benefits due under the Plan.
The Company commenced the Plan termination process, and, on April 6, 2022, the Internal Revenue Service issued a favorable determination letter, concurring that the Plan met all of the qualification requirements under the Internal Revenue Code. In December 2022, the Company distributed approximately $38 million of the Plan’s assets to participants in the form of lump sum payments in connection with a limited distribution window provided to all active and former employee participants as part of the Plan termination process.
In March 2023, the Company entered into a group annuity contract with a qualified insurance company relating to the Plan. Under the group annuity contract, the Company purchased an irrevocable nonparticipating single premium group annuity contract from the insurer and transferred to the insurer the future benefit obligations and annuity administration for remaining retirees and beneficiaries under the Plan.
27
Table of Contents
Upon issuance of the group annuity contract, the pension benefit obligations and annuity administration for the remaining participants was irrevocably transferred from the Plan to the insurer. By transferring these obligations through the payment to the insurer in March 2023, the Company has no remaining obligations under the Plan or any other U.S. tax-qualified defined benefit pension plan. The purchase of the group annuity contract was funded directly by the assets of the Plan. The Company recognized a pre-tax non-cash pension settlement charge of approximately $2 million during the six months ended June 30, 2023 as a result of the settlement of the Plan.
As of June 30, 2023, the Company had residual Plan assets of approximately $13 million. The Company has not transferred the residual Plan assets to a qualified replacement plan as of June 30, 2023 as the reconciliation process with the insurance company is ongoing.
The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.
Substantially all of the Company’s employees continue to be covered by the postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
Net periodic pension costs include the following components for the three and six months ended June 30, 2023 and 2022:
Consolidated Statements of
Operations Classification of
Net Periodic Benefit Cost		For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Service costGeneral and administrative expenses$— $— $— $— 
Interest costOther Loss, Net— 1 — 2 
Expected return on plan assetsOther Loss, Net— — — — 
Amortization of prior service costOther Loss, Net— (1)(1)(1)
Settlement lossOther Loss, Net— — 2 — 
Net periodic benefit cost $— $— $1 $1 
The Company’s other postretirement benefit plan had a net periodic benefit cost of less than $1 million for both the three months ended June 30, 2023 and 2022.
The Company did not make any contributions to the Plan during 2023 and does not expect to do so throughout the completion of the Plan termination process. The Company recognized residual pension assets of approximately $13 million and net pension assets of approximately $15 million related to its pension benefits as of June 30, 2023 and December 31, 2022, respectively. The Company recognized liabilities of approximately $10 million and $9 million related to its other postretirement benefits as of June 30, 2023 and December 31, 2022, respectively.
The Company maintains a non-qualified deferred compensation supplemental retirement savings plan (“Non-Qualified Plan”) for certain key employees who may elect to defer and contribute a portion of their compensation, as permitted by the Non-Qualified Plan. Shares of the Company’s common stock purchased under the terms of the Non-Qualified Plan are included in treasury stock and totaled 1,455 shares at June 30, 2023 and 1,743 shares at December 31, 2022.
(14) LONG-TERM INCENTIVE COMPENSATION
The Company’s long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from the Company’s common stock price, and cash-based awards that are fixed in amount but subject to meeting annual performance thresholds.
Stock-Based Compensation
The Company’s stock-based compensation is classified as either equity awards or liability awards in accordance with GAAP. The fair value of an equity-classified award is determined at the grant date and is amortized to general and administrative expense on a straight-line basis over the vesting period of the award. A portion of this general and administrative expense is capitalized into natural gas and oil properties, included in 2015property and 2016.equipment. The fair value of a liability-classified award is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general and administrative expense and capitalized expense over the vesting period of the award. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and
28
Table of Contents
expire 10 years from the date of grant. However, the Company has not granted stock options since 2017. The Company issues shares of restricted stock and restricted stock units to employees and directors which generally vest over three years.
Restricted stock, restricted stock units and stock options granted under the Southwestern Energy Company 2022 Incentive Plan (the “2022 Plan”) immediately vest upon death, disability or retirement (subject to a minimum of three years of service). To the extent no provision is made in connection with a “change in control” (as defined in the 2022 Plan) for the assumption of awards previously granted under the 2022 Plan or there is no substitution of such awards for new awards, then (i) outstanding time-based awards will become fully vested, and (ii) each outstanding performance-based award will vest with respect to the number of shares of common stock underlying such award or the amount of cash underlying the award eligible to vest based on performance during the performance period that includes the date of the change in control, prorated for the number of days which have elapsed during the performance period prior to the change in control. To the extent an award is assumed or substituted in connection with the change in control, if a participant is terminated by the Company without “cause” or the participant resigns for “good reason” (each as defined in the 2022 Plan) within 12 months following a change in control, then (i) each time-based award will become fully vested, and (ii) each outstanding performance-based award will vest based on performance during the performance period that includes the date of the change in control, prorated for the number of days which have elapsed during the performance period prior to such termination.
The Company issues performance unit awards to employees which historically have vested at or over three years. The performance units granted in 2021, 2022 and 2023 cliff-vest at the end of three years.
The Company recognized the following amounts in total related to long-term incentive compensation costs for the three and six months ended June 30, 2023 and 2022:
For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Long-term incentive compensation – expensed$7 $7 $11 $18 
Long-term incentive compensation – capitalized$4 $4 $7 $11 
Equity-Classified Awards
The Company recognized the following amounts in employee equity-classified stock-based compensation costs for the three and six months ended June 30, 2023 and 2022:
For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Equity-classified awards – expensed$4 $2 $5 $3 
Equity-classified awards – capitalized$— $— $1 $— 
Equity-Classified Stock Options
The following table summarizes equity-classified stock option activity for the six months ended June 30, 2023 and provides information for options outstanding and options exercisable as of June 30, 2023:
Number
of Options		Weighted Average
Exercise Price
(in thousands) 
Outstanding at December 31, 2022997 $8.59 
Granted— $— 
Exercised— $— 
Forfeited or expired(177)$8.60 
Outstanding at June 30, 2023820 $8.59 
Exercisable at June 30, 2023820 $8.59 
Equity-Classified Restricted Stock
As of June 30, 2023, there was $1 million of total unrecognized compensation cost related to the Company’s unvested equity-classified restricted stock grants. This cost is expected to be recognized over a weighted-average period of 0.7 years. The following table summarizes equity-classified restricted stock activity for the six months ended June 30, 2023 and provides information for unvested shares as of June 30, 2023:
29
Table of Contents
Number
of Shares		Weighted Average
Fair Value
(in thousands) 
Unvested shares at December 31, 2022211 $5.81 
Granted336 $5.34 
Vested(341)$5.75 
Forfeited— $— 
Unvested shares at June 30, 2023206 $5.15 
Equity-Classified Restricted Stock Units
As of June 30, 2023, there was $9 million of total unrecognized compensation cost related to the Company’s unvested equity-classified restricted stock units. This cost is expected to be recognized over a weighted-average period of 1.7 years. The following table summarizes equity-classified restricted stock units for the six months ended June 30, 2023 and provides information for unvested units as of June 30, 2023.
Number
of Shares		Weighted Average
Fair Value
(in thousands)
Unvested units at December 31, 20221,645 $4.44 
Granted1,539 $4.83 
Vested(555)$4.42 
Forfeited(1)$3.05 
Unvested units at June 30, 20232,628 $4.67 
Equity-Classified Performance Units
In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in either cash or shares. The performance units granted from 2020 through 2021 were accounted for as liability-classified awards as further described below. In 2022 and 2023, two types of performance units were granted. The first type of awards were liability-classified given the awards are payable only in cash as prescribed under the compensation agreements. The second type of awards granted during 2022 and 2023 have been accounted for as equity-classified awards given the intention to settle these awards in stock. The equity-classified awards were recognized at their fair value as of the grant date and are amortized throughout the vesting period. The 2022 and 2023 performance unit awards include a market condition based on relative TSR (as defined below). The fair values of the market conditions were calculated by Monte Carlo models as of the grant date. As of June 30, 2023, there was $8 million of total unrecognized compensation costs related to the Company’s unvested equity-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.3 years.
Number
of Shares		Weighted Average
Fair Value
(in thousands)
Unvested units at December 31, 2022817 $6.04 
Granted940 $6.12 
Vested— $— 
Forfeited— $— 
Unvested units at June 30, 20231,757 $6.08 
Liability-Classified Awards
The Company recognized the following amounts in employee liability-classified stock-based compensation costs for the three and six months ended June 30, 2023:
For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Liability-classified stock-based compensation cost – expensed$— $4 $1 $12 
Liability-classified stock-based compensation cost – capitalized$1 $2 $1 $8 
30
Table of Contents
Liability-Classified Restricted Stock Units
In the first quarter of each year beginning with 2018, the Company granted restricted stock units that vest over a period of four years and are payable in either cash or shares at the option of the Compensation Committee of the Company’s Board. The liability-classified awards granted in 2021 vest over a period of three years. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded decreasesto general and administrative expense and capitalized expense over the vesting period of the award. As of June 30, 2023, there was $4 million of total unrecognized compensation cost related to liability-classified restricted stock units that is expected to be recognized over a weighted-average period of 0.7 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.
Number
of Units		Weighted Average
Fair Value
(in thousands) 
Unvested units at December 31, 20223,950 $4.81 
Granted— $— 
Vested(2,206)$4.84 
Forfeited(3)$5.57 
Unvested units at June 30, 20231,741 $4.33 
Liability-Classified Performance Units
In each year beginning with 2018, the Company granted performance units that vest at the end of, or over, a three-year period and are payable in our valuation allowanceeither cash or shares. The performance units granted in 2020 vest over a three-year period and are payable in cash as prescribed under the compensation agreements and have been accounted for as liability-classified awards. The Company granted two types of $38performance units in 2021 that vest over a three-year period. One type is payable in cash as prescribed under the compensation agreements and the other type is payable in either cash or stock at the option of the Compensation Committee of the Company’s Board. Both award types have been accounted for as liability-classified awards. The Company granted two types of performance units in 2022 and 2023 that vest over a three-year period. For both 2022 and 2023, one type of award is payable in cash as prescribed under the compensation agreements and has been liability-classified while the other type is equity-classified as further discussed above. Changes in the fair market value of the instruments for liability-classified awards will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. 
The performance units granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative total shareholder return (“TSR”). In 2021, of the two types of performance units granted, the first type of award includes a performance condition based on return on capital employed and a performance condition based on reinvestment rate, and the second type of award includes one market condition based on relative TSR. The liability-classified performance units granted in 2022 and 2023 include performance conditions based on return on capital employed and reinvestment rate. The fair values of all market conditions discussed above are calculated by Monte Carlo models on a quarterly basis. 
As of June 30, 2023, there was $6 million of total unrecognized compensation cost related to liability-classified performance units. This cost is expected to be recognized over a weighted-average period of 2.2 years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market. The final value of the performance unit awards is contingent upon the Company’s actual performance against these performance measures.
Number
of Units		Weighted Average
Fair Value
(in thousands) 
Unvested units at December 31, 202210,982 $2.25 
Granted5,136 $4.83 
Vested(3,966)$6.13 
Forfeited— $— 
Unvested units at June 30, 202312,152 $0.98 

