ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. In many cases you can identify forward-looking statements 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,” “target” or similar words. Unless required to do so under the federal securities laws, the Company does not undertake to update, revise or correct any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements.”
OVERVIEW
Background
Southwestern Energy Company (including its subsidiaries, collectively, “we,” “our,” “us,” “the Company” or “Southwestern”) is an independent energy company engaged in natural gas, oil and NGLs exploration, development and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our marketing business, which we call “Marketing” but previously referred to as “Midstream” when it included the operations of gathering systems. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States. Our historical financial and operating results include the Fayetteville Shale E&P and related midstream gathering businesses which were sold in early December 2018.
E&P. Our primary business is the exploration for and production of natural gas, oil and NGLs, with our ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania and West Virginia. Our operations in northeast Pennsylvania, 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,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, our properties in Pennsylvania and West Virginia are herein referred to as “Appalachia.” We also have drilling rigs located in Pennsylvania and West Virginia, and we provide certain oilfield products and services, principally serving our E&P operations though vertical integration.
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. In December 2018, we divested almost all of our midstream gathering assets as part of the Fayetteville Shale sale.
Focus in 2019. In 2019, we continued our strategy to reposition the Company through portfolio optimization, balance sheet management and leveraging our technical, commercial and operational expertise to improve margins. We continued our strategic shift towards prioritizing the development of our high-value, liquids-rich Southwest Appalachia assets over our pure natural gas assets. We strengthened our balance sheet through an additional debt reduction of $80 million (net) and by amending our revolving credit facility to extend the maturity into 2024, which improved our debt maturity profile while preserving financial and operational flexibility. We made further technological advances in drilling longer laterals with increased precision and completion optimization that enhanced well productivity and significantly reduced our well costs on a per lateral foot basis, resulting in improved returns. In addition, we focused on identifying and implementing opportunities to lower our overall cost structure. We added to our derivative portfolio, limiting the impact of price volatility on approximately 604 Bcfe and 307 Bcfe of our forecasted 2020 and 2021 production, respectively, through the use of commodity derivatives.
Recent Financial and Operating Results
Significant operating and financial highlights for 2019 include:
Total Company
•Net income attributable to common stock of $891 million, or $1.65 per diluted share, up from a net income attributable to common stock of $535 million, or $0.93 per diluted share, in 2018. Net income increased in 2019 as a $409 million increase in deferred tax benefit, a $392 million increase in net derivative gains and a $59 million decrease in interest expense more than offset a $527 million decrease in operating income.
•Operating income of $270 million for the year ended December 31, 2019 decreased 66% from $797 million in 2018. The decrease was primarily due to lower margins associated with reduced commodity prices and the divestiture of the Fayetteville Shale E&P and related midstream gathering assets in December 2018.
•Net cash provided by operating activities of $964 million was down 21% from $1,223 million in 2018 primarily due to the decrease in operating income net of depreciation, depletion and amortization and non-cash impairments, partially offset by the improvement in settled derivatives and positive change in assets and liabilities.
•Total capital invested of $1,140 million was down 9% from $1,248 million in 2018.
•We repurchased $62 million of our outstanding long-term senior notes at a discount and recognized a gain on the extinguishment of debt of $8 million. In addition, we retired the remaining $52 million principal of our outstanding senior notes that were due in January 2020.
E&P
•E&P segment operating income of $283 million was down 64%, compared to $794 million in 2018. This excludes the impact of derivatives.
•Year-end reserves of 12,721 Bcfe increased 800 Bcfe, or 7%, from 11,921 Bcfe at the end of 2018, resulting from 1,195 Bcfe of additions and 385 Bcfe of revisions, partially offset by 778 Bcfe of production and 2 Bcfe of sales.
•Total net production of 778 Bcfe was comprised of 78% natural gas, 18% NGLs and 4% oil. In 2018, E&P segment production volumes of 946 Bcfe included 243 Bcf of production from our operations in the Fayetteville Shale, which was sold in December 2018. Excluding the impact of production from the sold Fayetteville Shale assets, our production increased 11% from 703 Bcfe in 2018, and our liquids production increased 23% over the same period.
•Excluding the effect of derivatives, our realized natural gas price of $1.98 per Mcf, realized oil price of $46.90 per barrel and realized NGL price of $11.59 per barrel decreased 19%, 17% and 35%, respectively, from 2018. Our weighted average realized price excluding the effect of derivatives of $2.18 per Mcfe decreased 18% from the same period in 2018.
•The E&P segment invested capital totaling $1,138 million, drilling 105 wells, completing 116 wells and placing 113 wells to sales.
Outlook
We expect to continue to exercise capital discipline in our 2020 capital investment program by investing within cash flow from operations, net of changes in working capital, supplemented by earmarked proceeds of the Fayetteville Shale sale that in the meantime have been used to reduce debt. We remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities, looking for ways to optimize our cost structure and to maximize margins in each core area of our business and further developing our knowledge of our asset base. We believe that we and our industry will continue to face challenges due to 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 above under “Risk Factors.”
RESULTS OF OPERATIONS
The following discussion of our results of operations for our segments is presented before intersegment eliminations. We report on our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Restructuring charges, interest expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income taxes are discussed on a consolidated basis.
We have applied the Securities and Exchange Commission’s recently adopted FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent fiscal years. This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for fiscal 2019 and fiscal 2018. For the comparison of fiscal 2018 and fiscal 2017, see “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2018 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 28, 2019.
E&P
The 2018 information in the table below includes the financial results from E&P assets in the Fayetteville Shale that were sold in December 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
Revenues (1)
|
$
|
1,703
|
|
|
$
|
2,525
|
|
|
Operating costs and expenses
|
1,420
|
|
(2)
|
1,731
|
|
(3)
|
Operating income
|
$
|
283
|
|
|
$
|
794
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives, settled (4)
|
$
|
180
|
|
|
$
|
(94)
|
|
|
(1)Includes $2 million and $5 million in third-party water sales for the years ended December 31, 2019 and 2018, respectively.
(2)Includes $11 million of restructuring charges and $13 million of non-cash, non-full cost pool impairments for the year ended December 31, 2019.
(3)Includes $37 million of restructuring charges, an $18 million loss on the sale of assets and $15 million of non-cash, non-full cost pool asset impairments for the year ended December 31, 2018.
(4)Includes $1 million amortization of premiums paid related to certain natural gas call options for each of the years ended December 31, 2019 and 2018.
Operating Income
•E&P segment operating income for the year ended December 31, 2018 included $105 million related to our operations in the Fayetteville Shale, which were sold in December 2018. Excluding the amounts related to Fayetteville, our E&P segment operating income decreased $406 million for the year ended December 31, 2019, compared to the same period in 2018, as lower margins associated with decreased commodity pricing were only partially offset by increased efficiencies and production.
Revenues
The following illustrate the effects on sales revenues associated with changes in commodity prices and production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
|
(in millions except percentages)
|
Natural
Gas
|
|
Oil
|
|
NGLs
|
|
Total
|
2018 sales revenues (1)
|
$
|
1,974
|
|
|
$
|
193
|
|
|
$
|
353
|
|
|
$
|
2,520
|
|
Changes associated with the Fayetteville Shale sale (2)
|
(537)
|
|
|
—
|
|
|
—
|
|
|
(537)
|
|
2018 sales revenues, net of Fayetteville Shale revenues
|
1,437
|
|
|
193
|
|
|
353
|
|
|
1,983
|
|
Changes associated with prices
|
(342)
|
|
|
(46)
|
|
|
(149)
|
|
|
(537)
|
|
Changes associated with production volumes
|
112
|
|
|
73
|
|
|
70
|
|
|
255
|
|
2019 sales revenues (3)
|
$
|
1,207
|
|
|
$
|
220
|
|
|
$
|
274
|
|
|
$
|
1,701
|
|
Increase (decrease) from 2018, net of Fayetteville Shale revenues
|
(16)
|
%
|
|
14
|
%
|
|
(22)
|
%
|
|
(14)
|
%
|
(1)Excludes $5 million in other operating revenues for the year ended December 31, 2018 related to third-party water sales.
(2)This amount represents the revenues associated with the Fayetteville Shale assets, which were sold in December 2018. There were no Fayetteville Shale revenues in 2019.
(3)Excludes $2 million in other operating revenues for the year ended December 31, 2019 related to third-party water sales.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
|
|
|
|
Increase/(Decrease)
|
|
2019
|
|
2018
|
|
|
Natural Gas (Bcf)
|
|
|
|
|
|
Northeast Appalachia
|
459
|
|
|
459
|
|
|
—%
|
|
Southwest Appalachia
|
150
|
|
|
105
|
|
|
43%
|
|
Fayetteville Shale (1)
|
—
|
|
|
243
|
|
|
(100)%
|
|
Other
|
—
|
|
|
—
|
|
|
—%
|
|
Total
|
609
|
|
|
807
|
|
|
(25)%
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
|
|
|
Southwest Appalachia
|
4,673
|
|
|
3,355
|
|
|
39%
|
|
Other
|
23
|
|
|
52
|
|
|
(56)%
|
|
Total
|
4,696
|
|
|
3,407
|
|
|
38%
|
|
|
|
|
|
|
|
|
|
NGL (MBbls)
|
|
|
|
|
|
|
|
Southwest Appalachia
|
23,611
|
|
|
19,679
|
|
|
20%
|
|
Other
|
9
|
|
|
27
|
|
|
(67)%
|
|
Total
|
23,620
|
|
|
19,706
|
|
|
20%
|
|
|
|
|
|
|
|
Production volumes by area (Bcfe):
|
|
|
|
|
|
Northeast Appalachia
|
459
|
|
|
459
|
|
|
—%
|
|
Southwest Appalachia (2)
|
319
|
|
|
243
|
|
|
31%
|
|
Fayetteville Shale (1)
|
—
|
|
|
243
|
|
|
(100)%
|
|
Other
|
—
|
|
|
1
|
|
|
(100)%
|
|
Total
|
778
|
|
|
946
|
|
|
(18)%
|
|
|
|
|
|
|
|
Production percentage:
|
|
|
|
|
|
Natural gas
|
78
|
%
|
|
85
|
%
|
|
|
|
Oil
|
4
|
%
|
|
2
|
%
|
|
|
|
NGL
|
18
|
%
|
|
13
|
%
|
|
|
|
(1)The Fayetteville Shale assets were sold in December 2018.
(2)Approximately 317 Bcfe and 240 Bcfe for the years ended December 31, 2019 and 2018, respectively, were produced from the Marcellus Shale formation.
•E&P segment production volumes for the year ended December 31, 2018 included 243 Bcf of production from our operations in the Fayetteville Shale which were sold in December 2018. Excluding this amount, production volumes for our E&P segment increased 75 Bcfe for the year ended December 31, 2019, compared to the same period in 2018, primarily due to a 31% increase in production volumes in Southwest Appalachia.
•Oil and NGL production increased 38% and 20%, respectively, for the year ended December 31, 2019, compared to 2018, reflecting our investment in our liquids-rich acreage in Southwest Appalachia.
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 cannot control or 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 hedging 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 activities in order to maintain appropriate liquidity and financial flexibility.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Increase/
(Decrease)
|
Natural Gas Price:
|
|
|
|
|
|
|
NYMEX Henry Hub Price ($/MMbtu) (1)
|
|
$
|
2.63
|
|
|
$
|
3.09
|
|
|
(15)%
|
|
Discount to NYMEX (2)
|
|
(0.65)
|
|
|
(0.64)
|
|
|
2%
|
|
Average realized gas price, excluding derivatives ($/Mcf)
|
|
$
|
1.98
|
|
|
$
|
2.45
|
|
|
(19)%
|
|
Loss on settled financial basis derivatives ($/Mcf)
|
|
—
|
|
|
(0.04)
|
|
|
|
|
Gain (loss) on settled commodity derivatives ($/Mcf)
|
|
0.20
|
|
|
(0.06)
|
|
|
|
|
Average realized gas price, including derivatives ($/Mcf)
|
|
$
|
2.18
|
|
|
$
|
2.35
|
|
|
(7)%
|
|
|
|
|
|
|
|
|
|
Oil Price:
|
|
|
|
|
|
|
|
WTI oil price ($/Bbl)
|
|
$
|
57.03
|
|
|
$
|
64.77
|
|
|
(12)%
|
|
Discount to WTI
|
|
(10.13)
|
|
|
(7.98)
|
|
|
27%
|
|
Average oil price, excluding derivatives ($/Bbl)
|
|
$
|
46.90
|
|
|
$
|
56.79
|
|
|
(17)%
|
|
Gain (loss) on settled derivatives ($/Bbl)
|
|
2.66
|
|
|
(0.72)
|
|
|
|
|
Average oil price, including derivatives ($/Bbl)
|
|
$
|
49.56
|
|
|
$
|
56.07
|
|
|
(12)%
|
|
|
|
|
|
|
|
|
|
NGL Price:
|
|
|
|
|
|
|
|
Average realized NGL price, excluding derivatives ($/Bbl)
|
|
$
|
11.59
|
|
|
$
|
17.91
|
|
|
(35)%
|
|
Gain (loss) on settled derivatives ($/Bbl)
|
|
2.05
|
|
|
(0.68)
|
|
|
|
|
Average realized NGL price, including derivatives ($/Bbl)
|
|
$
|
13.64
|
|
|
$
|
17.23
|
|
|
(21)%
|
|
Percentage of WTI, excluding derivatives
|
|
20
|
%
|
|
28
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Total Weighted Average Realized Price:
|
|
|
|
|
|
|
|
Excluding derivatives ($/Mcfe)
|
|
$
|
2.18
|
|
|
$
|
2.66
|
|
|
(18)%
|
|
Including derivatives ($/Mcfe)
|
|
$
|
2.42
|
|
|
$
|
2.57
|
|
|
(6)%
|
|
(1)Based on last day settlement prices from monthly futures contracts.