31
Table of Contents
Cash-Based Compensation
The Company recognized the following amounts in performance cash award compensation costs for the three and six months ended June 30, 2023 and 2022:
For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Performance cash awards – expensed$3 $1 $5 $3 
Performance cash awards – capitalized$3 $2 $5 $3 
Performance Cash Awards
From 2020 through 2022 the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. In 2023, the Company granted performance cash awards that vest over a three-year period and are payable in cash on an annual basis. The value of each unit of the award equals one dollar. The Company recognizes the cost of these awards as general and administrative expense and capitalized expense over the vesting period of the awards. The performance cash awards granted from 2020 through 2023 include a performance condition determined annually by the Company. For all years, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled. As of June 30, 2023, there was $45 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted-average period of 2.4 years. The final value of the performance cash awards is contingent upon the Company’s actual performance against these performance measures.
Number
of Units		Weighted Average Fair Value
(in thousands)
Unvested units at December 31, 202239,994 $1.00 
Granted27,493 $1.00 
Vested(12,900)$1.00 
Forfeited(2,156)$1.00 
Unvested units at June 30, 202352,431 $1.00 
(15) SEGMENT INFORMATION
The Company’s reportable business segments have been identified based on the differences in products or services provided. The Company’s E&P segment is comprised of gas and oil properties which are managed as a whole rather than through discrete operating segments. Operational information for the Company’s E&P segment is tracked by geographic area; however, financial performance and allocation of resources are assessed at the segment level without regard to geographic area. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids. The Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.
Summarized financial information for the Company’s reportable segments is shown in the following table.  The accounting policies of the segments are the same as those described in Note 1 of the Notes to Consolidated Financial Statements included in Item 8 of the 2022 Annual Report.  Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, gain on early extinguishment of debt and other income (loss). The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items. Corporate general and administrative costs, depreciation expense and taxes, other than income taxes, are allocated to the segments.
32
Table of Contents
Exploration and ProductionMarketingOtherTotal
Three months ended June 30, 2023(in millions)
Revenues from external customers$794 $475 $— $1,269 
Intersegment revenues(17)756 — 739 
Depreciation, depletion and amortization expense326 2 — 328 
Operating income (loss)(70)13 — (57)
Interest expense (1)
34 — — 34 
Gain on derivatives317 — — 317 
Benefit for income taxes (1)
(5)— — (5)
Assets12,413 (2)438 150 13,001 
Capital investments (3)
593 — 2 595 
Three months ended June 30, 2022
Revenues from external customers$2,931 $1,207 $— $4,138 
Intersegment revenues(2)2,816 — 2,814 
Depreciation, depletion and amortization expense286 2 — 288 
Operating income2,120 (4)11 — 2,131 
Interest expense (1)
48 — — 48 
Loss on derivatives(879)— — (879)
Loss on early extinguishment of debt— — (4)(4)
Other loss, net— (1)— (1)
Provision from income taxes (1)
26 — — 26 
Assets11,115 (2)1,664 153 12,932 
Capital investments (3)
585 — — 585 
Exploration and ProductionMarketingOtherTotal
Six months ended June 30, 2023(in millions)
Revenues from external customers$2,233 $1,154 $— $3,387 
Intersegment revenues(27)2,118 — 2,091 
Depreciation, depletion and amortization expense638 3 — 641 
Operating income508 41 — 549 
Interest expense (1)
70 — — 70 
Gain on derivatives1,718 — — 1,718 
Loss on extinguishment of debt— — (19)(19)
Other loss, net(1)— — (1)
Provision for income taxes (1)
7 — — 7 
Assets12,413 (2)438 150 13,001 
Capital investments (3)
1,257 — 3 1,260 
Six months ended June 30, 2022
Revenues from external customers$5,008 $2,073 $— $7,081 
Intersegment revenues(5)4,705 — 4,700 
Depreciation, depletion and amortization expense560 3 — 563 
Operating income3,398 (4)32 — 3,430 
Interest expense (1)
89 — — 89 
Loss on derivatives(4,804)— (2)(4,806)
Loss on early extinguishment of debt— — (6)(6)
Other loss, net— (1)— (1)
Provision from income taxes (1)
30 — — 30 
Assets11,115 (2)1,664 153 12,932 
Capital investments (3)
1,129 — — 1,129 
(1)Interest expense and provision (benefit) for income taxes by segment is an allocation of corporate amounts as they are incurred at the corporate level.
33
Table of Contents
(2)E&P assets includes office, technology, water infrastructure, drilling rigs and other ancillary equipment not directly related to natural gas and oil properties. This also includes deferred tax assets which are an allocation of corporate amounts as they are incurred at the corporate level.
(3)Capital investments include a decrease of $22 million and $220an increase of $34 million for the three and nine months ended SeptemberJune 30, 2017, respectively.  For2023 and June 30, 2022, respectively, and a decrease of $28 million and an increase of $77 million for the six months ended June 30, 2023 and June 30, 2022, respectively, relating to the change in accrued expenditures between periods.
(4)The E&P segment operating income includes $2 million and $27 million of merger-related expenses related to the Indigo and GEPH Mergers for the three and ninesix months ended SeptemberJune 30, 2016, there were increases in our valuation allowance2022, respectively.
The following table presents the breakout of $256 millionother assets, which represent corporate assets not allocated to segments and $903 million, respectively.  Management assessesassets for non-reportable segments at June 30, 2023 and 2022:
As of June 30,
(in millions)20232022
Cash and cash equivalents$25 $50 
Accounts receivable1 1 
Prepayments11 11 
Property, plant and equipment21 9 
Unamortized debt expense17 19 
Right-of-use lease assets53 60 
Non-qualified retirement plan3 3 
Other long-term assets19 (1)— 
$150 $153 
(1)Consists primarily of residual assets associated with the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permitCompany’s pension plan. See Note 13 for discussion on the use of deferred tax assets.  In management’s view, the cumulative loss incurred over recent years outweighs any positive factors, such as the possibility of future growth.  The amount of the deferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.

(15)  Company’s pension plan.

(16)NEW ACCOUNTINGACCOUNTING PRONOUNCEMENTS

New Accounting Standards Implemented

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-09, Compensation – Stock Compensation (Topic 718) (“Update 2016-09”), to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows.  For public entities, Update 2016-09 became effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted.  The Company adopted Update 2016-09 during the first quarter with an effective date of January 1, 2017.  The recognition of previously unrecognized windfall tax benefits resulted in a net cumulative-effect adjustment of $59 million, which increased net deferred tax assets and the related income tax valuation allowance by the same amount as of the beginning of 2017.    The amendments within Update 2016-09 related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation within the operating section of the statement of cash flows were adopted prospectively, with no adjustments made to prior periods.  The Company has elected to account for forfeitures as they occur.  The remaining provisions of this amendment did not have a material effect on its unaudited condensed consolidated results of operations, financial position or cash flows.

Report

25

None.

Table of Contents

New Accounting Standards Not Yet Implemented

In August 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-12, Derivatives and Hedging (Topic 815) (“Update 2017-12”), which makes significant changes to the current hedge accounting rules.  The new guidance impacts the designation of hedging relationships; measurement of hedging relationships; presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures.  The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods.  The Company is evaluating the impact of the adoption of Update 2017-12 on its consolidated financial statements and related disclosures.

In March 2017, the FASB issued Accounting Standards Update No. 2017-07, Compensation - Retirement Benefits (Topic 715) (“Update 2017-07”), which provides additional guidance on the presentation of net benefit cost in the statement of operations and on the components eligible for capitalization in assets.  The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost.  The service cost component of the net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the employees during the period, except for amounts capitalized.  All other components of net benefit cost shall be presented outside of a subtotal for income from operations.  The guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods.  The amendmentsAdopted in this update should be applied retrospectively for the presentation of the service cost component and the other components of net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic benefit cost in assets.  The Company does not expect the impact of adopting Update 2017-07Report

None that are expected to have a material effect on its consolidated financial statements and related disclosures.

In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows.  For public entities, Update 2016-15 becomes effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company does not expect the impact of adopting Update 2016-15 to have a material effect on its consolidated financial statements and related disclosures.  

In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“Update 2016-02”), which seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements.  Through September 2017, the Company made progress on contract reviews, drafting its accounting policies, evaluating lease accounting software and assessing the new disclosure requirements.  The Company will continue assessing the effect that the updated standard may have on its consolidated financial statements and related disclosures, and anticipates that its assessment will be complete in 2018.  For public entities, Update 2016-02 becomes effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue.  The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers and increases disclosure requirements.  The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  The Company performed an analysis, across all revenue streams, of the impact of Update 2014-09 and the related ASUs and did not, to date, identify any changes to its revenue recognition policies that would result in a material adjustment to its consolidated financial statements and related disclosures.  The Company will continue to conduct its contract review process throughout 2017 and, as a result, additional areas of impact may be identified.  The Company expects to adopt the new standard using the modified retrospective approach, under which the cumulative effect of initially applying the new guidance is recognized as an adjustment to the opening balance of retained earnings in the first quarter of 2018.  For public entities, the new standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.

impact.

26

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

OPERATIONS

The following updates information as to Southwestern Energy Company’s financial condition provided in our 2016 Annual Report on Form 10-K for the year ended December 31, 2022 (the “2022 Annual Report”) and analyzes the changes in the results of operations between the three and nine monthssix month periods ended SeptemberJune 30, 20172023 and 2016.2022. For definitions of commonly used natural gas and oil terms used in this Quarterly Report, please refer to the “Glossary of Certain Industry Terms” provided in our 20162022 Annual Report.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in forward-looking statements for many reasons, including the risks described in “Cautionary Statement About Forward-Looking Statements” in the forepart of this Quarterly Report and in Item 1A, “Risk Factors” in Part I and elsewhere in our 20162022 Annual Report, and Item 1A, “Risk Factors” in Part II in this Quarterly Report and any other quarterly report on Form 10-Q filed during the fiscal year.Report. You should read the following discussion with our unaudited condensed consolidated financial statements and the related notes included in this Quarterly Report.

OVERVIEW

Background

Southwestern Energy Company (including its subsidiaries, collectively, “we”, “our”, “us”, “the Company” or “Southwestern”) is

We are an independent energy company engaged in natural gas, oil and NGLNGLs development, exploration development and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses,business, which we refer to as “Midstream Services.”call “Marketing”. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the Appalachian and Haynesville natural gas basins in the lower 48 United States.

Exploration and Production.

E&P. Our primary business is the exploration fordevelopment and production of natural gas oilas well as associated NGLs and NGLs,oil, with our currentongoing operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia, Ohio and Arkansas.Louisiana. Our operations in northeast Pennsylvania, West Virginia and Ohio, which we refer to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale.  Our operations in West Virginia and southwest Pennsylvania, which we refer to as “Southwest Appalachia,“Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oilliquids reservoirs. Our
34
Table of Contents
operations in ArkansasLouisiana, which we refer to as “Haynesville,” are primarily focused on an unconventionalthe Haynesville and Bossier natural gas reservoir known as the Fayetteville Shale.  We have smaller holdings in Colorado and Louisiana, along with other areas in which we are testing potential new resources.reservoirs. We also have drilling rigs located in Pennsylvania, West VirginiaAppalachia and Arkansas,Haynesville, and we provide certain oilfield products and services, principally serving our E&P operations.

Midstream Services.  Throughoperations through vertical integration. Over the past three years, we have completed three strategic acquisitions which have added scale to our affiliated midstream subsidiaries,operations:

•On November 13, 2020, we engageclosed on the Montage Merger, which increased our footprint in West Virginia and Pennsylvania and expanded our operations into Ohio.
•On September 1, 2021, we closed on the Indigo Merger, which established our natural gas gathering activitiesoperations in Arkansasthe Haynesville and Bossier Shales in Louisiana. These activities primarily support
•On December 31, 2021, we closed on the GEPH Merger, which expanded our operations in the Haynesville.
The Indigo Merger and GEPH Merger extended our E&P operationsasset portfolio beyond Appalachia into the Haynesville and generate revenue from fees associated withBossier formations, giving us additional exposure to the gathering of natural gas.LNG corridor and other markets on the U.S. Gulf Coast. These mergers progressed our ability to lower our enterprise business risk, expand our economic inventory, opportunity set and business optionality and capture operating synergies and cost structure savings.
Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in our E&P operations.

Recent Financial and Operating Results
Significant thirdsecond quarter 2017 highlights2023 operating and financial results include:

·

Net income attributable to common stock of $43 million, or $0.09 per diluted share, improved substantially from a net loss attributable to common stock of $735 million, or ($1.52) per diluted share, in the same period in 2016.

Total Company

·

Net cash provided by operating activities of $211 million was up 23% from $172 million in the same period in 2016.

•Net income of $231 million, or $0.21 per diluted share, decreased compared to net income of $1,173 million, or $1.05 per diluted share, for the same period in 2022. Net income decreased primarily from a decrease in operating income of $2,188 million primarily associated with lower realized pricing and production. The decrease in net income from 2022 to 2023 was partially offset by a positive change in our net derivative position of approximately $1.2 billiondue to an increase in derivative gains on our settled hedges of approximately $1,811 million partially offset by a lower mark to market position on our unsettled hedges of approximately $615 million as a result of changes in commodity pricing. Further offsetting the decrease in net income from 2022 to 2023 was decreased interest expense of $14 million as a result from our debt repurchase activity, and a tax benefit of $5 million as compared to tax expense of $26 million.

·

Total net production of 232 Bcfe was up 10% from 211 Bcfe for the same period in 2016.

•Operating loss of $57 million decreased compared to operating income of $2,131 million for the same period in 2022 on a consolidated basis. Operating income decreased as a $2,869 million decrease in operating revenues was only partially offset by decreased operating costs of $681 million associated with lower realized pricing and production.

·

We extended the maturities on our debt by issuing $650 million of Senior Notes due 2026 and $500 million of Senior Notes due 2027 and using the proceeds of approximately $1.1 billion to repurchase $758 million of our 2020 Senior Notes and to repay the outstanding balance of $327 million on our 2015 Term Loan.

•Net cash provided by operating activities of $425 million decreased slightly as compared to $427 million for the same period in 2022. The decrease was primarily attributable to the impact of lower commodity pricing on revenues of $2,063 million and lower production of $89 million and was partially offset by an increase in our settled hedge positions of $1,811 million, changes in working capital of $297 million, lower provision for income taxes of $31 million and lower interest expense of $14 million.

27

•Total capital investment of $595 millionin the second quarter of 2023 increased 2%from $585 million for the same period in 2022 primarily due to increases in costs attributable to inflation.
•We sold non-core natural gas and oil properties in Appalachia for approximately $123 million in cash, subject to customary post-closing adjustments. The cash proceeds were used to pay down our revolving credit facility.
E&P
•E&P operating loss of $70 millionin the second quarter of 2023 decreased from operating income of $2,120 million in 2022for a total decrease of $2,190 million, primarily due to a $2,152 million decrease in E&P operating revenues resulting from a $4.85 per Mcfe decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 15 Bcfe decreasein production volumes combined with a $38 millionincrease in E&P operating costs and expenses attributable to inflation.
•Total net production of 423 Bcfe, which was comprised of 86% natural gas and 14% oil and NGLs, decreased 3% from 438 Bcfe in the same period in 2022, primarily due to a 5% decrease in our natural gas production.
•Excluding the effect of derivatives, our realized natural gas price of $1.47 per Mcf decreased 77%, our realized oil price of $63.20 per barrel decreased 37% and our realized NGL price of $18.63 per barrel decreased 54%, as compared to the same
35

Table of Contents

RESULTS

period in 2022. Excluding the effect of derivatives, our total weighted average realized price of $1.84 per Mcfe decreased 72% from the same period in 2022.
•E&P segment invested $593 million in capital; drilling 38 wells, completing 46 wells and placing 50 wells to sales.
Outlook
Our primary focus in 2023 is to generally maintain our productive capacity and improve the safety and efficiency of our operations to optimize our ability to generate free cash flow, further reduce debt and return capital to shareholders (subject to market and business conditions).
As we continue to develop our core positions in the Appalachian and Haynesville natural gas basins in the U.S., we will concentrate on:
•Creating Sustainable Value. We seek to create value for our stakeholders by allocating capital that is focused on earning economic returns and optimizing the value of our assets; delivering sustainable free cash flow through the cycle; upgrading the quality, depth and capital efficiency of our drilling inventory; and converting resources to proved reserves.
•Protecting Financial Strength. We intend to protect our financial strength by lowering our leverage ratio and total debt; maintaining a strong liquidity position and debt maturity profile; lowering our weighted average cost of debt; and deploying hedges to balance revenue protection with commodity upside exposure.
•Focus on Execution. We are focused on operating effectively and efficiently with health, safety and environmental (“HSE”) matters and environmental, social and governance (“ESG”) matters as core values; leveraging our data analytics, operating execution, strategic sourcing, vertical integration and large-scale asset development expertise; further enhancing well performance, optimizing well costs and reducing base production declines; and growing margins and securing flow assurance through commercial and marketing arrangements.
•Capturing the Tangible Benefits of Scale. We strive to enhance our enterprise returns by leveraging the scale gained from our past strategic transactions to deliver operating synergies, drive cost savings, expand our economic inventory, lower our enterprise risk profile, and expand our opportunity set and optionality.
We remain committed to achieving these objectives while maintaining our commitment to being environmentally conscious and proactive and to using best practices in social stewardship and corporate governance. We believe that we and our industry will continue to face challenges due to evolving environmental standards and expectations of both regulators and investors, the uncertainty of natural gas, oil and NGL prices in the United States, changes in laws, regulations and investor sentiment, and other key factors described in the 2022 Annual Report. As such, we intend to protect our financial strength by reducing our debt while continuing to extend the weighted average years to maturity of our debt, and by maintaining a derivative program designed to reduce our exposure to commodity price volatility.
RESULTS OF OPERATIONS

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income tax expensetaxes are discussed on a consolidated basis.

Exploration and Production



 

 

 

 

 

 

 

 

 

 

 



For the three months

 

For the nine months



ended September 30,

 

ended September 30,

(in millions except percentages)

2017

 

2016

 

2017

 

2016

Revenues

$

470 

 

$

378 

 

$

1,559 

 

$

998 

Impairment of natural gas and oil properties

$

–  

 

$

817 

 

$

–  

 

$

2,321 

Operating costs and expenses (1)

$

406 

 

$

338 

 

$

1,124 

 

$

1,163 

Operating income (loss)

$

64 

 

$

(777)

 

$

435 

 

$

(2,486)

Gain (loss) on derivatives, settled (2)

$

17 

 

$

(9)

 

$

(52)

 

$

22 
E&P

For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Revenues$777 $2,929 $2,206 $5,003 
Operating costs and expenses (1)
847 809 1,698 1,605 
Operating income (loss)$(70)$2,120 $508 $3,398 
Gain (loss) on derivatives, settled$210 $(1,601)$87 $(2,296)
(1)Includes $2 million and $74$27 million of restructuring chargesin merger-related expenses related to our Indigo and GEPH Mergers for the three and ninesix months ended SeptemberJune 30, 2016,2022, respectively.

(2)     Represents the gain (loss) on settled commodity derivatives.

36
Table of Contents
Operating Income

(Loss)

·

E&P segment operating income for the three and nine months ended September 30, 2016 includes impairments of natural gas and oil properties of $817 million and $2.3 billion, respectively.  Excluding the 2016 impairment, our E&P segment operating income increased $24 million for the three months ended September 30, 2017, compared to the same period in 2016, primarily due to a $92 million increase in revenues partially offset by a $68 million increase in operating costs.

•E&P segment operating loss decreased $2,190 millionfor the three months ended June 30, 2023, compared to the same period in 2022. This was primarily due to a $2,152 million decrease in E&P operating revenues resulting from a 72% decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 3% decrease in production volumes combined with a $38 million increase in E&P operating costs and expenses.

·

Excluding the 2016 impairment, our E&P segment operating income increased $600 million for the nine months ended September 30, 2017, compared to the same period in 2016, due to a $561 million increase in revenues and a $39 million decrease in operating costs.

•E&P segment operating income decreased $2,890 millionfor the six months ended June 30, 2023, compared to the same period in 2022. This was primarily due to a $2,797 million decrease in E&P operating revenues resulting from a 54% decrease in our realized weighted average price per Mcfe (excluding derivatives) and a 3% decrease in production volumes combined with a $93 million increase in E&P operating costs and expenses.

Revenues



 

 

 

 

 

 

 

 

 

 

 

 



 

Three Months Ended September 30



 

Natural

 

 

 

 

 

 

(in millions except percentages)

 

Gas

 

Oil

 

NGLs

 

Total

2016 sales revenues

 

$

337 

 

$

19 

 

$

22 

 

$

378 

Changes associated with prices

 

 

24 

 

 

3 

 

 

28 

 

 

55 

Changes associated with production volumes

 

 

27 

 

 

5 

 

 

5 

 

 

37 

2017 sales revenues

 

$

388 

 

$

27 

 

$

55 

 

$

470 

Increase from 2016

 

 

15% 

 

 

42% 

 

 

150% 

 

 

24% 



 

 

 

 

 

 

 

 

 

 

 

 



 

Nine Months Ended September 30



 

Natural

 

 

 

 

 

 

(in millions except percentages)

 

Gas

 

Oil

 

NGLs

 

Total

2016 sales revenues

 

$

890 

 

$

49 

 

$

59 

 

$

998 

Changes associated with prices

 

 

492 

 

 

23 

 

 

70 

 

 

585 

Changes associated with production volumes

 

 

(28)

  

 

1 

 

 

3 

 

 

(24)

2017 sales revenues

 

$

1,354 

 

$

73 

 

$

132 

 

$

1,559 

Increase from 2016

 

 

52% 

 

 

49% 

 

 

124% 

 

 

56% 

The tables above illustratefollowing illustrates the effects of the increaseon sales revenues associated with changes in commodity prices and changes associated with production volumes.

volumes:

28

Three months ended June 30,
(in millions except percentages)Natural
Gas		OilNGLsTotal
2022 sales revenues (1)
$2,485 $136 $310 $2,931 
Changes associated with prices(1,833)(53)(177)(2,063)
Changes associated with production volumes(117)8 20 (89)
2023 sales revenues (2)
$535 $91 $153 $779 
Decrease from 2022(78 %)(33 %)(51 %)(73 %)
Six months ended June 30,
(in millions except percentages)Natural
Gas		OilNGLsTotal
2022 sales revenues$4,175 $246 $582 $5,003 
Changes associated with prices(2,278)(82)(301)(2,661)
Changes associated with production volumes(226)21 73 (132)
2023 sales revenues (2)
$1,671 $185 $354 $2,210 
Decrease from 2022(60 %)(25 %)(39 %)(56 %)
(1)Excludes $2 million in other operating revenues for the three months ended June 30, 2022 primarily related to gas balancing losses.
(2)Excludes $2 million and$4 million in other operating revenues for the three and six months ended June 30, 2023, respectively, primarily related to gas balancing losses.
37

Table of Contents

Production Volumes

 

 

 

 

 

 

 

 

 

 

 

For the three months

 

 

 

For the nine months

 

 

ended September 30,

 

Increase/

 

ended September 30,

 

Increase/

For the three months ended June 30,Increase/(Decrease)For the six months ended June 30,Increase/(Decrease)

Production volumes:

2017

 

2016

 

(Decrease)

 

2017

 

2016

 

(Decrease)

Production volumes:2023202220232022

Natural Gas (Bcf)

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Bcf)
   

Northeast Appalachia

101 

 

84 

 

20%

 

285 

 

268 

 

6%

Southwest Appalachia

25 

 

15 

 

67%

 

60 

 

48 

 

25%

Fayetteville Shale

78 

 

90 

 

(13%)

 

241 

 

289 

 

(17%)

Other

1 

 

–  

 

100%

 

1 

 

 −  

 

100%

AppalachiaAppalachia199 214 (7)%392 424 (8)%
HaynesvilleHaynesville166 169 (2)%326 335 (3)%

Total

205 

 

189 

 

8%

 

587 

 

605 

 

(3%)

Total365 383 (5)%718 759 (5)%

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

Southwest Appalachia

639 

 

503 

 

27%

 

1,673 

 

1,610 

 

4%

AppalachiaAppalachia1,434 1,354 6%2,843 2,617 9%
HaynesvilleHaynesville7 7 —%15 11 36%

Other

24 

 

33 

 

(27%)

 

74 

 

119 

 

(38%)

Other— 2 (100)%1 5 (80)%

Total

663 

 

536 

 

24%

 

1,747 

 

1,729 

 

1%

Total1,441 1,363 6%2,859 2,633 9%

 

 

 

 

 

 

 

 

 

 

 

NGL (MBbls)

 

 

 

 

 

 

 

 

 

 

 

NGL (MBbls)

Southwest Appalachia

3,799 

 

3,053 

 

24%

 

10,098 

 

9,536 

 

6%

AppalachiaAppalachia8,240 7,738 6%16,480 14,657 12%
HaynesvilleHaynesville5 — 100%5 — 100%

Other

11 

 

15 

 

(27%)

 

36 

 

44 

 

(18%)

Other2 — 100%2 — 100%

Total

3,810 

 

3,068 

 

24%

 

10,134 

 

9,580 

 

6%

Total8,247 7,738 7%16,487 14,657 12%

 

 

 

 

 

 

 

 

 

 

 

Production volumes by area (Bcfe):

 

 

 

 

 

 

 

 

 

 

 

Northeast Appalachia

101 

 

84 

 

20%

 

285 

 

268 

 

6%

Southwest Appalachia

52 

 

37 

 

41%

 

131 

 

115 

 

14%

Fayetteville Shale

78 

 

90 

 

(13%)

 

241 

 

289 

 

(17%)

Other

1 

 

–  

 

100%

 

1 

 

1 

 

–%

Production volumes by area: (Bcfe)
Production volumes by area: (Bcfe)
AppalachiaAppalachia257 269 (4)%508 528 (4)%
HaynesvilleHaynesville166 169 (2)%326 335 (3)%

Total

232 

 

211 

 

10%

 

658 

 

673 

 

(2%)

Total423 438 (3)%834 863 (3)%
Production volumes by formation: (Bcfe)
Production volumes by formation: (Bcfe)
Marcellus ShaleMarcellus Shale228 226 1%448 443 1%
Utica ShaleUtica Shale29 43 (33)%60 85 (29)%
Haynesville ShaleHaynesville Shale97 105 (8)%195 210 (7)%
Bossier ShaleBossier Shale69 64 8%131 125 5%
TotalTotal423 438 (3)%834 863 (3)%
   
Production percentage:Production percentage:   
Natural gasNatural gas86 %87 % 86 %88 %
OilOil2 %2 % 2 %2 %
NGLNGL12 %11 % 12 %10 %

·

Production volumes for our E&P segment increased by 21 Bcfe for the three months ended September 30, 2017, compared to the same period in 2016, as increased production volumes from Northeast and Southwest Appalachia more than offset a natural gas production volume decline in the Fayetteville Shale.    

•E&P production volumes decreased by 15 Bcfe and 29 Bcfe for the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022. Lower natural gas production is attributable to our moderation of activity related to the decrease in near-term natural gas prices and the impact of inflation.

·

E&P segment production volumes decreased 15 Bcfe for the nine months ended September 30, 2017, compared to the same period in 2016, as a natural gas production volume decline in the Fayetteville Shale more than offset increased production volumes from Northeast and Southwest Appalachia.

•Oil and NGL production increased 6% and 12% for the three and six months ended June 30, 2023, respectively, as compared to the same period in 2022, primarily due to a higher allocation of capital investment to liquids- rich areas.

Commodity

Commodity Prices

The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we cannotcan neither control ornor predict, including increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our hedgingderivative activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity to invest within cash flows in order to maintain appropriate liquidity and financial flexibility.



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



For the three months

 

 

 

For the nine months

 

 



ended September 30,

 

Increase/

 

ended September 30,

 

Increase/

Average realized price per unit:

2017

 

2016

 

(Decrease)

 

2017

 

2016

 

(Decrease)

Natural gas sales, excluding derivatives (per Mcf)

$

1.89 

 

$

1.78 

 

6%

 

$

2.31 

 

$

1.47 

 

57%

Effect of settled gain (loss) on derivatives (per Mcf)

 

0.08 

 

 

(0.05)

 

260%

 

 

(0.09)

 

 

0.04 

 

(325%)

Natural gas sales, including derivatives (per Mcf)

$

1.97 

 

$

1.73 

 

14%

 

$

2.22 

 

$

1.51 

 

47%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil sales (per Bbl)

$

40.49 

 

$

35.41 

 

14%

 

$

41.48 

 

$

28.53 

 

45%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

NGL sales, excluding derivatives (per Bbl)

$

14.45 

 

$

7.03 

 

106%

 

$

13.04 

 

$

6.11 

 

113%

Effect of settled gain (loss) on derivatives (per Bbl)

 

0.02 

 

 

0.01 

 

100%

 

 

0.02 

 

 

–  

 

100%

NGL sales, including derivatives (per Bbl)

$

14.47 

 

$

7.04 

 

106%

 

$

13.06 

 

$

6.11 

 

114%

38

·

The average price realized for our natural gas production, including the effect of derivatives, increased for the three months ended September 30, 2017, compared to the same period in 2016, due to an $0.11 per Mcf increase in the average realized price, excluding derivatives, and a $0.13 per Mcf increase associated with our settled derivatives.