(2)This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation charges and fuel charges, and excludes financial basis hedges.
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 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.
We regularly enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to ensure 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 7A, Quantitative and Qualitative Disclosures about Market Risk, of this Annual Report, Note 6 to the consolidated financial statements included in this Annual Report, and our derivative risk factor for additional discussion about our derivatives and risk management activities.
The table below presents the amount of our future production in which the impact of basis volatility has been limited as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bcf)
|
|
Basis Differential
|
Financial Basis Swaps – Natural Gas
|
|
|
|
2020
|
198
|
|
|
$
|
(0.31)
|
|
2021
|
86
|
|
|
0.04
|
|
2022
|
45
|
|
|
(0.50)
|
|
Total
|
329
|
|
|
|
|
|
|
|
|
|
|
Physical Sales Arrangements – Natural Gas
|
|
|
|
|
|
2020
|
165
|
|
|
$
|
(0.04)
|
|
2021
|
50
|
|
|
(0.28)
|
|
Total
|
215
|
|
|
|
In addition to limiting the impact of basis volatility, the table below presents the amount of our future production in which the impact of price volatility has been limited through the use of derivatives as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2021
|
|
2022
|
Natural gas (Bcf)
|
496
|
|
|
260
|
|
|
31
|
|
Oil (MBbls)
|
5,402
|
|
|
3,029
|
|
|
438
|
|
Ethane (MBbls)
|
7,520
|
|
|
2,410
|
|
|
—
|
|
Propane (MBbls)
|
5,112
|
|
|
2,460
|
|
|
—
|
|
Total financial protection on future production (Bcfe)
|
604
|
|
|
307
|
|
|
34
|
|
We refer you to Note 6 to the consolidated financial statements included in this Annual Report for additional details about our derivative instruments.
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions except percentages)
|
2019
|
|
2018 (1)
|
|
Increase/(Decrease)
|
Lease operating expenses
|
$
|
722
|
|
|
$
|
878
|
|
|
(18)%
|
|
General & administrative expenses
|
150
|
|
(2)
|
186
|
|
(3)
|
(19)%
|
|
Restructuring charges
|
11
|
|
|
37
|
|
|
(70)%
|
|
Taxes, other than income taxes
|
62
|
|
|
83
|
|
|
(25)%
|
|
Full cost pool amortization
|
439
|
|
|
479
|
|
|
(8)%
|
|
Non-full cost pool DD&A
|
23
|
|
|
35
|
|
|
(34)%
|
|
Impairments
|
13
|
|
|
15
|
|
|
(13)%
|
|
Loss on sale of assets
|
—
|
|
|
18
|
|
|
(100)%
|
|
Total operating costs
|
$
|
1,420
|
|
|
|
$
|
1,731
|
|
|
(18)%
|
|
(1)Includes eleven months of expenses from our Fayetteville Shale operations, which were sold in December 2018.
(2)Includes a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $6 million of legal settlement charges for the year ended December 31, 2019.
(3)Includes $9 million of legal settlement charges for the year ended December 31, 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
Average unit costs per Mcfe:
|
2019
|
|
2018
|
|
Increase/(Decrease)
|
Lease operating expenses (1)
|
$
|
0.92
|
|
|
$
|
0.93
|
|
|
(1)%
|
|
General & administrative expenses
|
$
|
0.18
|
|
(2)
|
$
|
0.19
|
|
(3)
|
(5)%
|
|
Taxes, other than income taxes
|
$
|
0.08
|
|
|
|
$
|
0.09
|
|
(4)
|
(11)%
|
|
Full cost pool amortization
|
$
|
0.56
|
|
|
$
|
0.51
|
|
|
10%
|
|
(1)Includes post-production costs such as gathering, processing, fractionation and compression.
(2)Excludes $11 million in restructuring charges, a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $6 million of legal settlement charges for the year ended December 31, 2019.
(3)Excludes $36 million in restructuring charges, $9 million of legal settlement charges for the year ended December 31, 2018.
(4)Excludes $1 million of restructuring charges for the year ended December 31, 2018.
Lease Operating Expenses
•Lease operating expenses per Mcfe decreased $0.01 for the year ended December 31, 2019, compared to 2018, as a $0.02 per Mcfe decrease associated with the Fayetteville Shale sale was partially offset by a $0.01 per Mcfe increase primarily related to increased liquids production, which includes higher costs from processing and NGL fees.
General and Administrative Expenses
•General and administrative expenses in 2019 included a $6 million residual value guarantee short-fall payment to the previous lessor of our headquarters building and $6 million in legal settlement charges. 2018 included $9 million in legal settlement charges. Excluding these amounts, general and administrative expenses decreased $39 million for the year ended December 31, 2019, compared to 2018, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.
•On a per Mcfe basis, excluding restructuring, legal settlement charges and the residual value guarantee short-fall payment, general and administrative expenses per Mcfe decreased by $0.01 for the year ended December 31, 2019, compared to 2018, as a decrease in expenses more than offset an 18% decrease in production volumes primarily associated with the Fayetteville Shale sale.
Taxes, Other than Income Taxes
•Taxes other than income taxes per Mcfe may 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. Taxes, other than income taxes, per Mcfe decreased $0.01 per Mcfe for the year ended December 31, 2019, compared to the same period in 2018, primarily due to a $7 million severance tax refund/credit received in the fourth quarter of 2019 related to additional favorable assessments on deductible expenses in Southwest Appalachia and lower realized commodity pricing in 2019. In 2018, we received an $8 million severance tax refund related to a favorable assessment on deductible expenses in Southwest Appalachia which reduced our average severance tax rate applied in 2019.
Full Cost Pool Amortization
•Our full cost pool amortization rate increased $0.05 per Mcfe for the year ended December 31, 2019, as compared to 2018. The increase in the average amortization rate resulted primarily as a result of the impact of capital investments and the further evaluation of our unproved properties during the year and the impact of the Fayetteville Shale sale, which reduced our total natural gas reserves along with the carrying value of our full cost pool assets.
•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 $1.5 billion at December 31, 2019 compared to $1.8 billion at December 31, 2018. The unevaluated costs excluded from amortization decreased, as compared to 2018, as the evaluation of previously unevaluated properties totaling $507 million in 2019 was only partially offset by the impact of $258 million of unevaluated capital invested during the same period.
Impairments
•During the year ended December 31, 2019, we recognized non-cash impairments of $13 million associated with non-core E&P assets.
•In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of carrying value or fair value less costs to sell. Because the assets outside the full cost pool associated with the Fayetteville Shale sale met the criteria for held for sale accounting in the third quarter of 2018, we determined the carrying value of certain non-full cost pool E&P assets exceeded the fair value less costs to sell. As a result, a non-cash impairment charge of $15 million was recorded during the year ended December 31, 2018.
Marketing
The 2018 information in the table below includes the results from the gas gathering assets included in the Fayetteville Shale sale which closed in December 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions except percentages)
|
2019
|
|
2018
|
|
Increase/(Decrease)
|
Marketing revenues
|
$
|
2,849
|
|
|
$
|
3,497
|
|
|
(19)%
|
|
Gas gathering revenues (1)
|
—
|
|
|
248
|
|
|
(100)%
|
|
Other operating revenues
|
1
|
|
|
—
|
|
|
100%
|
|
Marketing purchases
|
2,833
|
|
|
3,455
|
|
|
(18)%
|
|
Operating costs and expenses (1)
|
25
|
|
|
166
|
|
(2)
|
(85)%
|
|
Impairments
|
3
|
|
|
155
|
|
(3)
|
(98)%
|
|
(Gain) loss on sale of assets, net
|
2
|
|
|
(35)
|
|
|
(106)%
|
|
Operating income (loss)
|
$
|
(13)
|
|
|
$
|
4
|
|
|
(425)%
|
|
|
|
|
|
|
|
|
Volumes marketed (Bcfe)
|
1,101
|
|
|
1,163
|
|
|
(5)%
|
|
Volumes gathered (Bcf) (1)
|
—
|
|
|
382
|
|
|
(100)%
|
|
|
|
|
|
|
|
Affiliated E&P natural gas production marketed
|
79
|
%
|
|
93
|
%
|
|
|
Affiliated E&P oil and NGL production marketed
|
61
|
%
|
|
66
|
%
|
|
|
(1)Amounts for 2018 include our Fayetteville Shale-related midstream gathering business, which was sold in December 2018.
(2)Includes $2 million of restructuring charges for the year ended December 31, 2018.
(3)Includes a $145 million non-cash impairment related to the midstream gathering assets associated with the Fayetteville Shale sale in December 2018 and a $10 million non-cash impairment related to certain non-core gathering assets for the year ended December 31, 2018.
Operating Income
•Marketing operating income for the year ended December 31, 2018 included a $7 million loss related to our midstream gathering operations in the Fayetteville Shale, which we sold in December 2018. Excluding this amount, operating income decreased $24 million for the year ended December 31, 2019, compared to 2018, primarily due to a $26 million decrease in marketing margin.
•The margin generated from marketing activities was $16 million and $42 million for the years ended December 31, 2019 and 2018, respectively.
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. Increases and decreases in marketing revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in marketing purchase expenses. Efforts to mitigate the costs of excess transportation capacity can result in greater expenses and therefore lower Marketing margins.
Revenues
•Revenues from our marketing activities decreased $648 million for the year ended December 31, 2019, compared to 2018, primarily due to a 14% decrease in the price received for volumes marketed and a 62 Bcfe decrease in the volumes marketed.
Operating Costs and Expenses
•Marketing operating costs and expenses for the year ended December 31, 2018 included $140 million related to our midstream gathering operations in the Fayetteville Shale, which were sold in December 2018. Excluding this amount, operating costs and expenses decreased $1 million for the year ended December 31, 2019, compared to the year ended December 31, 2018, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.
Impairments
•In the third quarter of 2019, we recorded non-cash impairments of $3 million to non-core gathering assets.
•During 2018, we determined the carrying value of our midstream gathering assets held for sale exceeded the fair value less the costs to sell. As a result, we recorded a non-cash impairment charge of $145 million in 2018. Additionally, in 2018, we recognized a $10 million non-cash impairment on unrelated non-core gathering assets.
Consolidated
Restructuring Charges
For the year ended December 31, 2019, we recognized total restructuring charges of $11 million, of which $6 million primarily related to office consolidation and $5 million in cash severance, including payroll taxes withheld. As of December 31, 2019, we had recorded a liability of $2 million related to severance to be paid out in 2020.
In June 2018, we announced a workforce reduction plan, which resulted primarily from our previously announced study of structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects of our business and activities. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were canceled. We recognized $23 million in restructuring charges related to the workforce reduction plan for the year ended December 31, 2018.
In December 2018, we closed the sale of the equity in certain of our subsidiaries that owned and operated our Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, most employees associated with those assets became employees of the buyer, although the employment of some was terminated. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited. We incurred $12 million in severance costs related to the Fayetteville Shale sale for the year ended December 31, 2018 and have recognized these costs as restructuring charges.
As a result of the Fayetteville Shale sale during 2018, we incurred $4 million in charges primarily related to office consolidation and recognized these costs as restructuring charges for the year ended December 31, 2018.
Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions except percentages)
|
|
2019
|
|
2018
|
|
Increase/
(Decrease)
|
Gross interest expense:
|
|
|
|
|
|
|
Senior notes
|
|
|
$
|
155
|
|
|
$
|
196
|
|
|
(21)%
|
|
Credit arrangements
|
|
|
11
|
|
|
35
|
|
|
(69)%
|
|
Amortization of debt costs
|
|
|
8
|
|
|
8
|
|
|
—%
|
|
Total gross interest expense
|
|
|
174
|
|
|
239
|
|
|
(27)%
|
|
Less: capitalization
|
|
|
(109)
|
|
|
(115)
|
|
|
(5)%
|
|
Net interest expense
|
|
|
$
|
65
|
|
|
$
|
124
|
|
|
(48)%
|
|
•Interest expense related to our senior notes decreased for the year ended December 31, 2019, as compared to the same period in 2018, as we repurchased $114 million and $900 million of our outstanding senior notes in the second half of 2019 and December 2018, respectively. Additionally, S&P and Moody's upgraded our public bond ratings in April and May 2018, respectively, which lowered the interest relates associated with our senior notes due 2020 and 2025 by 50 basis points, starting in July 2018.
•For the year ended December 31, 2019, interest expense related to our credit arrangements decreased, as compared to the same period in 2018, primarily due to the extinguishment of our 2016 term loan and entering into our revolving credit facility in April 2018, which decreased our outstanding borrowing amount, along with the repayment of our revolving credit facility borrowings with a portion of the net proceeds from the Fayetteville Shale sale in December 2018.