29

Table of Contents

·

Our average price realized for natural gas production, including the effect of derivatives, increased significantly for the nine months ended September 30, 2017, compared to the same period in 2016, due to an $0.84 per Mcf increase in the average realized price, excluding derivatives, partially offset by a $0.13 per Mcf decrease associated with our settled derivatives.

·

The average price realized for our crude oil production increased by $5.08 per Bbl and $12.95 per Bbl for the three and nine months ended September 30, 2017, compared to the same periods in 2016, respectively.  We did not use derivatives to financially protect our 2017 or 2016 oil production.

For the three months ended June 30,Increase/(Decrease)For the six months ended June 30,Increase/(Decrease)
2023202220232022
Natural Gas Price:   
NYMEX Henry Hub Price ($/MMBtu) (1)
$2.10 $7.17 (71)%$2.76 $6.06 (54)%
Discount to NYMEX (2)
(0.63)(0.69)(9)%(0.43)(0.56)(23)%
Average realized gas price, excluding derivatives ($/Mcf)
$1.47 $6.48 (77)%$2.33 $5.50 (58)%
Gain (loss) on settled financial basis derivatives ($/Mcf)
(0.02)0.06 (0.05)0.04 
Gain (loss) on settled commodity derivatives ($/Mcf)
0.57 (3.86)0.17 (2.70)
Average realized gas price, including derivatives ($/Mcf)
$2.02 $2.68 (25)%$2.45 $2.84 (14)%
Oil Price:
WTI oil price ($/Bbl) (3)
$73.78 $108.41 (32)%$74.96 $101.35 (26)%
Discount to WTI (4)
(10.58)(8.12)30%(10.41)(7.81)33%
Average oil price, excluding derivatives ($/Bbl)
$63.20 $100.29 (37)%$64.55 $93.54 (31)%
Loss on settled derivatives ($/Bbl)
(6.38)(43.35)(7.06)(39.81)
Average oil price, including derivatives ($/Bbl)
$56.82 $56.94 —%$57.49 $53.73 7%
NGL Price:
Average realized NGL price, excluding derivatives ($/Bbl)
$18.63 $40.07 (54)%$21.51 $39.72 (46)%
Gain (loss) on settled derivatives ($/Bbl)
2.22 (10.84)1.20 (11.50)
Average realized NGL price, including derivatives ($/Bbl)
$20.85 $29.23 (29)%$22.71 $28.22 (20)%
Percentage of WTI, excluding derivatives       25 %       37 %29%39%
Total Weighted Average Realized Price:
Excluding derivatives ($/Mcfe)
$1.84 $6.69 (72)%$2.65 $5.80 (54)%
Including derivatives ($/Mcfe)
$2.33 $3.04 (23)%$2.75 $3.14 (12)%

·

Our average price realized for NGL production, including the effect of derivatives, increased by $7.43 per Bbl and $6.95 per Bbl for the three and nine months ended September 30, 2017, compared to the same periods in 2016, respectively.

(1)Based on last day settlement prices from monthly futures contracts.

Our E&P segment receives

(2)This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation and fuel charges, and excludes financial basis derivatives.
(3)Based on the average daily settlement price of the nearby month futures contract over the period.
(4)This discount primarily includes location and quality adjustments.
We receive a sales price for our natural gas at a discount to average monthly NYMEX settlement prices based on heating content of the gas, locational basis differentials and transportation and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate (“WTI”) settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition and types of NGLs sold, locational basis differentials and transportation and fuel charges.

·

Excluding the impact of derivatives, the average price received for our natural gas production for the nine months ended September 30, 2017 of $2.31 per Mcf was approximately $0.86 per Mcf lower than the average monthly NYMEX settlement price, primarily due to locational basis differentials and transportation charges.  In comparison, the average price received for our natural gas production for the same period in 2016 of $1.47 per Mcf was approximately $0.82 per Mcf lower than the average monthly NYMEX settlement price.

We regularly enter into various hedgingderivatives and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to ensuresupport certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 3, "QuantitativeQuantitative and Qualitative Disclosures About Market Risks"Risk, and Note 67 to the unaudited condensed consolidated financial statements, included in this Quarterly Report for additional discussion aboutReport.

39
Table of Contents
The tables below present the amount of our future natural gas production in which the impact of basis volatility has been limited through derivatives and risk management activities.

physical sales arrangements as of June 30, 2023:

·

As of September 30, 2017, we have physically protected basis on approximately 72 Bcf and 145 Bcf of our remaining 2017 and 2018 expected natural gas production, respectively, through physical sales arrangements at a basis differential to NYMEX natural gas price of approximately ($0.47) per MMBtu and ($0.36) per MMBtu for the remainder of 2017 and 2018, respectively. 

Volume (Bcf)
Basis Differential
Basis Swaps – Natural Gas
2023146 $(0.62)
202446 (0.71)
20259 (0.64)
Total201 
Physical NYMEX Sales Arrangements – Natural Gas (1)
2023398 $(0.16)
2024626 (0.12)
2025474 (0.07)
2026366 (0.04)
2027329 (0.03)
2028302 (0.02)
2029252 (0.01)
2030105 (0.01)
Total2,852 

·

We have also financially protected basis on approximately 32 Bcf and 25 Bcf of our remaining 2017 and 2018 expected natural gas production, respectively, at a basis differential to NYMEX natural gas price of approximately ($0.95) per MMBtu and ($0.63) per MMBtu for the remainder of 2017 and 2018, respectively.

(1)Based on last day settlement prices from monthly futures contracts.

·

As of September 30, 2017 we have also financially protected 138 Bcf of our remaining 2017 natural gas production to limit our exposure to NYMEX price fluctuations. 

In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of June 30, 2023:

Remaining
2023		Full Year
2024		Full Year
2025
Natural gas (Bcf)
521 583 179 
Oil (MBbls)
2,342 1,717 41 
Ethane (MBbls)
4,499 1,305 — 
Propane (MBbls)
3,601 1,460 — 
Normal Butane (MBbls)
396 329 — 
Natural Gasoline (MBbls)
342 329 — 
Total financial protection on future production (Bcfe)
588 614 179 
We refer you to Note 67 to of the unaudited condensed consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments.

30

Operating Costs and Expenses
For the three months ended June 30, Increase/(Decrease)For the six months ended June 30,Increase/(Decrease)
(in millions except percentages)20232022 20232022
Lease operating expenses$425 $425  —%$855 $826 4%
General & administrative expenses37 

31 

19%79 70 13%
Merger-related expenses— 2 (100)%— 27 (100)%
Taxes, other than income taxes59 65  (9)%126 122 3%
Full cost pool amortization324 283 14%632 552 14%
Non-full cost pool DD&A2 3  (33)%6 8 (25)%
Total operating costs$847 $809 5%$1,698 $1,605 6%
40

Table of Contents

Operating Costs

For the three months ended June 30,Increase/For the six months ended June 30,Increase/
Average unit costs per Mcfe:20232022(Decrease)20232022(Decrease)
Lease operating expenses (1)
$1.00 $0.97 3%$1.03 $0.96 7%
General & administrative expenses$0.09 $0.07 (2)29%$0.09 $0.08 (2)13%
Taxes, other than income taxes$0.14 $0.15 (7)%$0.15 $0.14 7%
Full cost pool amortization$0.77 $0.65 18%$0.76 $0.64 19%
(1)Includes post-production costs such as gathering, processing, fractionation and Expenses



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



For the three months

 

 

 

For the nine months

 

 



ended September 30,

 

Increase/

 

ended September 30,

 

Increase/

(in millions except percentages)

2017

 

2016

 

(Decrease)

 

2017

 

2016

 

(Decrease)

Lease operating expenses

$

210 

 

$

181 

 

16%

 

$

591 

 

$

586 

 

1%

General & administrative expenses

 

54 

 

 

50 

 

8%

 

 

147 

 

 

141 

 

4%

Taxes, other than income taxes

 

22 

 

 

22 

 

–%

 

 

69 

 

 

62 

 

11%

Restructuring Charges

 

–  

 

 

2 

 

(100%)

 

 

–  

 

 

74 

 

(100%)

Full cost pool amortization

 

111 

 

 

73 

 

52%

 

 

291 

 

 

268 

 

9%

Non-full cost pool DD&A

 

9 

 

 

10 

 

(10%)

 

 

26 

 

 

32 

 

(19%)

Total operating costs

$

406 

 

$

338 

 

20%

 

$

1,124 

 

$

1,163 

 

(3%)



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



For the three months

 

 

 

For the nine months

 

 



ended September 30,

 

Increase/

 

ended September 30,

 

Increase/

Average unit costs per Mcfe:

2017

 

2016

 

(Decrease)

 

2017

 

2016

 

(Decrease)

Lease operating expenses

$

0.91 

 

$

0.86 

 

6%

 

$

0.90 

 

$

0.87 

 

3%

General & administrative expenses (1)

$

0.23 

 

$

0.23 

 

–%

 

$

0.22 

 

$

0.21 

 

5%

Taxes, other than income taxes (2)

$

0.10 

 

$

0.10 

 

–%

 

$

0.10 

 

$

0.09 

 

11%

Full cost pool amortization

$

0.48 

 

$

0.35 

 

37%

 

$

0.44 

 

$

0.40 

 

10%

compression.

(1)

Excludes $2 million and $71 million of restructuring charges for the three and nine months ended September 30, 2016, respectively.

(2)Excludes $2 million and $27 million in merger-related expenses related to the Indigo and GEPH Mergers for the three and six months ended June 30, 2022, respectively.

(2)

Excludes $3 million of restructuring charges for the nine months ended September 30, 2016.

Lease Operating Expenses

·

Lease operating expenses per Mcfe increased $0.05 for the three months ended September 30, 2017, compared to the same period of 2016, primarily due to increased salt water disposal costs and increased gas processing costs as our production growth shifts toward the Appalachian basin.

•Lease operating expenses per Mcfe increased $0.03 and $0.07 for the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022, primarily due to increased operating costs associated with the impact of inflation.

·

Lease operating expenses per Mcfe increased $0.03 for the nine months ended September 30, 2017, compared to the same period of 2016, primarily due to the impact of increased prices for natural gas used as compressor fuel.

General and Administrative Expenses

·

General and administrative expenses per Mcfe remained flat for the three months ended September 30, 2017 and 2016 as the $4 million increase was offset by a 10% increase in production volumes.  For the nine months ended September 30, 2017, general and administrative expenses per Mcfe increased 5% compared to the same period from the prior year primarily due to increased professional fees and legal settlements.

•General and administrative expenses increased $6 million or $0.02 per Mcfe and $9 million or $0.01 per Mcfe for the three and six months ended June 30, 2023, respectively, compared to the same periods in 2022, primarily due to costs associated with the development of our enterprise resource technology.

Merger-Related Expenses
•We focused on building scale and geographic diversification throughout 2021. As a result of this strategy, we merged with Indigo in September 2021 and GEPH in December 2021 which resulted in merger-related expenses during 2022. The tables below present the charges incurred for our merger-related activities for the three and six months ended June 30, 2022:
For the three months ended June 30, 2022For the six months ended June 30, 2022
(in millions)Indigo MergerGEPH MergerTotalIndigo MergerGEPH MergerTotal
Transition services$— $— $— $— $18 $18 
Professional fees (advisory, bank, legal, consulting)— — — — 1 1 
Contract buyouts, terminations and transfers1 — 1 1 2 3 
Due diligence and environmental— 1 1 1 1 2 
Employee-related— — — — 1 1 
Other— — — — 2 2 
Total merger-related expenses$1 $1 $2 $2 $25 $27 
We refer you to Note 2 of the consolidated financial statements included in this Quarterly Report for additional details about the Indigo and GEPH Mergers. We had no merger-related expenses for the three or six months ended June 30, 2023.
Taxes, Other than Income Taxes

·

Taxes other than income taxes per Mcfe vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in commodity prices.

•On a per Mcfe basis, taxes, other than income taxes may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes, fluctuations in commodity prices and changes in the tax rates enacted by the respective states we operate in. 

•Taxes, other than income taxes, per Mcfe decreased $0.01 for the three months ended June 30, 2023, compared to the same period in 2022, primarily due to lower commodity pricing on our severance taxes in West Virginia, which are calculated as a fixed percentage of revenue net of allowable production expenses.
•Taxes, other than income taxes, per Mcfe increased $0.01 for the six months ended June 30, 2023, compared to the same period in 2022, primarily due to increases in ad valorem taxes partially offset by lower commodity pricing on our severance taxes in West Virginia.
Full Cost Pool Amortization

·

Our full cost pool amortization rate increased $0.13 per Mcfe and $0.04 per Mcfe for the three and nine months ended September 30, 2017, respectively, as compared to the same periods in 2016.  The increase in the average amortization rate resulted primarily from the addition of future development costs associated with proved undeveloped reserves recognized as a result of improved commodity prices. 