•Capitalized interest decreased $6 million for the year ended December 31, 2019, compared to the same period in 2018, due to the evaluation of natural gas and oil properties over the past twelve months. Capitalized interest increased over the same periods as a percentage of gross interest expense primarily due to a smaller percentage decrease in our unevaluated natural gas and oil properties balance, as compared to the larger percentage decrease in our gross interest expense over the same period, in addition to an increase in our average cost of debt over the past twelve months.
Gain (Loss) on Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
Gain (loss) on unsettled derivatives
|
$
|
94
|
|
|
$
|
(24)
|
|
|
Gain (loss) on settled derivatives
|
180
|
|
(1)
|
(94)
|
|
(1)
|
Total gain (loss) on derivatives
|
$
|
274
|
|
|
|
$
|
(118)
|
|
|
|
(1)Includes $1 million of premiums paid related to certain natural gas purchased call options for each of the years ended December 31, 2019 and 2018, which is included in gain (loss) on derivatives on the consolidated statement of operations.
We refer you to Note 6 to the consolidated financial statements included in this Annual Report for additional details about our gain (loss) on derivatives.
Gain (Loss) on Early Extinguishment of Debt
•In 2019, we recorded a gain of $8 million on early extinguishment of debt as a result of our repurchase at a discount of $62 million in aggregate principal amount of our outstanding senior notes. See Note 9 to the consolidated financial statements of this Annual Report for more information on our long-term debt.
•In December 2018, we used a portion of the net proceeds from our Fayetteville Shale sale to repurchase $40 million of our senior notes due January 2020, $787 million of our senior notes due March 2022 and $73 million of our senior notes due January 2025. We recognized a loss of $9 million for the redemption of these senior notes, which included $2 million of premiums paid.
•Concurrent with the closing of our revolving credit facility in April 2018, we repaid our $1,191 million 2016 secured term loan balance and recognized a loss of $8 million on early debt extinguishment on the consolidated statements of operations related to the unamortized debt issuance expense.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
(in millions except percentages)
|
2019
|
|
2018
|
Income tax expense (benefit)
|
$
|
(411)
|
|
|
$
|
1
|
|
Effective tax rate
|
(86)
|
%
|
|
0
|
%
|
•As of the first quarter of 2019, we had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted income, we concluded that it was more likely than not that the deferred tax assets would be realized and determined that $522 million of the valuation allowance will be released. As a result, a net tax benefit was recorded during 2019 of $411 million, which was primarily comprised of a deferred tax benefit of $522 million related to the valuation allowance release offset by the recognition of deferred tax expense of $112 million related to taxes on pre-tax income. We expect to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.
•Our low effective income tax rate in 2018 was the result of our recognition of a valuation allowance that reduced the deferred tax asset primarily related to our current net operating loss carryforward, as well as changes to the deferred tax rate enacted under the Tax Reform Act. 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.
We refer you to Note 11 to the consolidated financial statements included in this Annual Report for additional discussion about our income taxes.
LIQUIDITY AND CAPITAL RESOURCES
We depend primarily on funds generated from our operations, our secured revolving credit facility, our cash and cash equivalents balance and capital markets as our primary sources of liquidity. We refer you to Note 9 to the consolidated financial statements included in this Annual Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our revolving credit facility. Looking forward to 2020, although we have financial flexibility with our ability to draw on the $1.8 billion in available liquidity under our revolving credit facility as of December 31, 2019, we remain committed to our capital discipline strategy of investing within our cash flow from operations net of changes in working capital, supplemented by a portion of the remaining net proceeds from the Fayetteville Shale sale realized in December 2018 that in the meantime was used to reduce outstanding debt. See Note 3 to the consolidated financial statements included in this Annual Report for additional discussion of the Fayetteville Shale sale.
In December 2018, we closed on the Fayetteville Shale sale and received net proceeds of approximately $1,650 million after customary purchase price adjustments. From the net proceeds received, $914 million was immediately used to repurchase $900 million of our outstanding senior notes along with related accrued interest and retirement premiums paid, $201 million was used in late 2018 and early 2019 to repurchase over 44 million shares of our outstanding common stock and the remainder was earmarked to supplement our 2019 and 2020 capital investing programs. Rather than hold these proceeds as cash and cash equivalents during this time, we chose to repurchase or pay down outstanding debt until such time that the sale proceeds would be used to supplement our capital investing program. Accordingly, as our 2020 capital investing program is expected to exceed our cash flow from operations, net of changes in working capital, supplemented by Fayetteville Shale sale proceeds, we plan on drawing no more than $300 million of the remaining earmarked sale proceeds from our revolving credit facility.
Our cash flow from operating activities is highly dependent upon 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. The sales price we realize for our production is also influenced by our commodity hedging activities. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. In 2019, gains on derivatives have offset a large portion of the impact of the recent decline in prices, and we currently have derivative positions in place for portions of our expected 2020, 2021 and 2022 production at prices above current market levels. There can be no assurance that we will be able to add derivative positions to cover the remainder of our expected production at favorable prices. See “Risk Factors” in Item 1A, “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A and Note 6 to the consolidated financial statements included in this Annual Report for further details.
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 our cash flow from operating activities.
Our short-term cash flows are also dependent on the timely collection of receivables from our customers and joint interest 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 and joint interest partners could adversely impact our cash flows.
Due to the 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 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
In April 2018, we replaced our 2016 credit facility with a new revolving credit facility. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion with a current aggregate commitment of $2.0 billion and a borrowing base (limit on availability) that is redetermined at least each April and October. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets. In October 2019, we entered into an amendment to the 2018 credit facility that, among other things, established the October 2019 borrowing base at $2.1 billion and extended the maturity date to April 2024. The borrowing base is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investing and operating costs. As of December 31, 2019, we had $34 million borrowings on our revolving credit facility and $172 million in outstanding letters of credit.
As of December 31, 2019, we were in compliance with all of the covenants of our revolving credit facility in all material respects. Our ability to comply with financial covenants is dependent upon the success of our development program and upon factors beyond our control, such as the market prices for natural gas and liquids. We refer you to Note 9 of the consolidated financial statements included in this Annual Report for additional discussion of the covenant requirements of our 2018 revolving credit facility.
The credit status of the financial institutions participating in our revolving credit facility could adversely impact our ability to borrow funds under the revolving credit facility. Although we believe all of the lenders under the facility 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 9 to the consolidated financial statements included in this Annual Report for additional discussion of our revolving credit facility.
In the second half of 2019, we repurchased $35 million of our 4.95% Senior Notes due 2025, $11 million of our 7.50% Senior Notes due 2026 and $16 million of our 7.75% Senior Notes due 2027, and recognized an $8 million gain on extinguishment of debt. Additionally, in December 2019, we retired the remaining $52 million principal of our 4.05% Senior Notes due 2020.
Because of the focused work on refinancing and repayment of our debt during the last three years, only $247 million, or 11%, of our outstanding debt balance as of December 31, 2019 is scheduled to become due prior to 2025.
At February 25, 2020, we had a long-term issuer credit rating of Ba2 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 upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively.
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
(in millions)
|
2019
|
|
2018
|
Net cash provided by operating activities
|
$
|
964
|
|
|
$
|
1,223
|
|
Net cash provided by (used in) investing activities
|
(1,045)
|
|
|
359
|
|
Net cash used in financing activities
|
(115)
|
|
|
(2,297)
|
|
Cash Flow from Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
(in millions)
|
2019
|
|
2018
|
Net cash provided by operating activities
|
$
|
964
|
|
|
$
|
1,223
|
|
Add: Changes in working capital
|
(69)
|
|
|
90
|
|
Net cash provided by operating activities, net of changes in working capital
|
895
|
|
|
1,313
|
|
•Net cash provided by operating activities decreased 21% or $259 million for the year ended December 31, 2019, compared to the same period in 2018, primarily due to a decrease in revenues resulting from an 18% decrease in production volumes as a result of the Fayetteville Shale sale in December 2018 and a 6% decrease in our weighted average realized commodity price, including derivatives.
•Net cash generated from operating activities, net of changes in working capital, provided 79% of our cash requirements for capital investments for the year ended December 31, 2019, compared to providing 105% of our cash requirements for capital investments for the same period in 2018. As discussed above, a portion of the Fayetteville Shale sale proceeds was also used to fund the 2019 capital investment program.
Cash Flow from Investing Activities
•Total E&P capital investing decreased $93 million for the year ended December 31, 2019, compared to the same period in 2018, due to a $73 million decrease in direct E&P capital investing, a $14 million decrease in capitalized internal costs and a $6 million decrease in capitalized interest.
•The decrease in capitalized interest for the year ended December 31, 2019, as compared to the same period in 2018, was primarily due to the evaluation of natural gas and oil properties over the past twelve months.
•Marketing capital investing decreased $9 million for the year ended December 31, 2019, compared to the same period in 2018, primarily due to the sale of the midstream gathering assets associated with the Fayetteville Shale in December 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
(in millions)
|
2019
|
|
2018
|
Additions to properties and equipment
|
$
|
1,099
|
|
|
$
|
1,290
|
|
Adjustments for capital investments:
|
|
|
|
|
|
Changes in capital accruals
|
35
|
|
|
(53)
|
|
Other (1)
|
6
|
|
|
11
|
|
Total capital investing
|
$
|
1,140
|
|
|
$
|
1,248
|
|
(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 years ended December 31,
|
|
|
|
|
(in millions except percentages)
|
2019
|
|
2018
|
|
Increase/
(Decrease)
|
E&P capital investing
|
$
|
1,138
|
|
|
$
|
1,231
|
|
|
|
Marketing capital investing (1)
|
—
|
|
|
9
|
|
|
|
Other capital investing
|
2
|
|
|
8
|
|
|
|
Total capital investing
|
$
|
1,140
|
|
|
$
|
1,248
|
|
|
(9)%
|
|
(1)Included our midstream gathering business in the Fayetteville Shale was sold in December 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
(in millions)
|
2019
|
|
2018
|
E&P Capital Investments by Type:
|
|
|
|
Drilling and completions, including workovers
|
$
|
838
|
|
|
$
|
895
|
|
Acquisitions of properties
|
55
|
|
|
51
|
|
Seismic expenditures
|
3
|
|
|
4
|
|
Water infrastructure projects
|
35
|
|
|
60
|
|
Drilling rigs, well services equipment and other
|
21
|
|
|
15
|
|
Capitalized interest and expenses
|
186
|
|
|
206
|
|
Total E&P capital investments
|
$
|
1,138
|
|
|
$
|
1,231
|
|
|
|
|
|
E&P Capital Investments by Area
|
|
|
|
Northeast Appalachia
|
$
|
365
|
|
|
$
|
422
|
|
Southwest Appalachia
|
710
|
|
|
691
|
|
Fayetteville Shale (1)
|
—
|
|
|
33
|
|
Other (2)
|
63
|
|
|
85
|
|
Total E&P capital investments
|
$
|
1,138
|
|
|
$
|
1,231
|
|
(1)The Fayetteville Shale assets were sold in December 2018.
(2)Includes $35 million and $60 million for the years ended December 31, 2019 and 2018, respectively, related to our water infrastructure project.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
2019
|
|
2018
|
Gross Operated Well Count Summary:
|
|
|
|
Drilled
|
105
|
|
|
106
|
|
Completed
|
116
|
|
|
119
|
|
Wells to sales
|
113
|
|
|
138
|
|
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 Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions except percentages)
|
2019
|
|
2018
|
|
Increase/
(Decrease)
|
Debt (1)
|
$
|
2,242
|
|
|
$
|
2,318
|
|
|
$
|
(76)
|
|
Equity
|
$
|
3,246
|
|
|
$
|
2,362
|
|
|
$
|
884
|
|
Total debt to capitalization ratio
|
41
|
%
|
|
50
|
%
|
|
|
(1)The decrease in total debt as of December 31, 2019, as compared to December 31, 2018, primarily relates to the repurchase of $114 of our outstanding senior notes in the second half of 2019, partially offset by a $34 million increase in our revolving credit facility borrowings.
•Net cash used in financing activities for the year ended December 31, 2019 was $115 million, compared to net cash used in financing activities of $2,297 million for the same period in 2018.
•In January 2019, we repurchased approximately 5 million shares of common stock for approximately $21 million.
•In the second half of 2019, we paid $54 million on the open market to repurchase $62 million of our outstanding senior notes at a discount. We recognized a gain on early extinguishment of debt of $8 million.
•In December 2019, we retired the remaining $52 million principal of our 4.05% Senior Notes due January 2020.
•In January 2018, we paid $27 million for a preferred stock dividend declared in the fourth quarter of 2017.
•In April 2018, we fully repaid our $1,191 million 2016 term loan and replaced it with the 2018 revolving credit facility with a $2.1 billion borrowing base. We recognized a loss on early extinguishment of debt of $8 million.
•In December 2018, upon closing of the Fayetteville Shale sale, a portion of the sale proceeds was used to fund tender offers to repurchase $900 million of our outstanding senior notes. We recognized a loss on early extinguishment of debt of $9 million, primarily related to the early retirement premiums.
•We also used a portion of the net proceeds from the Fayetteville Shale sale to repurchase 39 million shares of common stock for approximately $180 million in December 2018.
We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our outstanding debt and credit facility.
Working Capital
•We had negative working capital of $169 million at December 31, 2019, a $279 million decrease from December 31, 2018, as a decrease of $236 million in accounts receivable as compared to December 31, 2018, primarily related to the sale of the Fayetteville Shale production in December 2018 and lower commodity prices, a decrease of $196 million in cash and cash equivalents and a current liability of $34 million recorded in 2019 related to the implementation of the new lease accounting standard (Topic 842), were only partially offset by a $102 million increase in the net current mark-to-market value of our derivative position and an $84 million decrease in accounts payable, as compared to December 31, 2018.
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 December 31, 2019, our material off-balance sheet arrangements and transactions include operating service arrangements, $172 million in letters of credit outstanding against our 2018 revolving credit facility and $55 million in outstanding surety bonds. 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” below for more information on our operating leases.
Contractual Obligations and Contingent Liabilities and Commitments
We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual obligations as of December 31, 2019, were as follows:
Contractual Obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Total
|
|
Less than 1 Year
|
|
1 to 3 Years
|
|
3 to 5 Years
|
|
5 to 8 Years
|
|
More than 8 Years
|
Transportation charges (1)
|
$
|
8,470
|
|
|
$
|
768
|
|
|
$
|
1,235
|
|
|
$
|
1,169
|
|
|
$
|
1,739
|
|
|
$
|
3,559
|
|
Debt
|
2,262
|
|
|
—
|
|
|
213
|
|
|
34
|
|
|
2,015
|
|
|
—
|
|
Interest on debt (2)
|
985
|
|
|
160
|
|
|
317
|
|
|
296
|
|
|
212
|
|
|
—
|
|
Operating leases (3)
|
148
|
|
|
33
|
|
|
42
|
|
|
28
|
|
|
29
|
|
|
16
|
|
Compression services (4)
|
37
|
|
|
13
|
|
|
22
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Operating agreements
|
11
|
|
|
8
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchase obligations
|
69
|
|
|
69
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other obligations (5)
|
13
|
|
|
10
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
11,995
|
|
|
$
|
1,061
|
|
|
|
$
|
1,835
|
|
|
$
|
1,529
|
|
|
$
|
3,995
|
|
|
$
|
3,575
|
|
(1)As of December 31, 2019, we had commitments for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems. Of the total $8.5 billion, $1.1 billion related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. For further information, we refer you to “Operational Commitments and Contingencies” in Note 10 to the consolidated financial statements included in this Annual Report. This amount also included guarantee obligations of up to $293 million.
Included in the transportation charges above is $108 million (due in less than one year) related to certain agreements that remain in the name of our marketing affiliate but are expected to be paid in full by Flywheel Energy Operating, LLC, the purchaser of the Fayetteville Shale assets. Of these amounts, we may be obligated to reimburse Flywheel Energy Operating, LLC, for a portion of volumetric shortfalls during 2020 (up to $58 million) under these transportation agreements and have currently recorded a $46 million liability as of December 31, 2019, down from $88 million recorded at December 31, 2018.
In the first quarter of 2019, we agreed to purchase firm transportation with pipelines in the Appalachian basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments of which the seller has agreed to reimburse $133 million of these commitments.
In February 2020, we were notified that the proposed Constitution pipeline project was cancelled and that we were released from a firm transportation agreement with its sponsor. As of December 31, 2019, we had contractual commitments totaling $512 million over the next seventeen years related to the Constitution pipeline project that are reflected in the table above as transportation obligations that were pending regulatory approval and/or construction. These amounts are $6 million within one to three years, $68 million within three to five years, $102 million within five to eight years and $336 million more than eight years forward.
(2)Interest payments on our senior notes were calculated utilizing the fixed rates associated with our fixed rate notes outstanding at December 31, 2019. Senior note interest rates were based on our credit ratings as of December 31, 2019.
(3)Operating leases include costs for compressors, drilling rigs, pressure pumping equipment, office space and other equipment under non-cancelable operating leases expiring through 2029.
During the second quarter of 2019, we executed an agreement to convey our purchase option in our headquarters office building to a third-party, which closed on the purchase of the building in July 2019. Concurrent with the closing of the building sale, we terminated our existing lease agreement and entered into a new 10-year lease agreement for a smaller portion of the headquarters building in July 2019, resulting in an estimated annual savings of $7 million to $8 million.
(4)As of December 31, 2019, our E&P segment had commitments of approximately $37 million for compression services associated primarily with our Southwest Appalachia division.
(5)Our other significant contractual obligations include approximately $12 million for various information technology support and data subscription agreements.
Future contributions to the pension and postretirement benefit plans are excluded from the table above. For further information regarding our pension and other postretirement benefit plans, we refer you to Note 13 to the consolidated financial statements included in this Annual Report and “Critical Accounting Policies and Estimates” below for additional information.
We refer you to Note 9 to the consolidated financial statements included in this Annual Report for a discussion of the terms of our debt.
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, 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.
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, results of operations or cash flows.
For further information, we refer you to “Litigation” and “Environmental Risk” in Note 10 to the consolidated financial statements included in this Annual Report.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following describes significant judgments and estimates used in the preparation of our consolidated financial statements.
Natural Gas and Oil Properties
We utilize the full cost method of accounting for costs related to the 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) plus the lower of cost or market value of unproved properties. 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 qualifying as cash flow hedges, to calculate the ceiling value of their reserves.
Costs associated with unevaluated properties are excluded from our amortization base until we have evaluated the properties or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. Our decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves judgment and may be subject to changes over time based on several factors, including our drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2019, we had approximately $1,506 million of costs excluded from our amortization base, all of which related to our properties in the United States. Inclusion of some or all of these costs in our properties in the United States in the future, without adding any associated reserves, could result in non-cash ceiling test impairments.
At December 31, 2019, the ceiling value of our reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.58 per MMBtu, for West Texas Intermediate oil of $55.69 per barrel and NGLs of $11.58 per barrel, adjusted for market differentials. The net book value of our natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2019. We had no derivative positions that were designated for hedge accounting as of December 31, 2019. Although no ceiling test impairment was recorded in 2019, given the fall in commodity prices in 2019 and early 2020 and assuming that commodity prices remain at January 2020 levels for the rest of the first quarter of 2020, we expect a non-cash impairment to our natural gas and oil properties in the first quarter of 2020 ranging from approximately $400 million to $600 million, net of tax. Future decreases in commodity prices, increases in costs and/or changes in the balance of costs excluded from amortization and other factors may result in further non-cash impairments to our natural gas and oil properties.
Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.10 per MMBtu, West Texas Intermediate oil of $65.56 per barrel and NGLs of $17.64 per barrel, adjusted for market differentials, the net book value of our United States natural gas and oil properties did not exceed the ceiling amount and did not
result in a ceiling test impairment at December 31, 2018. We had no derivative positions that were designated for hedge accounting as of December 31, 2018.
A decline in natural gas, oil and NGL prices used to calculate the discounted future net revenues of our reserves affects both the present value of cash flows and the quantity of reserves. In the past, nearly all of our reserve base was natural gas; therefore changes in oil and NGL prices did not have as significant an impact as natural gas prices on cash flows and reserve quantities. However, with the sale of our Fayetteville Shale assets in 2018 and our strategic shift towards developing our liquids-rich assets in recent years, our reserve base as of December 31, 2019 was approximately 68% natural gas, 29% NGLs and 3% oil. Therefore, NGL and oil pricing will have a more significant impact on the cash flows and quantity of reserves going forward. Our standardized measure and reserve quantities as of December 31, 2019, were $3.7 billion and 12.7 Tcfe, respectively.
Natural gas, oil and NGL reserves cannot be measured exactly. Our estimate of natural gas, oil and NGL reserves requires extensive judgments of reservoir engineering data and projections of costs that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management. Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team for that property. The reservoir engineering and financial data included in these estimates are reviewed by senior engineers, who are not part of the asset management teams, and by our Director of Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Director of Reserves has more than 25 years of experience in petroleum engineering, including the estimation of natural gas and oil reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in 2018, our Director of Reserves served in various reservoir engineering roles for EP Energy Company, El Paso Corporation, Cabot Oil & Gas Corporation, Schlumberger and H.J. Gruy & Associates, and is a member of the Society of Petroleum Engineers. He reports to our Executive Vice President and Chief Operating Officer, who has more than 31 years of experience in petroleum engineering including the estimation of natural gas, oil and NGL reserves in multiple basins in the United States, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining Southwestern in 2017, our Chief Operating Officer served in various engineering and leadership roles for EP Energy Corporation, El Paso Corporation, ARCO Oil and Gas Company, Burlington Resources and Peoples Energy Production, and is a member of the Society of Petroleum Engineers.
We engage NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in more detail below. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 38 years and over 17 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 28 years and over 17 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in the State of Texas or a Licensed Professional Engineer in the State of Texas; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) each is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates is also separately reviewed by our accounting staff. Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our President and Chief Executive Officer. Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors, with whom final authority over the estimates of our proved reserves rests. A copy of NSAI’s report has been filed as Exhibit 99.1 to this Annual Report.
Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to proved undeveloped and proved non-producing reserves, as production history and pressure data over time is available for the majority of our proved developed properties. Proved developed reserves accounted for 50% of our total reserve base as of December 31, 2019. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. The uncertainties inherent in the reserve estimates are compounded by applying additional estimates of the rates and timing of production volumes and the costs that will be incurred in developing and producing the reserves. We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control. We refer you to “Our proved natural gas, oil and NGL reserves are estimates that include uncertainties. Any material changes to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A, “Risk Factors,” of Part I of this Annual Report for a more detailed discussion of these uncertainties, risks and other factors.
In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approximately 99% of the present worth of the company’s total proved reserves. NSAI’s audit process consists of sorting all fields by descending present value order and selecting the fields from highest value to descending value until the selected fields account for more than 80% of the present worth of our reserves. The fields included in approximately the top 99% present value as of December 31, 2019, accounted for approximately 99% of our total proved reserves and approximately 100% of our proved undeveloped reserves. In the conduct of its audit, NSAI did not independently verify the data we provided to them with respect to ownership interests, natural gas, oil and NGL production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. On February 7, 2020, NSAI issued its audit opinion as to the reasonableness of our reserve estimates for the year-ended December 31, 2019 stating that our estimated proved natural gas, oil and NGL reserves are, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Assets and liabilities held for sale are subject to an assessment of fair value which includes many key valuation estimates, inputs and assumptions including but not limited to: production forecasts, pricing, basis differentials, operating and general and administrative expense forecasts, future development costs, discount rate determination and tax inputs. In the third quarter of 2018, we recognized certain assets and liabilities as held for sale related to the Fayetteville Shale sale requiring a comparison of their respective carrying cost and fair value less costs to sell. Our full cost pool assets were excluded from held for sale accounting treatment as they are governed by SEC Regulation S-X Rule 4-10. The fair value of our gathering assets to be sold was estimated using an estimated discounted cash flow model along with market assumptions. The assumptions used in the calculation of estimated discounted cash flows included future commodity prices, projections of estimated quantities of natural gas reserves, operating costs, projections of future rates of production, inflation factors and risk-adjusted discount rates. We believe the assumptions used were reasonable.
Under full cost accounting rules, sales of oil and gas properties, whether or not being amortized currently, shall be accounted for as a reduction of the full cost pool, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. For instance, a significant alteration would not ordinarily be expected to occur for sales involving less than 25 percent of the reserve quantities of a given cost center. Judgments are required around the determination of whether a divestment is deemed significant. Such judgments include an assessment of the of the reserve quantities sold as compared to total reserve quantities and other qualitative and quantitative assessments of the relationship between capitalized costs and proved reserves. We did not recognize a gain or loss on the sale of our oil and gas properties as the divestment was deemed not significant. Please refer to Note 3 to the consolidated financial statements included in this Annual Report for further detail.
Derivatives and Risk Management
We use fixed price swap agreements and options to reduce the volatility of earnings and cash flow due to fluctuations in the prices of certain commodities and interest rates. Our policies prohibit speculation with derivatives and limit agreements to counterparties with appropriate credit standings to minimize the risk of uncollectability. We actively monitor the credit status of our counterparties 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. In both 2019 and 2018, we financially protected 69% of our total production with derivatives. The primary risks related to our derivative contracts are the volatility in market prices and basis differentials for our production. However, the market price risk is generally offset by the gain or loss recognized upon the related transaction that is financially protected.
All derivatives are recognized in the balance sheet as either an asset or a liability as measured at fair value other than transactions for which the normal purchase/normal sale exception is applied. Certain criteria must be satisfied for derivative financial instruments to be designated for hedge accounting. Accounting guidance for qualifying hedges allows an unsettled derivative’s unrealized gains and losses to be recorded in either earnings or as a component of other comprehensive income until settled. In the period of settlement, we recognize the gains and losses from these qualifying hedges in gas sales revenues. The ineffective portion of those fixed price swaps was recognized in earnings. 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 consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. We calculate gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period.
As of December 31, 2019, none of our derivative contracts were designated for hedge accounting treatment. Changes in the fair value of unsettled derivatives that were not designated for hedge accounting treatment are recorded in gain (loss) on derivatives. See Note 6 to the consolidated financial statements included in this Annual Report for more information on our derivative position at December 31, 2019.