•Our full cost pool amortization rate increased $0.12 per Mcfe for the three and six months ended June 30, 2023, as compared to the same periods in 2022, primarily as a result of increases in development costs as a result of inflation.

41
Table of Contents
•The amortization rate is impacted by the timing and amount of reserve additions and the future development costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from non-cash full cost ceiling impairments, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserve changes.

•Unevaluated costs excluded from amortization were $2,163 million and $2,217 million at June 30, 2023 and December 31,

Table 2022, respectively. The unevaluated costs excluded from amortization decreased as the impact of Contents

$125 million of unevaluated capital invested during the period was more than offset by the evaluation of previously unevaluated properties totaling $179 million.

·

Unevaluated costs excluded from amortization were $1.9 billion at September 30, 2017, compared to $2.1 billion at December 31, 2016.  The unevaluated costs excluded from amortization decreased as the evaluation of previously unevaluated properties totaling $491 million in the first nine months of 2017 was only partially offset by the impact of $297 million of unevaluated capital invested during the same period.

Marketing
For the three months ended June 30,Increase/
(Decrease)		For the six months ended June 30,Increase/
(Decrease)
(in millions except volumes and percentages)2023202220232022
Marketing revenues$1,231$4,023(69)%$3,272 $6,778 (52)%
Marketing purchases1,2134,006(70)%3,220 6,734 (52)%
Operating costs and expenses5

6

(17)%11 12 (8)%
Operating income$13$1118%$41 $32 28%
 
Volumes marketed (Bcfe)
574

577(1)%1,125 1,115 1%
  
Percent natural gas production marketed from affiliated E&P operations93 %

94 % 93 %93 %
Affiliated E&P oil and NGL production marketed88 %88 % 89 %86 %

Midstream Services



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



For the three months

 

 

 

For the nine months

 

 



ended September 30,

 

Increase/

 

ended September 30,

 

Increase/

(in millions except percentages)

2017

 

2016

 

(Decrease)

 

2017

 

2016

 

(Decrease)

Marketing revenues

$

656 

 

$

591 

 

11%

 

$

2,173 

 

$

1,571 

 

38%

Gas gathering revenues

$

78 

 

$

91 

 

(14%)

 

$

241 

 

$

291 

 

(17%)

Marketing purchases

$

645 

 

$

578 

 

12%

 

$

2,141 

 

$

1,533 

 

40%

Operating costs and expenses (1)

$

43 

 

$

52 

 

(17%)

 

$

144 

 

$

160 

 

(10%)

Operating income

$

46 

 

$

52 

 

(12%)

 

$

129 

 

$

169 

 

(24%)



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Volumes marketed (Bcfe)

 

273 

 

 

264 

 

3%

 

 

782 

 

 

814 

 

(4%)

Volumes gathered (Bcf)

 

123 

 

 

145 

 

(15%)

 

 

380 

 

 

463 

 

(18%)

(1)

Includes $3 million of restructuring charges for the nine months ended September 30, 2016.

Operating Income

·

Operating income from our Midstream Services segment decreased $6 million for the three months ended September 30, 2017, compared to the same period in 2016, primarily due to a $13 million decrease in gas gathering revenues and a $2 million decrease in marketing margin, partially offset by a $9 million decrease in operating costs and expenses.

•Operating income for our Marketing segment increased $2 million for the three months ended June 30, 2023, compared to the same period in 2022, primarily due to a $1 million increase in the marketing margin and $1 million decrease in operating costs and expenses (discussed below).

·

Operating income decreased $40 million for the nine months ended September 30, 2017, compared to the same period in 2016, primarily due to a $50 million decrease in gas gathering revenues and a $6 million decrease in marketing margin, partially offset by a $16 million decrease in operating costs and expenses.

•Operating income for our Marketing segment increased $9 million for the six months ended June 30, 2023, compared to the same period in 2022, primarily due to an $8 million increase in the marketing margin and $1 million decrease in operating costs and expenses (discussed below).

·

The margin generated from marketing activities was $11 million and $13 million for the three months ended September 30, 2017 and 2016, respectively, and $32 million and $38 million for the nine months ended September 30, 2017 and 2016, respectively.

•The margin generated from marketing activities was $18 million and $17 million for the three months ended June 30, 2023 and 2022, respectively, and $52 million and $44 million for the six months ended June 30, 2023 and 2022, respectively. The marketing margin increased for the three and six months ended June 30, 2023, compared to the same periods in 2022, primarily from utilizing existing transportation capacity to take advantage of low in-basin pricing on the purchase and sale of third-party natural gas.

Margins

Marketing margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for commodities, related cost of transportation and the ultimate disposition of those commodities. We enter into derivative contractsIncreases and decreases in revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in purchase expenses. Efforts to optimize the cost of our transportation can result in greater expenses and therefore lower marketing margins.
Revenues
•Revenues from timeour marketing activities decreased $2,792 million for the three months ended June 30, 2023, as compared to time with respectthe same period in 2022. The decrease was primarily due to a 69% decrease in the price received for volumes marketed and partially attributable to 3 Bcfe decrease in the volumes marketed for the three months ended June 30, 2023, compared to the same period in 2022.
•Revenues from our marketing activities decreased $3,506 million for the six months ended June 30, 2023, as compared to the same period in 2022. The decrease was primarily due to a 52% decrease in the price received for volumes marketed partially offset by a 10 Bcfe increase in the volumes marketed for the six months ended June 30, 2023, as compared to the same period in 2022.
42
Table of Contents
Operating Costs and Expenses
•Operating costs and expenses for the marketing segment decreased $1 million for the three and six months ended June 30, 2023, as compared to the same periods in 2022, as a result of lower personnel-related costs.
Consolidated
Interest Expense
For the three months ended June 30,Increase/(Decrease)For the six months ended June 30,Increase/(Decrease)
(in millions except percentages)2023202220232022
Gross interest expense:   
Senior notes$51 $60 (15)%$107 $118 (9)%
Credit arrangements9 13 (31)%16 23 (30)%
Amortization of debt costs3 4 (25)%6 7 (14)%
Total gross interest expense63 77 (18)%129 148 (13)%
Less: capitalization(29)(29)—%(59)(59)—%
Net interest expense$34 $48 (29)%$70 $89 (21)%
•Interest expense decreased for the three and six months ended June 30, 2023, compared to the same periods in 2022, due to lower revolver borrowings and the effects of our debt repurchase activity in 2022 and the full redemption of our 7.75% Senior Notes due 2027 during the first quarter of 2023.
•Capitalized interest remained flat for the three and six months ended June 30, 2023, as compared to the same periods in 2022.
•Capitalized interest as a percentage of gross interest expense increased for the three and six months ended June 30, 2023, compared to the same periods in 2022, primarily related to a smaller percentage change in our unevaluated natural gas marketing activitiesand oil properties balance as compared to provide margin protection.  For more information aboutthe larger percentage decrease in our derivatives and risk management activities, wegross interest expense over the same periods.
•We refer you to Item 3, "Quantitative and Qualitative Disclosures About Market Risks"Note 10 to the consolidated financial statements included in this Quarterly Report for additional information.

Revenues

·

Revenues from our marketing activities increased $65 million for the three months ended September 30, 2017, compared to the same period in 2016, primarily due to a 7% increase in the price received for volumes marketed and a 9 Bcfe increase in the volumes marketed. 

·

For the nine months ended September 30, 2017, revenues from our marketing activities increased $602 million, compared to the same period in 2016, as a 44% increase in the price received for volumes marketed more than offset a 32 Bcfe decrease in volumes marketed. 

·

Increases and decreases in marketing revenues due to changes in commodity prices are largely offset by corresponding changes in marketing purchase expenses. 

·

Of the total natural gas volumes marketed, production from our affiliated E&P operated wells accounted for 97% and 91% of the natural gas marketed volumes for the three months ended September 30, 2017 and 2016, respectively, and 96% and 94% of the natural gas marketed volumes for the nine months ended September 30, 2017 and 2016, respectively. 

32

Table of Contents

details about our debt and our financing activities.

·

Our Midstream Services segment marketed approximately 61% and 63% of our combined oil and NGL production for the three months ended September 30, 2017 and 2016, respectively, and 63% and 65% of our combined oil and NGL production for the nine months ended September 30, 2017 and 2016, respectively.  

·

Revenues from our gathering activities decreased $13 million and $50 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, primarily due to the decreased volumes in the Fayetteville Shale.

Operating Costs and Expenses

·

The decrease in operating costs and expenses for the three and nine months ended September 30, 2017 primarily resulted from reduced compression and personnel costs due to lower activity levels as a result of decreased volumes gathered in the Fayetteville Shale.

Restructuring Charges

In January 2016, we announced a 40% workforce reduction, which was substantially concluded by the end of March 2016. In April 2016, we also partially restructured executive management.  Affected employees were offered a severance package that included a one-time cash payment depending on length of service and, if applicable, accelerated vesting of outstanding stock-based equity awards.  As a result of the workforce reduction and executive management restructuring, we recognized restructuring charges of $2 million and $77 million for the three and nine months ended September 30, 2016, respectively.

Interest Expense



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



For the three months

 

 

 

For the nine months

 

 



ended September 30,

 

Increase/

 

ended September 30,

 

Increase/

(in millions except percentages)

2017

 

2016

 

(Decrease)

 

2017

 

2016

 

(Decrease)

Gross interest expense

$

60 

 

$

67 

 

(10%)

 

$

182 

 

$

180 

 

1%

Less: capitalization

 

(29)

 

 

(41)

 

(29%)

 

 

(85)

 

 

(123)

 

(31%)

Net interest expense

$

31 

 

$

26 

 

19%

 

$

97 

 

$

57 

 

70%

·

The decrease in gross interest expense for the three months ended September 30, 2017, as compared to the same period in 2016, was primarily due to a decrease in our outstanding debt.  The increase in gross interest expense for the nine months ended September 30, 2017, as compared to the same period in 2016, was primarily due to an increase in our cost of debt.

·

The decrease in capitalized interest for the three and nine months ended September 30, 2017, compared to the same periods in 2016, was primarily due to the evaluation of a portion of our Southwest Appalachia assets.

Gain (Loss) on Derivatives



 

 

 

 

 

 

 

 

 

 

 



For the three months

 

For the nine months



ended September 30,

 

ended September 30,

(in millions)

2017

 

2016

 

2017

 

2016

Gain (loss) on unsettled derivatives

$

31 

 

$

81 

 

$

350 

 

$

(48)

Gain (loss) on settled derivatives

 

17 

 

 

(10)

 

 

(52)

 

 

20 

Gain (loss) on derivatives (1)

$

48 

 

$

71 

 

$

298 

 

$

(28)
For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
Gain (loss) on unsettled derivatives$107 $718 $1,635 $(2,519)
Gain (loss) on settled derivatives210 (1,601)87 (2,296)
Non-performance risk adjustment— 4 (4)9 
Gain (loss) on derivatives$317 $(879)$1,718 $(4,806)

(1)

Excludes $3 million amortization of premiums paid related to certain call options for the three and nine months ended September 30, 2017, which is included in gain (loss) on derivatives on the condensed consolidated statement of operations.

We refer you to Note 67 to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional details about our gain (loss) on derivatives.

Gain/Loss on Early Extinguishment of Debt

·

In September 2017, we used the proceeds of approximately $1.1 billion from our September 2017 senior notes offering to repurchase approximately $758 million of our 2020 Senior Notes and to repay the remaining $327 million principal amount outstanding of our 2015 Term Loan.  We recognized a loss of $59 million for the redemption of these senior notes, which included $53 million of premiums paid.

During the six months ended June 30, 2023, we redeemed all of the outstanding 7.75% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs.

33

For the three months ended June 30, 2022, we recorded a loss on early debt extinguishment of $4 million as a result of our repurchase of $45 million in aggregate principal amount of our outstanding senior notes for $49 million. For the six months ended June 30, 2022, we recorded a loss on early debt extinguishment of $6 million as a result of the repurchase of $65 million in aggregate principal amount of our outstanding senior notes for $71 million. We also fully redeemed our 4.10% Senior Notes due March 2022 with an aggregate principal amount retired of $201 million.
See Note 10 to the consolidated financial statements of this Quarterly Report for more information on our long-term debt.
43

Table of Contents

·

In the first half of 2017, we redeemed the remaining $276 million principal amount outstanding of our 2018 Senior Notes, recognizing a loss of $11 million.

·

During the third quarter of 2016, we used proceeds from our $1,247 million July 2016 equity offering to purchase and retire $700 million of our outstanding senior notes due in the first quarter of 2018 and retire $375 million of our $750 million term loan entered into in November 2015.  We recognized a loss of $51 million for the redemption of these senior notes, which included $50 million of premiums paid.