Future market price volatility could create significant changes to the derivative positions recorded in our consolidated financial statements. We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of Part II of this Annual Report for additional information regarding our hedging activities.
Pension and Other Postretirement Benefits
We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation (see Note 13 to the consolidated financial statements included in this Annual Report for further discussion and disclosures regarding these benefit plans). Two of the assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds invested. For the December 31, 2019 benefit obligation and periodic benefit cost to be recorded in 2020, the initial discount rate assumed is 3.70%. This compares to an initial discount rate of 4.35% for the benefit obligation and periodic benefit cost recorded in 2019. For the 2020 periodic benefit cost, the expected return assumed decreased to 6.50%, from 7.00% in 2019.
Using the assumed rates discussed above, we recorded total benefit cost of $15 million in 2019 related to our pension and other postretirement benefit plans. Due to the significance of the discount rate and expected long-term rate of return, the following sensitivity analysis demonstrates the effect that a 0.5% change in those assumptions would have had on our 2019 pension expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) of Annual Pension Expense
|
|
|
(in millions)
|
0.5% Increase
|
|
0.5% Decrease
|
Discount rate
|
$
|
(1)
|
|
|
$
|
1
|
|
Expected long-term rate of return
|
$
|
—
|
|
|
$
|
—
|
|
As of December 31, 2019, we recognized a liability of $43 million, compared to $47 million at December 31, 2018, related to our pension and other postretirement benefit plans. During 2019, we also made cash contributions totaling $14 million to fund our pension and other postretirement benefit plans.
Stock-Based Compensation
We account for stock-based compensation transactions using a fair value method and recognize an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalize the cost into natural gas and oil properties included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of our natural gas and oil properties. We use models to determine fair value of stock-based compensation, which requires significant judgment with respect to forfeitures, volatility and other factors.
Our stock-based compensation is classified as either an equity award or a liability award in accordance with generally accepted accounting principles. The fair value of an equity-classified award is determined at the grant date and is amortized on a straight-line basis over the vesting life of the award. The fair-value of a liability-classified award is determined on a quarterly basis through the final vesting date and is amortized based on the current fair value of the award and the percentage of vesting period incurred to date.
New Accounting Standards
Refer to Note 1 to the consolidated financial statements included in this Annual Report for further discussion of our significant accounting policies and for discussion of accounting standards that have been implemented in this report, along with a discussion of relevant accounting standards that are pending adoption.
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
All statements, other than historical fact or present financial information, 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 Exchange Act of 1934, as amended. All statements 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, they 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 Annual Report 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,” “target” or similar 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. 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:
•the timing and extent of changes in market conditions and prices for natural gas, oil and NGLs (including regional basis differentials);
•our ability to fund our planned capital investments;
•a change in our credit rating, an increase in interest rates and any adverse impacts from the discontinuation of the London Interbank Offered Rate (“LIBOR”);
•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 the possible impact of the coronavirus (COVID-19);
•difficulties in appropriately allocating capital and resources among our strategic opportunities;
•the timing and extent of our success in discovering, developing, producing and estimating reserves;
•our ability to maintain leases that may expire if production is not established or profitably maintained;
•our ability to realize the expected benefits from 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 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, climate and over-the-counter derivatives;
•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;
•increased competition;
•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 SEC.
Should one or more of the risks or uncertainties described above or elsewhere in this Annual 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 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.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Southwestern Energy Company to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, utilizing the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control – Integrated Framework (2013).
Based on this evaluation, management has concluded the Company’s internal control over financial reporting was effective as of December 31, 2019.
The effectiveness of our internal control over financial reporting as of December 31, 2019 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Southwestern Energy Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Southwestern Energy Company and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Natural Gas, Oil and NGL Reserves on Proved Natural Gas and Oil Properties, Net
The Company’s consolidated property and equipment, net balance was $5,267 million as of December 31, 2019, and depreciation, depletion, and amortization (DD&A) expense for the year ended December 31, 2019 was $471 million, both of which substantially relate to proved natural gas and oil properties. As described in Note 1 to the consolidated financial statements, the Company utilizes the full cost method of accounting for its natural gas and oil producing properties. Under this method, all capitalized costs are amortized over the estimated lives of the properties using the unit-of-production method based on proved natural gas, oil and NGL reserves. 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%. In 2019, the Company did not have any ceiling test impairments on its proved natural gas and oil properties. As disclosed by management, estimates of natural gas, oil and NGL reserves require extensive judgments of reservoir engineering data and projections of costs that will be incurred in developing and producing reserves. The uncertainties inherent in the reserve estimates are compounded by applying additional estimates of the rates and timing of production volumes and the costs that will be incurred in developing and producing the reserves. The estimates of natural gas, oil and NGL reserves have been developed by specialists, specifically reservoir engineers.
The principal considerations for our determination that performing procedures relating to the impact of proved natural gas, oil and NGL reserves on proved natural gas and oil properties, net is a critical audit matter are there was significant judgment by management, including the use of specialists, when developing the estimates of proved natural gas, oil and NGL reserves. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the significant assumptions used in developing those estimates, including future production volumes.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved natural gas, oil and NGL reserves, the calculation of the full cost ceiling impairment test, and the calculation of DD&A expense. These procedures also included, among others, evaluating the significant assumptions used by management in developing these estimates, including future production volumes, testing the full cost ceiling impairment test calculation, and testing the unit-of-production rate used to calculate DD&A expense. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved natural gas, oil and NGL reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as the methods and assumptions used by the specialists. The procedures performed also included tests of the data used by the specialists and an evaluation of the specialists’ findings.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 27, 2020
We have served as the Company’s auditor since 2002.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions, except share/per share amounts)
|
2019
|
|
2018
|
|
2017
|
Operating Revenues:
|
|
|
|
|
|
Gas sales
|
$
|
1,241
|
|
|
$
|
1,998
|
|
|
$
|
1,793
|
|
Oil sales
|
223
|
|
|
196
|
|
|
102
|
|
NGL sales
|
274
|
|
|
352
|
|
|
206
|
|
Marketing
|
1,297
|
|
|
1,222
|
|
|
972
|
|
Gas gathering
|
—
|
|
|
89
|
|
|
126
|
|
Other
|
3
|
|
|
5
|
|
|
4
|
|
|
3,038
|
|
|
3,862
|
|
|
3,203
|
|
Operating Costs and Expenses:
|
|
|
|
|
|
Marketing purchases
|
1,320
|
|
|
1,229
|
|
|
976
|
|
Operating expenses
|
720
|
|
|
785
|
|
|
671
|
|
General and administrative expenses
|
166
|
|
|
209
|
|
|
233
|
|
(Gain) loss on sale of operating assets, net
|
2
|
|
|
(17)
|
|
|
(6)
|
|
Restructuring charges
|
11
|
|
|
39
|
|
|
—
|
|
Depreciation, depletion and amortization
|
471
|
|
|
560
|
|
|
504
|
|
Impairments
|
16
|
|
|
171
|
|
|
—
|
|
Taxes, other than income taxes
|
62
|
|
|
89
|
|
|
94
|
|
|
2,768
|
|
|
3,065
|
|
|
2,472
|
|
Operating Income
|
270
|
|
|
797
|
|
|
731
|
|
Interest Expense:
|
|
|
|
|
|
Interest on debt
|
166
|
|
|
231
|
|
|
239
|
|
Other interest charges
|
8
|
|
|
8
|
|
|
9
|
|
Interest capitalized
|
(109)
|
|
|
(115)
|
|
|
(113)
|
|
|
65
|
|
|
124
|
|
|
135
|
|
|
|
|
|
|
|
Gain (Loss) on Derivatives
|
274
|
|
|
(118)
|
|
|
422
|
|
Gain (Loss) on Early Extinguishment of Debt
|
8
|
|
|
(17)
|
|
|
(70)
|
|
Other Income (Loss), Net
|
(7)
|
|
|
—
|
|
|
5
|
|
|
|
|
|
|
|
Income Before Income Taxes
|
480
|
|
|
538
|
|
|
953
|
|
Provision (Benefit) for Income Taxes
|
|
|
|
|
|
Current
|
(2)
|
|
|
1
|
|
|
(22)
|
|
Deferred
|
(409)
|
|
|
—
|
|
|
(71)
|
|
|
(411)
|
|
|
1
|
|
|
(93)
|
|
Net Income
|
$
|
891
|
|
|
$
|
537
|
|
|
$
|
1,046
|
|
Mandatory convertible preferred stock dividend
|
—
|
|
|
—
|
|
|
108
|
|
Participating securities – mandatory convertible preferred stock
|
—
|
|
|
2
|
|
|
123
|
|
Net Income Attributable to Common Stock
|
$
|
891
|
|
|
$
|
535
|
|
|
$
|
815
|
|
|
|
|
|
|
|
Earnings Per Common Share
|
|
|
|
|
|
Basic
|
$
|
1.65
|
|
|
$
|
0.93
|
|
|
$
|
1.64
|
|
Diluted
|
$
|
1.65
|
|
|
$
|
0.93
|
|
|
$
|
1.63
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding:
|
|
|
|
|
|
Basic
|
539,345,343
|
|
|
574,631,756
|
|
|
498,264,321
|
|
Diluted
|
540,382,914
|
|
|
576,642,808
|
|
|
500,804,297
|
|
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions)
|
2019
|
|
2018 (1)
|
|
2017 (1)
|
Net income
|
$
|
891
|
|
|
$
|
537
|
|
|
$
|
1,046
|
|
|
|
|
|
|
|
Change in value of pension and other postretirement liabilities:
|
|
|
|
|
|
Amortization of prior service cost and net loss, including loss on settlements and curtailments included in net periodic pension cost (2)
|
8
|
|
|
10
|
|
|
2
|
|
Net actuarial loss incurred in period (3)
|
(5)
|
|
|
(2)
|
|
|
(13)
|
|
Total change in value of pension and postretirement liabilities
|
3
|
|
|
8
|
|
|
(11)
|
|
|
|
|
|
|
|
Change in currency translation adjustment
|
—
|
|
|
—
|
|
|
6
|
|
|
|
|
|
|
|
Comprehensive income
|
$
|
894
|
|
|
$
|
545
|
|
|
$
|
1,041
|
|
(1)In 2018 and 2017, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.
(2)Net of $2 million in taxes for the year ended December 31, 2019.
(3)Net of ($1) million in taxes for the year ended December 31, 2019.
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2019
|
|
December 31,
2018
|
ASSETS
|
(in millions, except share amounts)
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
5
|
|
|
$
|
201
|
|
Accounts receivable, net
|
345
|
|
|
581
|
|
Derivative assets
|
278
|
|
|
130
|
|
Other current assets
|
51
|
|
|
44
|
|
Total current assets
|
679
|
|
|
956
|
|
Natural gas and oil properties, using the full cost method, including $1,506 million as of December 31, 2019 and $1,755 million as of December 31, 2018 excluded from amortization
|
25,250
|
|
|
24,180
|
|
Other
|
520
|
|
|
525
|
|
Less: Accumulated depreciation, depletion and amortization
|
(20,503)
|
|
|
(20,049)
|
|
Total property and equipment, net
|
5,267
|
|
|
4,656
|
|
Operating lease assets
|
159
|
|
|
—
|
|
Deferred tax assets
|
407
|
|
|
—
|
|
Other long-term assets
|
205
|
|
|
185
|
|
Total long-term assets
|
771
|
|
|
185
|
|
TOTAL ASSETS
|
$
|
6,717
|
|
|
$
|
5,797
|
|
LIABILITIES AND EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
525
|
|
|
$
|
609
|
|
Taxes payable
|
59
|
|
|
58
|
|
Interest payable
|
51
|
|
|
52
|
|
Derivative liabilities
|
125
|
|
|
79
|
|
Current operating lease liabilities
|
34
|
|
|
—
|
|
Other current liabilities
|
54
|
|
|
48
|
|
Total current liabilities
|
848
|
|
|
846
|
|
Long-term debt
|
2,242
|
|
|
2,318
|
|
Long-term operating lease liabilities
|
119
|
|
|
—
|
|
Pension and other postretirement liabilities
|
43
|
|
|
46
|
|
Other long-term liabilities
|
219
|
|
|
225
|
|
Total long-term liabilities
|
2,623
|
|
|
2,589
|
|
Commitments and contingencies (Note 10)
|
|
|
|
Equity:
|
|
|
|
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 585,555,923 shares as of December 31, 2019 and 585,407,107 as of December 31, 2018
|
6
|
|
|
6
|
|
Additional paid-in capital
|
4,726
|
|
|
4,715
|
|
Accumulated deficit
|
(1,251)
|
|
|
(2,142)
|
|
Accumulated other comprehensive loss
|
(33)
|
|
|
(36)
|
|
Common stock in treasury, 44,353,224 shares as of December 31, 2019 and 39,092,537 shares as of December 31, 2018
|
(202)
|
|
|
(181)
|
|
Total equity
|
3,246
|
|
|
2,362
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
6,717
|
|
|
$
|
5,797
|
|
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
Net income
|
$
|
891
|
|
|
$
|
537
|
|
|
$
|
1,046
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
471
|
|
|
560
|
|
|
504
|
|
Amortization of debt issuance costs
|
8
|
|
|
8
|
|
|
9
|
|
Impairments
|
16
|
|
|
171
|
|
|
—
|
|
Deferred income taxes
|
(409)
|
|
|
—
|
|
|
(71)
|
|
(Gain) loss on derivatives, unsettled
|
(94)
|
|
|
24
|
|
|
(451)
|
|
Stock-based compensation
|
8
|
|
|
14
|
|
|
24
|
|
(Gain) loss on early extinguishment of debt
|
(8)
|
|
|
17
|
|
|
70
|
|
(Gain) loss on sale of assets, net
|
2
|
|
|
(17)
|
|
|
(6)
|
|
|
|
|
|
|
|
Other
|
10
|
|
|
(1)
|
|
|
13
|
|
Change in assets and liabilities:
|
|
|
|
|
|
Accounts receivable
|
234
|
|
|
(153)
|
|
|
(65)
|
|
Accounts payable
|
(141)
|
|
|
65
|
|
|
48
|
|
Taxes payable
|
—
|
|
|
2
|
|
|
4
|
|
Interest payable
|
—
|
|
|
(10)
|
|
|
(2)
|
|
Inventories
|
(7)
|
|
|
(13)
|
|
|
(1)
|
|
Other assets and liabilities
|
(17)
|
|
|
19
|
|
|
(25)
|
|
Net cash provided by operating activities
|
964
|
|
|
1,223
|
|
|
1,097
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities:
|
|
|
|
|
|
Capital investments
|
(1,099)
|
|
|
(1,290)
|
|
|
(1,268)
|
|
Proceeds from sale of property and equipment
|
54
|
|
|
1,643
|
|
|
10
|
|
Other
|
—
|
|
|
6
|
|
|
6
|
|
Net cash provided by (used in) investing activities
|
(1,045)
|
|
|
359
|
|
|
(1,252)
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities:
|
|
|
|
|
|
Payments on current portion of long-term debt
|
(52)
|
|
|
—
|
|
|
(328)
|
|
Payments on long-term debt
|
(54)
|
|
|
(2,095)
|
|
|
(1,139)
|
|
Payments on revolving credit facility
|
(532)
|
|
|
(1,983)
|
|
|
—
|
|
Borrowings under revolving credit facility
|
566
|
|
|
1,983
|
|
|
—
|
|
Change in bank drafts outstanding
|
(19)
|
|
|
17
|
|
|
9
|
|
Proceeds from issuance of long-term debt
|
—
|
|
|
—
|
|
|
1,150
|
|
Debt issuance costs
|
(3)
|
|
|
(9)
|
|
|
(24)
|
|
Purchase of treasury stock
|
(21)
|
|
|
(180)
|
|
|
—
|
|
Preferred stock dividend
|
—
|
|
|
(27)
|
|
|
(16)
|
|
Cash paid for tax withholding
|
(1)
|
|
|
(3)
|
|
|
(2)
|
|
Other
|
1
|
|
|
—
|
|
|
(2)
|
|
Net cash used in financing activities
|
(115)
|
|
|
(2,297)
|
|
|
(352)
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents
|
(196)
|
|
|
(715)
|
|
|
(507)
|
|
Cash and cash equivalents at beginning of year
|
201
|
|
|
916
|
|
|
1,423
|
|
Cash and cash equivalents at end of year
|
$
|
5
|
|
|
$
|
201
|
|
|
$
|
916
|
|
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
Preferred
Stock
|
|
Additional
Paid-In
Capital
|
|
Accumulated
Deficit (1)
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Common Stock
in Treasury
|
|
|
|
|
(in millions, except share amounts)
|
|
Shares
Issued
|
|
Amount
|
|
Shares
Issued
|
|
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Total
|
Balance at December 31, 2016
|
|
495,248,369
|
|
|
$
|
5
|
|
|
1,725,000
|
|
|
$
|
4,677
|
|
|
$
|
(3,725)
|
|
|
$
|
(39)
|
|
|
31,269
|
|
|
$
|
(1)
|
|
|
$
|
917
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,046
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,046
|
|
Other comprehensive loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5)
|
|
|
—
|
|
|
—
|
|
|
(5)
|
|
Total comprehensive income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,041
|
|
Stock-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38
|
|
Preferred stock dividend
|
|
12,791,716
|
|
|
—
|
|
|
—
|
|
|
(16)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16)
|
|
Issuance of restricted stock
|
|
5,055,208
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Cancellation of restricted stock
|
|
(742,028)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Performance units vested
|
|
121,208
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Issuance of stock awards
|
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax withholding – stock compensation
|
|
(340,234)
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
Balance at December 31, 2017
|
|
512,134,311
|
|
|
$
|
5
|
|
|
1,725,000
|
|
|
$
|
4,698
|
|
|
$
|
(2,679)
|
|
|
$
|
(44)
|
|
|
31,269
|
|
|
$
|
(1)
|
|
|
$
|
1,979
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
537
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
537
|
|
Other comprehensive income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Total comprehensive income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
545
|
|
Stock-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
Conversion of preferred stock
|
|
74,998,614
|
|
|
1
|
|
|
(1,725,000)
|
|
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Issuance of restricted stock
|
|
349,562
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Cancellation of restricted stock
|
|
(1,804,122)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Performance units vested
|
|
214,866
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Treasury stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
39,061,268
|
|
|
(180)
|
|
|
(180)
|
|
Tax withholding – stock compensation
|
|
(486,124)
|
|
|
—
|
|
|
—
|
|
|
(3)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3)
|
|
Balance at December 31, 2018
|
|
585,407,107
|
|
|
$
|
6
|
|
|
—
|
|
|
$
|
4,715
|
|
|
$
|
(2,142)
|
|
|
$
|
(36)
|
|
|
39,092,537
|
|
|
$
|
(181)
|
|
|
$
|
2,362
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
891
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
891
|
|
Other comprehensive income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Total comprehensive income
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
894
|
|
Stock-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
Issuance of restricted stock
|
|
236,978
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Cancellation of restricted stock
|
|
(239,571)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Performance units vested
|
|
535,802
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Treasury stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,260,687
|
|
|
(21)
|
|
|
(21)
|
|
Tax withholding – stock compensation
|
|
(384,393)
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
Balance at December 31, 2019
|
|
585,555,923
|
|
|
$
|
6
|
|
|
—
|
|
|
$
|
4,726
|
|
|
$
|
(1,251)
|
|
|
$
|
(33)
|
|
|
44,353,224
|
|
|
$
|
(202)
|
|
|
$
|
3,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 2016-9 as of the beginning of 2017. This adjustment increased net deferred tax assets and the related income tax valuation allowance by the same amount.
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 NGLs exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its marketing business (“Marketing”), which was previously referred to as “Midstream” when it included the operations of gathering systems. Southwestern conducts most of its business through subsidiaries and operates principally in two segments: E&P and Marketing. The Company’s historical financial and operating results include its Fayetteville Shale E&P and related midstream gathering businesses, which were sold in early December 2018 (“the Fayetteville Shale sale”). The sale is discussed in further detail in Note 3.
E&P. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania and West Virginia. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania and West Virginia as “Appalachia.” The Company also operates drilling rigs located in Pennsylvania and West Virginia, and provides oilfield products and services, principally serving 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 consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued.
Principles of Consolidation
The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
In 2015, the Company purchased an 86% ownership in a limited partnership that owns and operates a gathering system in Northeast Appalachia. Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The minority partner’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the years ended December 31, 2019, 2018 and 2017 was insignificant.
Major Customers
The Company sells the vast majority of its E&P natural gas, oil and NGL production to third-party customers through its marketing subsidiary. In 2019, no single customer accounted for 10% or greater of total sales. For the years ended December 31, 2018 and 2017, two subsidiaries of Royal Dutch Shell Plc in aggregate accounted for approximately 10.4% and 10.3%, respectively, of total natural gas, oil and NGL sales. The Company believes that the loss of a major customer would not have a material adverse effect on its ability to sell its natural gas, oil and NGL production because alternative purchasers are available.
Cash and Cash Equivalents
Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. Management considers cash and cash equivalents to have minimal credit and market risk as the Company monitors the credit status of the financial
institutions holding its cash and marketable securities. The following table presents a summary of cash and cash equivalents as of December 31, 2019, and December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
December 31, 2019
|
|
December 31, 2018
|
Cash
|
$
|
5
|
|
|
$
|
32
|
|
Marketable securities (1)
|
—
|
|
|
169
|
|
Total
|
$
|
5
|
|
|
$
|
201
|
|
(1)Consists of government stable value money market funds.
Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $15 million and $34 million as of December 31, 2019 and 2018, respectively.
Property, Depreciation, Depletion and Amortization
Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the 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. 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 ceiling test impairments.
Costs associated with unevaluated properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. The Company’s decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves judgment and may be subject to changes over time based on several factors, including drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2019, the Company had a total of $1,506 million of costs excluded from the amortization base, all of which related to its properties in the United States. Inclusion of some or all of these costs in the Company’s United States properties in the future, without adding any associated reserves, could result in additional non-cash ceiling test impairments.
At December 31, 2019, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.58 per MMBtu, West Texas Intermediate oil of $55.69 per barrel and NGLs of $11.58 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties was $218 million below the ceiling amount and therefore did not result in a ceiling test impairment at December 31, 2019. Given the fall in commodity prices in 2019 and early 2020, the Company expects some non-cash impairment of its assets will likely occur as early as the first quarter of 2020. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2019.
Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $3.10 per MMBtu, West Texas Intermediate oil of $65.56 per barrel and NGLs of $17.64 per barrel, adjusted for market 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 December 31, 2018. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2018.
Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.98 per MMBtu, West Texas Intermediate oil of $47.79 per barrel and NGLs of $14.41 per barrel, adjusted for market 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 results in a ceiling test impairment at December 31, 2017. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2017.
Gathering Systems. The Company’s investment in gathering systems was primarily in a system serving its Fayetteville Shale operations in Arkansas. These assets were included in the Fayetteville Shale sale that closed in December 2018.
Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization.
Asset Retirement Obligations. Natural gas and oil properties require expenditures to plug and abandon the wells and reclaim the associated pads and other supporting infrastructure when the wells are no longer producing. An asset retirement obligation associated with the retirement of a tangible long-lived asset such as oil and gas properties is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
Impairment of Long-Lived Assets. The Company’s non-full cost pool assets include water facilities, gathering systems, technology infrastructure, land, buildings and other equipment with useful lives that range from 3 to 30 years. The carrying value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Should an impairment exist, the impairment loss would be measured as the amount that the asset’s carrying value exceeds its fair value. For the year ended December 31, 2019, the Company recognized non-cash impairments of $16 million for non-core assets.
In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of carrying value or fair value less costs to sell. This accounting guidance does not apply to the Company’s full cost pool assets, which are governed under SEC Regulation S-X 4-10, and thus were not classified as held for sale. Because the assets excluding the full cost pool met the criteria for held for sale accounting in the third quarter of 2018 due to their inclusion in the Fayetteville Shale sale, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, a non-cash impairment charge of $160 million was recorded for the year ended December 31, 2018, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale. Separately, the Company recorded an $11 million non-cash impairment of other non-core assets that were not included in the Fayetteville Shale sale, for the year ended December 31, 2018.
Intangible Assets. The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their useful life. At December 31, 2019 and 2018, the Company had $56 million and $65 million, respectively, in marketing-related intangible assets that were included in Other long-term assets on the consolidated balance sheets. The Company amortized $9 million of its marketing-related intangible asset in each of the years ended December 31, 2019, 2018 and 2017, and expects to amortize $9 million in 2020, $8 million in 2021 and $5 million for the three years thereafter.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations. Additional information regarding uncertain tax positions along with the impact of the Tax Reform Act can be found in Note 11.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses derivative instruments to financially protect sales of natural gas, oil and NGLs. In addition, the Company uses interest rate swaps to manage exposure to unfavorable interest rate changes. Since the Company does not designate its derivatives for hedge accounting treatment, gains and losses resulting from the settlement of derivative contracts have been recognized in gain (loss) on derivatives in the consolidated statements of operations when the contracts expire and the related physical transactions of the underlying commodity are settled. Additionally, changes in the fair value of the unsettled portion of derivative contracts are also recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 6 and Note 8 for a discussion of the Company’s hedging activities.
Earnings Per 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, performance units and the assumed conversion of mandatory convertible preferred stock. An antidilutive impact is an increase in earnings per share resulting from the conversion, exercise, or contingent issuance of certain securities.
In January 2015, the Company issued 34,500,000 depositary shares that entitled the holder to a proportional fractional interest in the rights and preferences of the mandatory convertible preferred stock, including conversion, dividend, liquidation and voting rights. The mandatory convertible preferred stock had 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, therefore, was considered a participating security. Accordingly, it has been included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, earnings are allocated to participating securities 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. In January 2018, all outstanding shares of mandatory convertible preferred stock were converted to 74,998,614 shares of the Company’s common stock. The Company paid its last dividend payment of approximately $27 million associated with the depositary shares in January 2018.
The Company declared dividends on its mandatory convertible preferred stock in the first, second and third quarters of 2017 that were settled partially in common stock for a total of 10,040,306 shares.