Income Taxes

For the three months ended June 30,For the six months ended June 30,
(in millions except percentages)2023202220232022
Income tax (benefit) expense$(5)$26 $7 $30 
Effective tax rate(2)%2 %0 %(2)%



 

 

 

 

 

 

 

 

 

 

 



For the three months

 

For the nine months



ended September 30,

 

ended September 30,

(in millions except percentages)

2017

 

2016

 

2017

 

2016

Income tax expense (benefit)

$

(14)

 

$

(20)

 

$

(14)

 

$

(20)

Effective tax rate

 

(21%)

 

 

3% 

 

 

(2%)

 

 

1% 
Our effective tax rate was approximately (2)% and 0% for the three and six months ended June 30, 2023, respectively, primarily as a result of the release of the valuation allowances against our U.S. deferred tax assets. A valuation allowance for deferred tax assets, including NOLs, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, we used estimates and judgment regarding future taxable income and considered the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.

·

The income tax benefits recognized for the three and nine months ended September 30, 2017 and 2016 primarily resulted from an expected alternative minimum tax refund, along with the expiration of a portion of our uncertain tax provision. 

For the year ended December 31, 2022, the Company maintained a full valuation allowance against its deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2022, primarily due to impairments of proved oil and gas properties recognized in 2020. As of the first quarter of 2023, the Company has sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence such as forecasted income, the Company concluded that $523 million of its federal and state deferred tax assets were more likely than not to be realized and plan to release this portion of the valuation allowance in 2023. Accordingly, during the six months ended June 30, 2023, the Company recognized $504 million of deferred income tax expense related to recording its tax provision which was partially offset by $497 million of tax benefit attributable to the release of the valuation allowance. The remaining valuation allowance will be released during subsequent quarters during 2023. The Company expects to keep a valuation allowance of $66 million related to NOLs in jurisdictions in which it no longer operates and against the portion of our federal and state deferred tax assets such as capital losses and interest carryovers, which may expire before being fully utilized due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied.

·

Our low effective tax rate is the result of our recognition of a valuation allowance that reduced the deferred tax asset primarily related to our current net operating loss carryforward.  A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

Due to the issuance of common stock associated with the Indigo Merger, we incurred a cumulative ownership change and as such, our NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available. At June 30, 2023, we had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion have an expiration date between 2035 and 2037 and $1 billion have an indefinite carryforward life. We currently estimate that approximately $2 billion of these federal NOLs will expire before they are able to be used and accordingly, no value has been ascribed to these NOLs on our balance sheet. If a subsequent ownership change were to occur as a result of future transactions in our common stock, our use of remaining U.S. tax attributes may be further limited.

The Inflation Reduction Act of 2022 (the “IRA”) was enacted on August 16, 2022 and may impact how the U.S. taxes certain large corporations. The IRA imposes a 15% alternative minimum tax on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. This alternative minimum tax requires complex computations to be performed that were not previously required in U.S. tax law, significant judgments to be made in interpretation of the provisions of the IRA, significant estimates in calculations, and the preparation and analysis of information not previously relevant or regularly produced. The U.S. Treasury Department, the Internal Revenue Service, and other standard-setting bodies are expected to issue guidance on how the alternative minimum tax provisions of the IRA will be applied or otherwise administered that may differ from our interpretations. As we complete our analysis of the IRA, collect and prepare necessary data, and interpret any additional guidance, we may make adjustments to provisional amounts that we have recorded that may materially impact our provision for income taxes in the period in which adjustments are made. We do not expect to be impacted by the alternative minimum tax during 2023 and will continue to monitor updates to the IRA and the impact it will have on our consolidated financial statements.
New Accounting Standards Implemented in this Report

Refer to Note 1516 to the unaudited condensed consolidated financial statements of this Quarterly Report for a discussion of new accounting standards whichthat have been implemented.

44
Table of Contents
New Accounting Standards Not Yet Implemented in this Report

Refer to Note 1516 to the unaudited condensed consolidated financial statements of this Quarterly Report for a discussion of new accounting standards whichthat have not yet been implemented.

LIQUIDITY

LIQUIDITY AND CAPITALCAPITAL RESOURCES

We depend primarily on funds generated from our operations, our 2022 credit facility, our cash and cash equivalents balance and our $809 million revolving credit facilities andaccess to capital markets as our primary sources of liquidity. AlthoughOn April 8, 2022, we have financial flexibilityamended and restated our 2018 credit facility and extended the maturity through April 2027 (the “2022 credit facility”). In connection with entering into our cash balance2022 credit facility, the banks participating in our 2022 credit facility increased our borrowing base to $3.5 billion and agreed to provide five-year revolving commitments of $2.0 billion (the “Five-Year Tranche”) and agreed to updated terms that provide the ability to draw onconvert our revolvingsecured credit facilitiesfacility to an unsecured credit facility if we are able to achieve investment grade status, as necessary,deemed by the relevant credit rating agencies.
On April 5, 2023, our borrowing base was reaffirmed at $3.5 billion and our Five-Year Tranche was reaffirmed at $2.0 billion. At June 30, 2023, we continue to behad approximately $1.7 billion of total available liquidity, which exceeds our currently modeled needs as we remain committed to our capital discipline strategy of investing withincapital discipline.
Effective August 4, 2022, the Company elected to temporarily increase commitments under the 2022 credit facility by $500 million (the “Short-Term Tranche”) as a temporary working capital liquidity resource. The Company had no borrowings under the Short-Term Tranche which expired on April 30, 2023 and was not renewed.
Our flexibility to access incremental secured debt capital is derived from our excess asset collateral value above the elected $3.5 billion maximum revolving credit amount and borrowing base of our 2022 credit facility and the elected aggregate revolving commitments from our bank group. Our ability to issue secured debt is governed by the limitations of our 2022 credit facility as well as our secured debt capacity (as defined by our senior note indentures) which was $4.4 billion as of June 30, 2023, based on 25% of adjusted consolidated net tangible assets. If we were to realize a return to investment grade ratings and the subsequent conversion of our secured credit facility to an unsecured credit facility, we would expect to have access to additional liquidity capital beyond our elected aggregate revolving commitments, either by increasing commitments to the 2022 credit facility up to the $3.5 billion aggregate size or otherwise on a similarly unsecured basis, given our current asset collateral value and credit quality. We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2022 credit facility and related covenant requirements.
In June 2022, we announced a share repurchase program, under which we have been authorized to repurchase up to $1 billion of our outstanding common stock beginning June 21, 2022 and continuing through and including December 31, 2023. The timing, as well as the number and value of shares repurchased under the program, will be determined at our discretion and includes a variety of factors, including our progress in reducing debt to our target debt range, our free cash flow from operations, supplemented in 2017 bygeneration capabilities, our assessment of the remaining funds fromintrinsic value of our common stock, the July 2016 equity issuancemarket price of our common stock, general market and economic conditions, available liquidity, compliance with our debt and other agreements, and applicable legal requirements among other considerations. The exact number of shares to be repurchased is not guaranteed, and the September 2016 asset saleprogram may be suspended, modified, or discontinued at any time without prior notice. During 2022, we repurchased approximately 17.3 million shares of our outstanding common stock at an average price of $7.24 per share for a total cost of approximately $125 million. We did not repurchase any shares during the six months ended June 30, 2023.
Looking forward, we intend to prioritize the use of any free cash flow to pay down our debt in West Virginia.

order to progress toward our debt and leverage targets.

Our cash flow from operating activities is highly dependent upon our ability to sell and the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See “Risk Factors” in Item 1A of our 2022 Annual Report for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity hedging activities.  See “Quantitative and Qualitative Disclosures about Market Risks” in Item 3 and Note 6 to the unaudited condensed consolidated financial statements included in this Quarterly Report for further details. 

derivative program. Our derivative contracts allow us to ensuresupport a certain level of cash flow to fund our operations. At September 30, 2017,Although we had NYMEX price derivatives in place on 138 Bcfare continually assessing adding derivative positions for portions of our remaining targeted 2017 natural gasexpected 2023, 2024, 2025 and 2026 production, and 473 Bcf and 108 Bcf on our targeted 2018 and 2019 natural gas production, respectively.  We also had commodity derivatives in place on 46 MBblsthere can be no assurance that we will be able to add derivative positions to cover the remainder of our remaining targeted 2017 ethaneexpected production and 183 MBblsat favorable prices. We again refer you to “Risk Factors” in Item 1A of our targeted 2018 ethane production.

2022 Annual Report.

Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact
45
Table of Contents
our cash flow from operating activities.

34

Table Additionally, we do not expect the events of Contents

early 2023 within the banking industry to have a material impact on our expected results of operations, financial performance, or liquidity. However, if there are issues in the wider financial system and if other financial institutions fail, our business, liquidity and financial condition could be materially affected, including as a result of impacts of any such issues or failures on our counterparties.

Our short-term cash flows are also dependent on the timely collection of receivables from our customers, hedging counterparties and joint interest partners.owners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers, hedging counterparties and joint interest partnersowners could adversely impact our cash flows.

Due to these above factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from time to time seek to retire, rearrange or amend some or all of our outstanding debt preferred stock or debt agreements through cash purchases, and/or exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Credit Arrangements and Financing Activities

We have taken substantial steps

In April 2022, we entered into an amended and restated credit agreement that replaced the 2018 credit facility (the “2022 credit facility”) with a group of banks that, as amended, has a maturity date of April 2027. As of June 30, 2023, the 2022 credit facility had an aggregate maximum revolving credit amount and borrowing base of $3.5 billion and elected commitments of $2.0 billion.
The borrowing base is subject to redetermination at least twice a year, which typically occurs in managingApril and October, and is subject to change based primarily on drilling results, commodity prices, our debt maturitiesfuture derivative position, the level of capital investment and liquidityoperating costs. The 2022 credit facility is secured by substantially all of our assets and our subsidiaries’ assets (taken as a whole). The permitted lien provisions in 2017.  These steps, discussed in further detail below, had the effectsenior note indentures currently limit liens securing indebtedness to the greater of extending maturities on total debt outstanding by reducing the amount$2.0 billion or 25% of debt,adjusted consolidated net of cash and cash equivalents, coming due in 2020 from $1,257 milliontangible assets, which was $4.4 billion as of June 30, 2017 to $294 million as of September 30, 2017.

·

In September 2017, we completed a public offering of $650 million aggregate principal amount of our 7.50% senior notes due 2026 and $500 million aggregate principal amount of our 7.75% senior notes due 2027, with net proceeds from the offering totaling approximately $1.1 billion after underwriting discounts and offering expenses. 

·

The proceeds from the September 2017 offering were used to repurchase $758 million of our 4.05% Senior Notes due 2020 and to repay the remaining $327 million principal amount outstanding of our 2015 Term Loan.

·

Also in September 2017, we entered into Amendment No. 1 to our credit agreement covering the $1,191 million secured term loan and the $743 million unsecured revolving facility entered into in June 2016.  This amendment provides greater flexibility to our minimum liquidity covenant and allows us to retain the first $500 million of net cash proceeds from asset sales that would have otherwise been required to be used for further debt reduction.

·

During the first half of 2017, we redeemed the remaining $276 million principal amount outstanding of our 2018 Senior Notes.

Our 2016 revolving2023. The 2022 credit facility contains the ability to utilize SOFR index rates for purposes of calculating interest expense.

The 2022 credit facility has certain financial covenant requirements but provides borrowing capacitycertain fall away features should we receive an Investment Grade Rating (defined as an index debt rating of $743 millionBBB- or higher with S&P, Baa3 or higher with Moody’s, or BBB- or higher with Fitch) and maturesmeet other criteria in December 2020.  The maturity date will acceleratethe future. We refer you to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 millionNote 10 to the consolidated financial statements included in this Quarterly Report for additional discussion of our senior notes due in January 2020.  2022 credit facility.
As of SeptemberJune 30, 2017, we have repurchased approximately $758 million of our 4.05% Senior Notes due 2020.  Our 2013 revolving credit facility provides borrowing capacity of $66 million and matures in December 2018.  As of September 30, 2017, there were no borrowings under either revolving credit facility; however, there was $323 million in letters of credit outstanding against the 2016 revolving credit facility.

As of September 30, 2017,2023, we were in compliance with all of the applicable covenants ofcontained in the term loans and revolving credit facilities.  Although we do not anticipate any violations of the financial covenants,agreement governing our 2022 credit facility. Our ability to comply with thesefinancial covenants is dependent uponin future periods depends, among other things, on the success of our exploration and development program and upon other factors beyond our control, such as the market demand and prices for natural gas, oil and liquids.NGLs. We refer you to Note 910 of the unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of the covenant requirements of our term loans and revolving2022 credit facilities.

At October 24, 2017,facility.

As of June 30, 2023, we had $310 million of borrowings on our 2022 credit facility and $25 million in outstanding letters of credit. We currently do not anticipate being required to supply a long-term issuermaterially greater amount of letters of credit rating of Ba3 by Moody’s, a long-term debt rating of BB- by S&P and a long-term issuer default rating of BB by Fitch Ratings.  Any downgrades in our public debt ratings by Moody’s or S&P could increase our cost of funds and decrease our liquidity under our revolvingexisting contracts. We refer you to Note 10 to the consolidated financial statements included in this Quarterly Report for additional discussion of our 2022 credit facilities.

facility.

The credit status of the financial institutions participating in our revolving2022 credit facilitiesfacility could adversely impact our ability to borrow funds under the revolving2022 credit facilities.facility. Although we believe all of the lenders under the facilitiesfacility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 910 of to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of our revolving credit facilities.

facility.