As part of the Company’s share repurchase program, the Company paid approximately $180 million to repurchase 39,061,268 shares of its outstanding common stock in 2018 and paid approximately $21 million to repurchase 5,260,687 shares in 2019, which are included in the Company's treasury stock.
The following table presents the computation of earnings per share for the years ended December 31, 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions, except share/per share amounts)
|
2019
|
|
2018
|
|
2017
|
Net income
|
$
|
891
|
|
|
$
|
537
|
|
|
$
|
1,046
|
|
Mandatory convertible preferred stock dividend
|
—
|
|
|
—
|
|
|
108
|
|
Participating securities – mandatory convertible preferred stock
|
—
|
|
|
2
|
|
|
123
|
|
Net income attributable to common stock
|
$
|
891
|
|
|
$
|
535
|
|
|
$
|
815
|
|
|
|
|
|
|
|
Number of common shares:
|
|
|
|
|
|
Weighted average outstanding
|
539,345,343
|
|
|
574,631,756
|
|
|
498,264,321
|
|
Issued upon assumed exercise of outstanding stock options
|
—
|
|
|
—
|
|
|
—
|
|
Effect of issuance of non-vested restricted common stock
|
361,380
|
|
|
698,103
|
|
|
1,061,056
|
|
Effect of issuance of non-vested performance units
|
676,191
|
|
|
1,312,949
|
|
|
1,478,920
|
|
Weighted average and potential dilutive outstanding
|
540,382,914
|
|
|
576,642,808
|
|
|
500,804,297
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
1.65
|
|
|
$
|
0.93
|
|
|
$
|
1.64
|
|
Diluted
|
$
|
1.65
|
|
|
$
|
0.93
|
|
|
$
|
1.63
|
|
The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2019, 2018 and 2017, as they would have had an antidilutive effect:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
Unexercised stock options
|
5,078,253
|
|
|
5,909,082
|
|
|
116,717
|
|
Unvested share-based payment
|
1,728,264
|
|
|
3,692,794
|
|
|
5,361,849
|
|
Performance units
|
271,268
|
|
|
642,568
|
|
|
765,689
|
|
Mandatory convertible preferred stock
|
—
|
|
|
2,465,708
|
|
|
74,999,895
|
|
Total
|
7,077,785
|
|
|
12,710,152
|
|
|
81,244,150
|
|
Supplemental Disclosures of Cash Flow Information
The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Cash paid during the year for interest, net of amounts capitalized
|
$
|
58
|
|
|
$
|
135
|
|
|
$
|
130
|
|
Cash paid (received) during the year for income taxes
|
(52)
|
|
|
6
|
|
|
(5)
|
|
Increase (decrease) in noncash property additions
|
41
|
|
|
(42)
|
|
|
25
|
|
Stock-Based Compensation
The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties. See Note 14 for a discussion of the Company’s stock-based compensation.
Liability-Classified Awards
The Company classifies certain awards that can or will be settled in cash as liability awards. 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 or capitalized expense over the vesting period of the award. The Company’s liability-classified performance unit awards that were granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute total shareholder return and the other on relative total shareholder return as compared to a group of the Company’s peers. The Company’s liability-classified performance unit awards that were granted in 2019 include a performance condition based on the return of average capital employed and the same two market conditions as in the 2018 awards. The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis. See Note 14 for a discussion of the Company’s stock-based compensation.
Treasury Stock
In the third quarter of 2018, the Company announced its intention to repurchase up to $200 million of its outstanding common stock using a portion of the net proceeds from the Fayetteville Shale sale. At December 31, 2018, approximately $180 million had been spent to repurchase 39,061,268 shares at an average price of $4.63 per share. In the first quarter of 2019, the Company completed its share repurchase program by purchasing 5,260,687 shares of its outstanding common stock for approximately $21 million at an average price of $3.84 per share.
The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liabilities of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust, are presented as treasury stock and are carried at cost. As of December 31, 2019 and 2018, 5,115 shares and 10,653 shares, respectively, were held in the Rabbi Trust and were accounted for as treasury stock. In 2018, 20,616 shares were released from the Rabbi Trust due to a reduction in our workforce. These shares are still held as treasury stock.
Foreign Currency Translation
The Company has designated the Canadian dollar as the functional currency for its activities in Canada. The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders’ equity.
New Accounting Standards Implemented in this Report
In February 2016, the FASB issued Accounting Standards Update No. 2016-2, Leases (Topic 842) (“Update 2016-2”), 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. The codification was amended through additional ASUs. For public entities, Update 2016-02 became effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted Accounting Standards Codification (“ASC”) 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial application. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period of adoption on January 1, 2019, the incremental borrowing rate as of the adoption date was used to calculate the present value of remaining lease payments. Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of the standard did not materially change the Company's consolidated statement of operations or its consolidated statement of cash flows. Please refer to Note 4 for additional disclosure.
New Accounting Standards Not Yet Adopted in this Report
In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“Update 2016-13”). Update 2016-13 replaces the incurred loss model with an expected loss model, which is referred to as the current expected credit loss (“CECL”) model. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. For public business entities, the new standard is effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period.
From an evaluation of the Company’s existing credit portfolio, which includes trade receivables from commodity sales, joint interest billings due from partners, other receivables and cash equivalents, historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of our business partners. As anticipated, the CECL model did not have a significant impact on Southwestern's consolidated financial statements or related control environment upon adoption on January 1, 2020.
(2) RESTRUCTURING CHARGES
As part of an ongoing strategic effort to reposition its portfolio, optimize operational performance and improve margins, the Company has incurred charges related to restructuring that include reductions in workforce, office consolidation and other costs, including those associated with the sale of a large asset such as the Fayetteville Shale. These charges are further discussed below. The following table presents a summary of the restructuring charges included in Operating Income for the years ended December 31, 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions)
|
|
2019
|
|
2018 (1)
|
|
2017
|
Reduction in workforce (not Fayetteville Shale sale-related)
|
|
$
|
—
|
|
|
$
|
23
|
|
|
$
|
—
|
|
Fayetteville Shale sale-related
|
|
11
|
|
|
16
|
|
|
—
|
|
Total restructuring charges
|
|
$
|
11
|
|
|
$
|
39
|
|
|
$
|
—
|
|
(1)Does not include a $4 million gain for the year ended December 31, 2018 related to curtailment of the other postretirement benefit plan presented in other income (loss), net on the consolidated statements of operations.
The following table presents a summary of liabilities associated with the Company’s restructuring activities at December 31, 2019, which are reflected in accounts payable on the consolidated balance sheet:
|
|
|
|
|
|
(in millions)
|
|
Liability at December 31, 2018
|
$
|
5
|
|
Additions
|
11
|
|
Distributions
|
(14)
|
|
Liability at December 31, 2019
|
$
|
2
|
|
Reduction in Workforce (Not Fayetteville Shale Sale-Related)
In June 2018, the Company notified affected employees of a workforce reduction plan, which resulted primarily from a previously announced study of structural, process and organizational changes to enhance shareholder value and continues with respect to other aspects of the Company’s business activities. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited.
The following table presents a summary of the restructuring charges related to workforce reduction plans included in Operating Income (Loss) for the year ended December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31,
|
|
|
(in millions)
|
|
|
2018
|
|
|
Severance (including payroll taxes)
|
|
|
$
|
21
|
|
|
|
Stock-based compensation
|
|
|
—
|
|
|
|
Other benefits
|
|
|
—
|
|
|
|
Outplacement services, other
|
|
|
2
|
|
|
|
Total reduction in workforce-related restructuring charges (1)
|
|
|
$
|
23
|
|
|
|
(1)Total restructuring charges for the Company's E&P and Marketing segments were $21 million and $2 million, respectively, for the year ended December 31, 2018.
Fayetteville Shale Sale-Related
In December 2018, the Company closed on the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was terminated. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited. As of December 31, 2019, the Company has substantially completed the Fayetteville Shale sale-related employment terminations.
As a result of the Fayetteville Shale sale, the Company relocated certain employees and infrastructure to other locations and began the process of consolidating and reorganizing its office space. These charges related to office consolidation and reorganization have been recognized as restructuring charges.
In July 2019, the Company terminated its existing lease agreement in its headquarters office building and entered into a new 10-year lease agreement for a smaller portion of the building. Approximately $3 million of the fees associated with the Company’s headquarters office consolidation are reflected as restructuring charges for the year ended December 31, 2019. The Company also recognized additional severance costs in the third and fourth quarters of 2019, related to continued organizational restructuring, for which a liability of $2 million has been accrued as of December 31, 2019. The following table presents a summary of the restructuring charges related to the consolidation and reorganization associated with the Fayetteville Shale sale included in Operating Income on the condensed statements of operations for the years ended December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
(in millions)
|
2019
|
|
2018
|
Severance (including payroll taxes)
|
$
|
5
|
|
|
|
$
|
12
|
|
Office consolidation
|
6
|
|
|
|
4
|
|
Total Fayetteville Shale sale-related charges (1) (2)
|
$
|
11
|
|
|
|
$
|
16
|
|
(1)Total restructuring charges were $11 million and $16 million for the Company’s E&P segment for the years ended December 31, 2019 and 2018, respectively.
(2)Does not include a $4 million gain for the year ended December 31, 2018 related to the curtailment of the other postretirement benefit plan presented in Other Income (Loss), net on the consolidated statements of operations.
(3) DIVESTITURES
In August 2018, the Company entered into an agreement with Flywheel Energy Operating, LLC to sell 100% of the equity in the Company’s subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets for $1,865 million in cash, subject to customary closing adjustments, with an economic effective date of July 1, 2018.
In December 2018, the Company closed the Fayetteville Shale sale and received approximately $1,650 million, which included purchase price adjustments of approximately $215 million primarily related to the net cash flows from the economic
effective date to the closing date. The Company allocated the sale proceeds to gain on sale for the non-full cost pool assets and to capitalized costs for the full cost pool assets based on the proportion of the estimated fair values of the underlying assets. The fair values of these assets was estimated primarily using an income approach. Consequently, the Company recognized a gain on the sale of non-full cost pool assets of $17 million and a reduction of $887 million to its full cost pool assets. As the sale did not involve a significant change in proved reserves or significantly alter the relationship between capitalized costs and proved reserves, the Company recognized no gain or loss related to the full cost pool assets sold.
As part of the Fayetteville Shale sale agreement, the Company entered into certain natural gas derivative positions that were subsequently novated to the buyer in conjunction with finalization of the sale. The unrealized fair value of these derivatives at the closing of the sale in December 2018 was a net liability of $151 million, which was transferred to the buyer. The unrealized loss associated with the novated positions was offset by the gain that the Company recognized when the liability was transferred to the buyer. These offsetting amounts were recognized on the consolidated statements of operations in (gain) loss on sale of operating assets, net. In addition, the Company paid $22 million in premiums for these novated derivatives which was recorded as a loss in (gain) loss on sale of operating assets, net in 2018.
The Company retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of December 31, 2019, approximately $108 million of these contractual commitments remain, of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $58 million through 2020 depending on the buyer’s actual use. At December 31, 2019, the Company has recorded a $46 million liability for the estimated future payments.
In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of the carrying value or fair value less costs to sell. Because the assets outside the full cost pool included in the Fayetteville Shale sale met the criteria for held for sale accounting as of September 30, 2018, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, a non-cash impairment charge of $161 million was recorded in the third quarter of 2018, of which $145 million related to midstream gathering assets held for sale and $15 million related to E&P assets held for sale. Additionally, the Company recorded a $1 million non-cash impairment related to other non-core assets that were not included in the sale.
From the proceeds received, $914 million was used to repurchase $900 million of the Company’s outstanding senior notes, including premiums and $9 million in accrued interest paid in December 2018. In addition, $201 million, including approximately $1 million in commissions, was used to repurchase approximately 44 million shares of the Company's outstanding common stock, including $21 million in the first quarter of 2019. The Company earmarked the remaining net proceeds from the sale to supplement 2019 and 2020 Appalachia development and for general corporate purposes. Pending these other uses, a portion of these remaining net proceeds has been used to repay revolving credit facility borrowings until investments are made.
During 2019, the Company sold non-core acreage for $38 million. There was no production or proved reserves associated with this acreage. In addition, during July 2019, the Company sold the land associated with its headquarters office building for $16 million and recognized a $2 million gain on the sale. The Company also from time to time sells leases and other properties whose value, individually, is not material but is reflected in the Company’s financial statements.
(4) LEASES
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. The codification was amended through additional ASUs. For public entities, Update 2016-02 became effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted ASC 842 with an effective date of January 1, 2019 using the modified retrospective approach for all leases that existed at the date of initial adoption. The Company elected to apply the transition as of the beginning of the period of adoption. For leases that existed at the period of adoption on January 1, 2019, the incremental borrowing rate as of the adoption date was used to calculate the present value of remaining lease payments.