35

Other key financing activities for the six months ended June 30, 2023 and June 30, 2022 are as follows:
Debt Repurchases
•On February 26, 2023, we redeemed all of the outstanding 7.750% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs. We funded the redemption using approximately $316 million of cash on hand and approximately $134 million of borrowings under our 2022 credit facility.
46

Table of Contents

•In January 2022, we repurchased the remaining outstanding principal balance of $201 million on our 2022 senior notes using our credit facility. As a result of the focused work on refinancing and repayment of our debt in recent years, coupled with the amendment and restatement of our credit facility on April 8, 2022, none of our outstanding debt balance is scheduled to become due prior to 2025.
•In March 2022, we repurchased $5 million of our 8.375% Senior Notes due 2028 and $15 million of our 7.75% Senior Notes due 2027, resulting in a $2 million loss on debt extinguishment.
•In April 2022, we repurchased $4 million of our 7.75% Senior Notes due 2027 and $23 million of our 8.375% Senior Notes due 2028, resulting in a $3 million loss on debt extinguishment.
•In May 2022, we repurchased $18 million of our 8.375% Senior Notes due 2028, resulting in a $1 million loss on debt extinguishment.
As of August 1, 2023, we had long-term debt issuer ratings of Ba1 by Moody’s (rating and stable outlook affirmed on June 28, 2023), BB+ by S&P (rating upgraded to BB+ and outlook upgraded to positive on January 18, 2023) and BB+ by Fitch Ratings (rating upgraded to BB+ with positive outlook on August 10, 2022). Effective in January 2022, the interest rate for our 4.95% senior notes due January 2025 (“2025 Notes”) was 5.95%, reflecting a net downgrade in our bond ratings since their issuance. On May 31, 2022, Moody’s upgraded our bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively, as our 2025 Notes are subject to ratings driven changes.
Cash Flows

 

 

 

 

 

For the nine months

ended September 30,

For the six months ended June 30,

(in millions)

2017

 

2016

(in millions)20232022

Net cash provided by operating activities

$

789 

 

$

337 Net cash provided by operating activities$1,562 $1,399 

Net cash provided by (used in) investing activities

 

(921)

 

 

43 

Net cash provided by (used in) financing activities

 

(302)

 

 

1,079 
Net cash used in investing activitiesNet cash used in investing activities(1,163)(1,049)
Net cash used in financing activitiesNet cash used in financing activities(424)(328)

Cash Flow from Operations

·

Net cash provided by operating activities increased 134% or $452 million for the nine months ended September 30, 2017, compared to the same period in 2016, primarily due to an increase in revenues resulting from improved realized commodity prices partially offset by lower production volumes and a reduction in realized derivative results.

For the six months ended June 30,
(in millions)20232022
Net cash provided by operating activities$1,562 $1,399 
Add back (subtract) changes in working capital(345)189 
Net cash provided by operating activities, net of changes in working capital$1,217 $1,588 

·

Net cash generated from operating activities provided 83% of our cash requirements for capital investments for the nine months ended September 30, 2017, compared to net cash from operating activities providing 89% of our cash requirements for capital investments for the same period in 2016, reflecting our commitment to our capital discipline strategy of investing within our cash flow from operations, supplemented by the 2016 equity issuance and asset sales.

•Net cash provided by operating activities increased 12%, or $163 million, for the six months ended June 30, 2023, compared to the same period in 2022, primarily due to a $2,383 million improvement in our settled derivative positions, a $534 million increase in working capital, a $23 million reduction in our tax provision, a $19 million decrease in interest expense, and an $8 million increase in our marketing margin partially offset by a $2,661 million decrease resulting from lower commodity prices, a $132 million decrease related to decreased production, and a $15 million increase in operating costs and expenses.

•Net cash provided by operating activities, net of changes in working capital, provided 97% of our cash requirements for capital investments for the six months ended June 30, 2023 and exceeded our cash requirements for capital investments for the six months ended June 30, 2022. While we front-loaded our capital program into the earlier quarters of the year, we remain committed to our capital discipline strategy of investing within our cash flow from operations, net of changes in working capital.
Cash Flow from Investing Activities



 



For the nine months



ended September 30,

(in millions)

2017

 

2016

Cash Flows from Investing Activities

 

 

 

 

 

Additions to properties and equipment

$

943 

 

$

391 

Adjustments for capital investments

 

 

 

 

 

Changes in capital accruals

 

(13)

 

 

(24)

Other non-cash adjustments to properties and equipment

 

16 

 

 

9 

Total capital investing

$

946 

 

$

376 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



For the three months

 

 

 

For the nine months

 

 



ended September 30,

 

Increase/

 

ended September 30,

 

Increase/

(in millions except percentages)

2017

 

2016

 

(Decrease)

 

2017

 

2016

 

(Decrease)

E&P capital investing (1)

 

320 

 

 

179 

 

 

 

 

921 

 

 

372 

 

 

Midstream capital investing

 

9 

 

 

1 

 

 

 

 

21 

 

 

3 

 

 

Other capital investing

 

2 

 

 

–  

 

 

 

 

4 

 

 

1 

 

 

Total capital investing

$

331 

 

$

180 

 

84%

 

$

946 

 

$

376 

 

152%

(1)

Includes $54 million and $62 million of capitalized interest and internal costs for the three months ended September 30, 2017 and 2016, respectively, and $159 million and $183 million of capitalized interest and internal costs for the nine months ended September 30, 2017 and 2016, respectively.  These internal costs were directly related to acquisition, exploration and development activities and are included as part of the cost of natural gas and oil properties.

•Total E&P capital investments increased $128 million for the six months ended June 30, 2023, compared to the same period in 2022, primarily attributable to higher costs due to inflation.

·

Total E&P capital investing increased $141 million for the three months ended September 30, 2017, compared to the same period in 2016, as a $149 million increase in direct E&P capital investing was only partially offset by an $8 million decrease in capitalized interest and internal costs.

47

·

Total E&P capital investing increased $549 million for the nine months ended September 30, 2017, compared to the same period in 2016, as a $573 million increase in direct E&P capital investing was only partially offset by a $24 million decrease in capitalized interest and internal costs.  We suspended drilling activity in the first half of 2016 due to an unfavorable commodity price environment.

·

The increase in E&P capital investments for the three and nine months ended September 30, 2017, as compared to the same periods in 2016, reflects our operational flexibility in light of current and expected economic conditions as we adjusted our activities based on our anticipated cash flows from operation.

·

The decrease in capitalized interest for the three and nine months ended September 30, 2017, compared to the same periods in 2016, was primarily due to the evaluation of a portion of our Southwest Appalachia assets acquired in December 2014.

36

Table of Contents

·

Midstream capital investing increases of $8 million and $18 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, related primarily to the purchase of several of our leased compressors during 2017 which were subsequently sold to third parties for a year-to-date net gain of $3 million.

For the six months ended June 30,
(in millions)20232022
Additions to properties and equipment$1,286 $1,050 
Adjustments for capital investments
Changes in capital accruals(28)77 
Other (1)
2 2 
Total capital investing$1,260 $1,129 
(1)Includes capitalized non-cash stock-based compensation and costs to retire assets, which are classified as cash used in operating activities.
Capital Investing
For the three months ended June 30,Increase/(Decrease)For the six months ended June 30,Increase/(Decrease)
(in millions except percentages)2023202220232022
E&P capital investing$593 $585 1%$1,257 $1,129 11%
Other capital investing (1)
2 — 100%3 — 100%
Total capital investing$595 $585 2%$1,260 $1,129 12%
(1)Other capital investing relates to information technology purchases for the three and six months ended June 30, 2023.
For the three months ended June 30,For the six months ended June 30,
(in millions)2023202220232022
E&P Capital Investments by Type:  
Development and exploration, including workovers$513 $515 $1,097 $975 
Acquisition of properties21 18 45 44 
Other11 5 16 9 
Capitalized interest and expenses48 47 99 101 
Total E&P capital investments$593 $585 $1,257 $1,129 
  
E&P Capital Investments by Area:  
Appalachia$275 $244 $551 $479 
Haynesville312 335 693 641 
Other E&P6 6 13 9 
Total E&P capital investments$593 $585 $1,257 $1,129 
For the three months ended June 30,For the six months ended June 30,
2023202220232022
Gross Operated Well Count Summary:  
Drilled38 41 69 74 
Completed46 35 82 72 
Wells to sales50 42 86 74 
Actual capital expenditure levels may vary significantly from period to period due to many factors, including drilling results, natural gas, oil and NGL prices, industry conditions, the prices and availability of goods and services, and the extent to which properties are acquired or non-strategic assets are sold.

Cash Flow from FinanFinancing Activities
•On February 26, 2023, we redeemed all of the outstanding 7.750% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs. We funded the redemption using approximately $316 million of cash on hand and approximately $134 million of borrowings under our 2022 credit facility.
•For the six months ended June 30, 2022, we fully redeemed our 4.10% Senior Notes due 2022 for $201 million and paid down additional aggregate principal balances on our senior notes of $65 million in principal and $6 million in premiums, paid down $3 million of our Term Loan B due 2027 and paid down $54 million on our 2022 credit facility.
48
Table of Contentscing Activities



 

 

 

 

 

 

 

 



September 30,

 

December 31,

 

Increase/

(in millions except percentages)

2017

 

2016

 

(Decrease)

Short-term debt

$

40 

 

$

41 

 

$

(1)

Long-term debt

 

4,396 

 

 

4,612 

 

 

(216)

Total debt

$

4,436 

 

$

4,653 

 

$

(217)

Equity

$

1,652 

 

$

917 

 

$

735 

Total debt to capitalization ratio 

 

73% 

 

 

84% 

 

 

(11%)



 

 

 

 

 

 

 

 

Total debt

$

4,436 

 

$

4,653 

 

$

(217)

Less: Cash and cash equivalents

 

989 

 

 

1,423 

 

 

(434)

Debt, net of cash and cash equivalents (1)

$

3,447 

 

$

3,230 

 

$

217 

(1)

Debt, net of cash and cash equivalents is a non-GAAP financial measure of a company’s ability to repay its debts if they were all due today.

•For the six months ended June 30, 2022, we repurchased approximately 2.8 million shares of our outstanding common stock pursuant to our previously announced share repurchase program at an average of $7.10 per share for a total cost of approximately $20 million.

·

Net cash used in financing activities for the nine months ended September 30, 2017 was $302 million, compared to net cash provided by financing activities of $1,079 million for the same period in 2016.

·

In September 2017, we completed a public offering of $650 million aggregate principal amount of our 7.50% senior notes due 2026 and $500 million aggregate principal amount of our 7.75% senior notes due 2027, with net proceeds from the offering totaling approximately $1.1 billion, after approximately $17 million in offering expenses.    

·

The proceeds from the September 2017 offering were used to repay $758 million of our 4.05% Senior Notes due 2020 and the remaining $327 million principal amount outstanding of our 2015 Term Loan.  We recognized a loss on early extinguishment of debt of $59 million.

·

In the first half of 2017, we redeemed $276 million principal amount outstanding of our 2018 Senior Notes.  We recognized a loss on early extinguishment of debt of $11 million.

·

The net cash provided by financing activities in 2016 resulted primarily from our fully-drawn 2016 Term Loan.

We refer you to Note 910 of the unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of our outstanding debt and credit facilities.

Working Capital

·

We had positive working capital of $692 million at September 30, 2017 and positive working capital of $808 million at December 31, 2016. 

We had negative working capital of $790 million at June 30, 2023, a $1,027 million increase from December 31, 2022, primarily attributable to a $1,325 million increase in the current mark-to-market value of our derivatives position related to commodity pricing declines, a decrease in our accounts payable of $454 million, a decrease in other current liabilities of $43 million, a decrease in taxes payable of $20 million, and a decrease of interest payables of $9 million, which was partially offset by a decrease in accounts receivable of $803 million, and a decrease in cash and cash equivalents of $25 million as compared to December 31, 2022. We believe that our existing cash and cash equivalents, our anticipated cash flows from operations and our available 2022 credit facility will be sufficient to meet our working capital and operational spending requirements.

·

The positive working capital as of September 30, 2017 and December 31, 2016 was primarily due to $1.0 billion and $1.4 billion of cash and cash equivalents, respectively.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of SeptemberJune 30, 2017,2023, our material off-balance sheet arrangements and transactions include operating leaseservice arrangements and $323$25 million in letters of credit outstanding underagainst our 2016 revolving2022 credit facility. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” in our 2016 Annual Report on Form 10-K.  

below for more information.

37

Table of Contents

Contractual Obligations and Contingent Liabilities and Commitments

We have various contractual obligations in the normal course of our operations and financing activities. Other than the firm transportation and gathering agreements discussed below, there have been no material changes to our contractual obligations from those disclosed in our 20162022 Annual Report.

Contingent Liabilities and Commitments

As of SeptemberJune 30, 2017, our contractual obligations2023, we had commitments for demand and similar charges under firm transporttransportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaledtotaling approximately $8.9$9.8 billion, $3.7$1.4 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and/or additional construction efforts. This amount also included guarantee obligations of up to $832$839 million. As of SeptemberJune 30, 2017,2023, future payments under non-cancelable firm transportation and gathering agreements are as follows:



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Payments Due by Period



Total

 

Less than 1 Year

 

1 to 3 Years

 

3 to 5 Years

 

5 to 8 Years

 

More than 8 Years



 

(in millions)

Infrastructure Currently in Service

$

5,136 

 

$

196 

 

$

1,105 

 

$

524 

 

$

1,492 

 

$

1,819 

Pending Regulatory Approval and/or Construction (1)

 

3,722 

 

 

432 

 

 

458 

 

 

702 

 

 

114 

 

 

2,016 

  Total Transportation Charges

$

8,858 

 

$

628 

 

$

1,563 

 

$

1,226 

 

$

1,606 

 

$

3,835 
Payments Due by Period
(in millions)TotalLess than 1 Year1 to 3 Years3 to 5 Years5 to 8 yearsMore than 8 Years
Infrastructure currently in service$8,441 $970 $1,888 $1,696 $1,798 $2,089 
Pending regulatory approval and/or construction (1)
1,363 61 242 276 362 422 
Total transportation charges$9,804 $1,031 $2,130 $1,972 $2,160 $2,511 

(1)Based on the estimated in-service dates as of SeptemberJune 30, 2017.

Substantially2023.

Prior to January 1, 2021, substantially all of our employees arewere covered by the defined benefit pension plan, a cash balance plan that provided benefits based upon a fixed percentage of an employee’s annual compensation (the “Plan”). As part of an ongoing effort to reduce costs, we elected to freeze the Plan effective January 1, 2021. Employees that were participants in the Plan prior to January 1, 2021 continued to receive the interest component of the Plan but no longer received the service component. On September 13, 2021, the Compensation Committee of the Board approved terminating the Plan, effective December 31, 2021. This decision, among other benefits, will provide Plan participants quicker access to, and postretirementgreater flexibility in, the management of participants’ respective benefits due under the Plan.
We have commenced the Plan termination process, and, on April 6, 2022, the Internal Revenue Service issued a favorable determination letter, concurring that the Plan met all of the qualification requirements under the Internal Revenue Code. In December 2022, we distributed approximately $38 million of the Plan’s assets to participants in the form of lump sum payments in connection with a limited distribution window provided to all active and former employee participants as part of the Plan termination process.
49
Table of Contents
In March 2023, we entered into a group annuity contract with a qualified insurance company relating to the Plan. Under the group annuity contract, we purchased an irrevocable nonparticipating single premium group annuity contract from the insurer and transferred to the insurer the future benefit plans.  Forobligations and annuity administration for certain retirees and beneficiaries under the nine months ended September 30, 2017,Plan.
Upon issuance of the group annuity contract, the pension benefit obligations and annuity administration for the remaining participants was irrevocably transferred from the Plan to the insurer. By transferring these obligations through the payment to the insurer in March 2023, we have contributed $11no remaining obligations under the Plan or any other U.S. tax-qualified defined benefit pension plan. The purchase of the group annuity contract was funded directly by the assets of the Plan. We recognized a pre-tax non-cash pension settlement charge of approximately $2 million to the pension and postretirement benefit plans.  We expect to contribute an additional $3 million to our pension and postretirement benefit plans during the remainderfirst half of 2017.  As of September 30, 2017 and December 31, 2016, we recognized liabilities of $46 million and $49 million, respectively,2023 as a result of the underfunded statussettlement of the Plan.
For the six months ended June 30, 2023, we have not made contributions to the pension plan or postretirement benefit plans, and we do not expect to contribute additional funds to our pension plan during the remainder of 2023. We recognized assets of approximately $13 million and $15 million related to our pension plan benefits and liabilities of approximately $10 million and $9 million related to our other postretirement benefit plans.benefits as of June 30, 2023 and December 31, 2022, respectively. See Note 1113 to the unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion about our pension and other postretirement benefits.

We are subject to various litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic incidents, and pollution, contamination, encroachment on others’ property or nuisance. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. Management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows, although it is possible that adverse outcomes could have a material adverse effect on our results of operations or cash flows for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future.  For further information, we refer you to “Litigation” and “Environmental Risk” in Note 10 to the unaudited condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

We are also subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position, or results of operations.  

operations or cash flows.

38

For further information, we refer you to “Litigation” and “Environmental Risk” in Note 11 to the consolidated financial statements included in Item 1 of Part I of this Quarterly Report.
Supplemental Guarantor Financial Information
As discussed in Note 10, in April 2022 the Company entered into the 2022 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that becomes a guarantor of the 2022 credit facility is also required to become a guarantor of each of our senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2022 credit facility, but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of our operating units are accounted for on a consolidated basis do not guarantee the 2022 credit facility and senior notes.
The Company and the Guarantor Subsidiaries jointly and severally, and fully and unconditionally, guarantee the payment of the principal and premium, if any, and interest on the senior notes when due, whether at stated maturity of the senior notes, by acceleration, by call for redemption or otherwise, together with interest on the overdue principal, if any, and interest on any overdue interest, to the extent lawful, and all other obligations of the Company to the holders of the senior notes.
SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantor Subsidiaries are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company. The Parent and Guarantor Subsidiaries comprise the material operations of the Company. Therefore, the Company concluded that the presentation of the Summarized Financial Information is not required as the Summarized Financial Information of the Company’s Guarantors is not materially different from our consolidated financial statements.
50

Table of Contents

Critical Accounting Policies and Estimates
There have been no material changes to our critical accounting policies and estimates as compared to the critical accounting policies and estimates described in our 2022 Annual Report.
ITEM 3. QUANTITATIVEQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

RISK

Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as service costs and credit risk concentrations. We use fixed price swap agreements, fixed priceswaps, two-way costless collars, three-way costless collars, options (calls and puts), basis swaps, index swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas, oil and certain NGLs along with interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate riskrisks is also overseen by our Board of Directors.Board. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.

Credit Risk

Our financial instruments that are exposedexposure to concentrations of credit risk consistconsists primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our physical commodity purchasers and their dispersion across geographic areas. No singleFor the six months ended June 30, 2023, one purchaser accounted for greater14% of our revenues. For the year ended December 31, 2022, one purchaser accounted for 17% of our revenues. No other individual purchasers accounted for more than 10% of our revenues forin either of these respective periods. A default on this account could have a material impact on the nine months ended September 30, 2017.Company. See “Commodities“Commodities Risk” below for discussion of credit risk associated with commodities trading.

Interest Rate Risk

As of SeptemberJune 30, 2017,2023, we had approximately $3.3 billion$3,743 million of outstanding senior notes with a weighted average interest rate of 6.21%5.46%, and $1.2 billion$310 million of term loanborrowings under our 2022 credit facility. As of June 30, 2023, we had long-term debt with a variableissuer ratings of BB+ by S&P, Ba1 by Moody’s and BB+ by Fitch Ratings. On September 1, 2021 S&P upgraded our bond rating to BB, and on January 6, 2022, S&P further upgraded our bond rating to BB+, which decreased the interest rate of 3.70%.  We currently have anon the 2025 notes to 5.95%, beginning with coupon payments paid after January 2022. On May 31, 2022, Moody’s upgraded the Company’s bond rating to Ba1, which decreased the interest rate swapon the 2025 Notes from 5.95% to 5.70% with coupon payments paid after July 2022. Any further upgrades or downgrades in effectour public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively, as our 2025 Notes are subject to mitigate a portion of our exposure to volatility in interest rates.

ratings driven changes.



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 



Expected Maturity Date

 



 

2017

 

 

 

2018

 

 

 

2019

 

 

 

2020

 

 

 

2021

 

 

 

Thereafter

 

 

 

Total

 

Fixed Rate Payments (1)

$

40 

 

 

$

–  

 

 

$

–  

 

 

$

92 

 

 

$

 –  

 

 

$

3,150 

 

 

$

3,282 

 

Weighted Average Interest Rate

 

7.21 

%

 

 

–  

%

 

 

–  

%

 

 

5.80 

%

 

 

–  

%

 

 

6.21 

%

 

 

6.21 

%



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable Rate Payments (1)

 

–  

 

 

 

 –  

 

 

 

 –  

 

 

 

1,191 

(2)

 

 

 –  

 

 

 

–  

 

 

 

1,191 

 

Weighted Average Interest Rate

 

–  

%

 

 

–  

%

 

 

–  

%

 

 

3.70 

%

 

 

–  

%

 

 

–  

%

 

 

3.70 

%

Expected Maturity Date
($ in millions except percentages)20232024202520262027ThereafterTotal
Fixed rate payments (1)
$— $— $389 $— $— $3,354 $3,743 
Weighted average interest rate— %— %5.70 %— %— %5.43 %5.46 %
Variable rate payments (1)
$— $— $— $— $310 $— $310 
Weighted average interest rate— %— %— %— %6.90 %— %6.90 %

(1)Excludes unamortized debt issuance costs and debt discounts.

(2)     The maturity date will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of our 2020 Senior Notes.  As of September 30, 2017, we have redeemed $758 million principal amount of our 2020 Senior Notes.

Commoditiesdiscounts.

Commodities Risk

We use over-the-counter fixed price swap agreements and options to protect sales of our production against the inherent risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market.  These swaps and options include transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps) and transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps).  For additional information on our derivatives and risk management, see Note 6 in the unaudited condensed consolidated financial statements included in this Quarterly Report.

The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas.our production.  However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gasproduction that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure.  Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable.  We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have
51
Table of Contents
currently.  However, we cannot be certain that we will not experience such losses in the future.

39

Table The fair value of Contentsour derivative assets and liabilities includes a non-performance risk factor. We refer you to Note 7

and Note 9of the consolidated financial statements included in this Quarterly Report for additional details about our derivative instruments and their fair value.

Item

ITEM 4. Controls and Procedures.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act.Act as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of SeptemberJune 30, 20172023 at a reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended SeptemberJune 30, 20172023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS. 

PROCEEDINGS

Refer to “Litigation”“Litigation” and “Environmental“Environmental Risk” in Note 1011 to the unaudited condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report for a discussion of the Company’s legal proceedings.

ITEM 1A. RISK FACTORS. 

FACTORS

There were no additions or material changes to our risk factors as disclosed in Item 1A of Part I in the Company’s 20162022 Annual Report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

PROCEEDS

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

SECURITIES

Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES.

Our sand mining operations in supportDISCLOSURES

Not applicable.
ITEM 5. OTHER INFORMATION
Securities Trading Plans of our E&P business are subject to regulation byDirectors and Executive Officers
During the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violationsthree months ended June 30, 2023, no director or other regulatory matters required by Section 1503(a)officer of the Dodd-Frank Wall Street Reform and Consumer Protection Act andCompany adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 104408(a) of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Quarterly Report.

ITEM 5. OTHER INFORMATION.

Not applicable.

under the Exchange Act.

40

52

Table of Contents

ITEM 6. EXHIBITS.

EXHIBITS

(10.1)*

(2.1)

SeparationAgreement and Release AgreementPlan of Merger, dated August 23, 2017 between12, 2020, by and among Southwestern Energy Company and Mark K. BolingMontage Resources Corporation (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K/A filed on August 12, 2020).

(10.2)*

(2.2)

Amendment to Awards Agreement and Plan of Merger, dated August 23, 2017 betweenJune 1, 2021, by and among Southwestern Energy Company, Ikon Acquisition Company, LLC, Indigo Natural Resources LLC, and Mark K. BolingIbis Unitholder Representative, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed on June 2, 2021).

(2.3)

Agreement and Plan of Merger, dated November 3, 2021, by and among Southwestern Energy Company, Mustang Acquisition Company, LLC, GEP Haynesville, LLC, and GEPH Unitholder Rep, LLC solely in its capacity as the Unitholder Representative (Incorporated by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K filed on November 5, 2021).
(3.1)
Amended and Restated Certificate of Incorporation of Southwestern Energy Company (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010).
(3.2)
Certificate of Amendment of the Amended and Restated Certificate of Incorporation, dated September 1, 2021 (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed September 1, 2021).
(3.3)
Certificate of Amendment No. 2 of the Amended and Restated Certificate of Incorporation, dated May 18, 2023(Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 22, 2023).
(3.4)
Amended and Restated Bylaws of Southwestern Energy Company, as amended through March 21, 2023 (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on March 22, 2023).
(10.1)*
Southwestern Energy Company 2022 Incentive Plan Form of Restricted Stock Unit Award Agreementfor Directors, for awards granted on or after May 18, 2023.
(10.2)*
Southwestern Energy Company 2022 Incentive Plan Form of Restricted Stock Award Agreement for Directors, for awards granted on or after May 18, 2023.
(31.1)*

Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 20022002.

(31.2)*

Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 20022002.

(32.1)*

*

Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 20022002.

(32.2)*

*

Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 20022002.

(95.1)*

(101.INS)

Mine Safety Disclosure

(101.INS)

Inline Interactive Data File Instance Document

(101.SCH)

Inline Interactive Data File Schema Document

(101.CAL)

Inline Interactive Data File Calculation Linkbase Document

(101.LAB)

Inline Interactive Data File Label Linkbase Document

(101.PRE)

Inline Interactive Data File Presentation Linkbase Document

(101.DEF)

Inline Interactive Data File Definition Linkbase Document

(104.1)Cover Page Interactive Data File – the cover page from this Quarterly Report on Form 10-Q, formatted in inline XBRL (included within the Exhibit 101 attachments)

*Filed herewith

** Furnished herewith
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.

SOUTHWESTERN ENERGY COMPANY

Registrant

Dated:

October 26, 2017

/s/ JENNIFER STEWART

Dated:

August 3, 2023

Jennifer Stewart

/s/ CARL F. GIESLER, JR.

SeniorCarl F. Giesler, Jr.
Executive Vice President and


Chief Financial Officer – Interim

41

53