The standard provides optional practical expedients to ease the burden of transition. The Company has adopted the following practical expedients through implementation:
•an election not to apply the recognition requirements in the leases standard to short-term leases and recognize lease payments in the consolidated statement of operations (a lease that at commencement date has an initial term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise);
•a package of practical expedients to not reassess: whether a contract is or contains a lease, lease classification and initial direct costs;
•a practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset class);
•a practical expedient to not reassess certain land easements in existence prior to January 1, 2019; and
•an election to adopt the modified retrospective approach for all leases existing at or entered into after the initial date of adoption which does not require a restatement of prior period. No cumulative-effect adjustment to retained earnings was required as a result of the modified retrospective approach.
Upon adoption of ASC 842, the Company recognized a discounted right-of-use asset and corresponding lease liability with opening balances of approximately $105 million as of January 1, 2019. The adoption of the standard did not materially change the Company’s consolidated statement of operations or its consolidated statement of cash flows.
The Company determines if a contract contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. A right-of-use asset and corresponding lease liability are recognized on the balance sheet at commencement at an amount based on the present value of the remaining lease payments over the lease term. As the implicit rate of the lease is not always readily determinable, the Company uses the incremental borrowing rate to calculate the present value of the lease payments based on information available at commencement date, such as the initial lease term. Operating right-of-use assets and operating lease liabilities are presented separately on the consolidated balance sheet. The Company does not have any finance leases as of December 31, 2019. By policy election, leases with an initial term of twelve months or less are not recorded on the balance sheet. The Company recognizes lease expense for these leases on a straight-line basis, and variable lease payments are recognized in the period as incurred.
Certain leases contain both lease and non-lease components. The Company has chosen to account for most of these leases as a single lease component instead of bifurcating lease and non-lease components. However, for compression service leases and fleet vehicle leases, the lease and non-lease components are accounted for separately.
The Company leases drilling rigs, pressure pumping equipment, vehicles, office space, certain water transportation lines, an aircraft and other equipment under non-cancelable operating leases expiring through 2032. Certain lease agreements include options to renew the lease, early terminate the lease or purchase the underlying asset(s). The Company determines the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. The Company’s water transportation lines are the only leases with renewal options that are reasonably certain to be exercised. These renewal options are reflected in the right-of-use asset and lease liability balances.
In July 2019, the Company terminated its existing lease agreement and entered into a new ten-year lease agreement for a smaller portion of the headquarters office building, which resulted in the Company making a $6 million residual value guarantee short-fall payment to the building’s previous lessor. The Company’s variable lease costs are primarily comprised of variable operating charges incurred in connection with the new building lease which are expected to continue throughout the lease term. There are currently no material residual value guarantees in the Company’s existing leases.
The components of lease costs are shown below:
|
|
|
|
|
|
|
For the year ended
|
(in millions)
|
December 31, 2019
|
Operating lease cost
|
$
|
45
|
|
Short-term lease cost
|
45
|
|
Variable lease cost
|
1
|
|
Total lease cost
|
$
|
91
|
|
As of December 31, 2019, the Company has operating leases of $15 million, related primarily to compressor and information technology leases, that have been executed but not yet commenced. These operating leases are planned to commence during 2020 with lease terms expiring through 2030. The Company’s existing operating leases do not contain any material restrictive covenants.
Supplemental cash flow information related to leases is set forth below:
|
|
|
|
|
|
|
For the year ended
|
(in millions)
|
December 31, 2019
|
Cash paid for amounts included in the measurement of lease liabilities:
|
|
Operating cash flows from operating leases
|
$
|
47
|
|
|
|
Right-of-use assets obtained in exchange for operating liabilities:
|
|
Operating leases
|
$
|
95
|
|
Supplemental balance sheet information related to leases is as follows:
|
|
|
|
|
|
(in millions)
|
December 31, 2019
|
Right-of-use asset balance:
|
|
|
Operating leases
|
$
|
159
|
|
Lease liability balance:
|
|
|
Current operating leases
|
$
|
34
|
|
Long-term operating leases
|
119
|
|
Total operating leases
|
$
|
153
|
|
|
|
Weighted average remaining lease term: (years)
|
|
Operating leases
|
6.6
|
|
|
Weighted average discount rate:
|
|
Operating leases
|
5.33
|
%
|
Maturity analysis of operating lease liabilities:
|
|
|
|
|
|
(in millions)
|
December 31, 2019
|
2020
|
$
|
41
|
|
2021
|
33
|
|
2022
|
22
|
|
2023
|
19
|
|
2024
|
15
|
|
Thereafter
|
52
|
|
Total undiscounted lease liability
|
182
|
|
Imputed interest
|
(29)
|
|
Total discounted lease liability
|
$
|
153
|
|
Undiscounted maturities of operating leases accounted for under ASC 840:
|
|
|
|
|
|
(in millions)
|
December 31, 2018
|
2019
|
$
|
38
|
|
2020
|
28
|
|
2021
|
14
|
|
2022
|
6
|
|
2023
|
5
|
|
Thereafter
|
4
|
|
Total minimum payments required
|
$
|
95
|
|
(5) REVENUE RECOGNITION
Effective January 1, 2018, the Company adopted ASC 606, “Revenue from Contracts with Customers,” using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Under the modified retrospective method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no material adjustment was required as a result of adopting ASC 606. Results for reporting periods beginning on January 1, 2018 are presented under the new revenue standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The
Company performed an analysis of the impact of adopting ASC 606 across all revenue streams and did not identify any changes to its revenue recognition policies that resulted in a material impact to its consolidated financial statements.
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 to 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. Production imbalances are generally recorded as receivables and payables and not contract assets or contract liabilities as the imbalances are between the Company and other working interest owners, not the end customer.
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 a market index 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 to which the Company has a right to invoice and has not disclosed information regarding its remaining performance obligations.
Gas gathering. Prior to the Fayetteville Shale sale in December 2018, the Company, through its midstream gathering affiliate, gathered natural gas pursuant to a variety of contracts with customers, including an affiliated E&P company. The performance obligations for gas gathering services included delivery of each unit of natural gas to the designated delivery point, which may include treating of certain natural gas units to meet interstate pipeline specifications. Revenue was recognized at the point in time when performance obligations were fulfilled. Under the Company’s gathering contracts, customers were invoiced and revenue was recognized each month based on the volume of natural gas transported and treated at a contractually agreed upon price per unit. Payment terms were typically within 30 to 60 days of completion of the performance obligations. Furthermore, consideration from a customer corresponded directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognized revenue in the amount to which the Company had a right to invoice and had not disclosed information regarding its remaining performance obligations. Any imbalances were settled on a monthly basis by cashing-out with the respective shipper. Accordingly, there were no contract assets or contract liabilities related to the Company’s gas gathering revenues.
Disaggregation of Revenues
The Company presents a disaggregation of E&P revenues by product in 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&P
|
|
Marketing
|
|
Intersegment
Revenues
|
|
Total
|
Year ended December 31, 2019
|
|
|
|
|
|
|
|
Gas sales
|
$
|
1,207
|
|
|
$
|
—
|
|
|
$
|
34
|
|
|
$
|
1,241
|
|
Oil sales
|
220
|
|
|
—
|
|
|
3
|
|
|
223
|
|
NGL sales
|
274
|
|
|
—
|
|
|
—
|
|
|
274
|
|
Marketing
|
—
|
|
|
2,849
|
|
|
(1,552)
|
|
|
1,297
|
|
Other (1)
|
2
|
|
|
1
|
|
|
—
|
|
|
3
|
|
Total
|
$
|
1,703
|
|
|
$
|
2,850
|
|
|
$
|
(1,515)
|
|
|
$
|
3,038
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
$
|
1,974
|
|
|
$
|
—
|
|
|
$
|
24
|
|
|
$
|
1,998
|
|
Oil sales
|
193
|
|
|
—
|
|
|
3
|
|
|
196
|
|
NGL sales
|
353
|
|
|
—
|
|
|
(1)
|
|
|
352
|
|
Marketing
|
—
|
|
|
3,497
|
|
|
(2,275)
|
|
|
1,222
|
|
Gas gathering (2)
|
—
|
|
|
248
|
|
|
(159)
|
|
|
89
|
|
Other (1)
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
Total
|
$
|
2,525
|
|
|
$
|
3,745
|
|
|
$
|
(2,408)
|
|
|
$
|
3,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
Gas sales
|
$
|
1,775
|
|
|
$
|
—
|
|
|
$
|
18
|
|
|
$
|
1,793
|
|
Oil sales
|
101
|
|
|
—
|
|
|
1
|
|
|
102
|
|
NGL sales
|
206
|
|
|
—
|
|
|
—
|
|
|
206
|
|
Marketing
|
—
|
|
|
2,867
|
|
|
(1,895)
|
|
|
972
|
|
Gas gathering (2)
|
—
|
|
|
331
|
|
|
(205)
|
|
|
126
|
|
Other (1)
|
4
|
|
|
|
—
|
|
|
|
—
|
|
|
|
4
|
|
Total
|
$
|
2,086
|
|
|
$
|
3,198
|
|
|
$
|
(2,081)
|
|
|
$
|
3,203
|
|
(1)Other E&P revenues consists primarily of water sales to third-party operators and other marketing revenues consists primarily of sales of gas from storage.
(2)The Company’s gas gathering assets were divested in December 2018 as part of the Fayetteville Shale sale.
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 in Pennsylvania and West Virginia. In December 2018, the Company sold 100% of its Fayetteville Shale assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Northeast Appalachia
|
$
|
964
|
|
|
|
$
|
1,165
|
|
|
|
$
|
837
|
|
Southwest Appalachia
|
736
|
|
|
|
817
|
|
|
|
498
|
|
Fayetteville Shale
|
—
|
|
|
|
537
|
|
|
|
743
|
|
Other
|
3
|
|
|
|
6
|
|
|
|
8
|
|
Total
|
$
|
1,703
|
|
|
|
$
|
2,525
|
|
|
|
$
|
2,086
|
|
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)
|
December 31, 2019
|
|
December 31, 2018
|
Receivables from contracts with customers
|
$
|
284
|
|
|
$
|
494
|
|
Other accounts receivable
|
61
|
|
|
87
|
|
Total accounts receivable
|
$
|
345
|
|
|
$
|
581
|
|
Amounts recognized against the Company’s allowance for doubtful accounts related to receivables arising from contracts with customers were immaterial for the years ended December 31, 2019 and 2018. The Company has no contract assets or contract liabilities associated with its revenues from contracts with customers.
(6) DERIVATIVES AND 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 December 31, 2019, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, call options and interest rate swaps. A description of the Company’s derivative financial instruments is provided below:
|
|
|
|
|
|
Fixed price swaps
|
If the Company sells a fixed price swap, the Company receives a fixed price for the contract and pays a floating market to the counterparty. If the Company purchases a fixed price swap, the Company receives a floating market price for the contract and pays a fixed price to the counterparty.
|
Two-way costless collars
|
Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call 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, 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. If 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 state terms of the contract and receives a payment from the counterparty if the price differential is less than the stated terms of the contract.
|
Call options
|
The Company purchases and sells call options in exchange for a premium. If the Company purchases a call option, the Company receives from 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 sells a call option, the Company pays the counterparty the excess (if any) of the market price over the strike price at the time of settlement, but if the market price is below the call’s strike price, no payment is due from either party.
|
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.
|
The Company chooses counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company actively monitors the 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 derivative positions on a gross basis and does not net the asset and liability positions.
As part of the Fayetteville Shale sale agreement, the Company entered into certain natural gas derivative positions that were subsequently novated to the buyer in conjunction with finalization of the sale. The derivatives that were novated to the buyer are not included in the tables below.
The following tables 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 tables present the notional amount, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2019:
Financial Protection on Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per MMBtu
|
|
|
|
|
|
|
|
|
|
Fair value at December 31, 2019
($ in millions)
|
|
|
Volume
(Bcf)
|
|
Swaps
|
|
Sold Puts
|
|
Purchased Puts
|
|
Sold Calls
|
|
Basis Differential
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
280
|
|
|
$
|
2.51
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
76
|
|
(1)
|
Two-way costless collars
|
31
|
|
|
—
|
|
|
—
|
|
|
2.56
|
|
|
2.85
|
|
|
—
|
|
|
6
|
|
|
Three-way costless collars
|
185
|
|
|
—
|
|
|
2.28
|
|
|
2.65
|
|
|
3.00
|
|
|
—
|
|
|
42
|
|
|
Total
|
496
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
124
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
30
|
|
|
$
|
2.54
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
7
|
|
|
Two-way costless collars
|
17
|
|
|
|
—
|
|
|
—
|
|
|
2.50
|
|
|
2.83
|
|
|
—
|
|
|
—
|
|
|
Three-way costless collars
|
213
|
|
|
—
|
|
|
2.23
|
|
|
2.53
|
|
|
2.90
|
|
|
—
|
|
|
—
|
|
|
Total
|
260
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7
|
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three-way costless collars
|
31
|
|
|
$
|
—
|
|
|
$
|
2.30
|
|
|
$
|
2.69
|
|
|
$
|
3.15
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
198
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.31)
|
|
|
$
|
—
|
|
|
2021
|
86
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.04
|
|
|
7
|
|
|
2022
|
45
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(0.50)
|
|
|
(1)
|
|
|
|
Total
|
329
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
6
|
|
|
(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per Bbl
|
|
|
|
|
|
|
|
Fair value at December 31, 2019
($ in millions)
|
|
Volume
(MBbls)
|
|
Swaps
|
|
Sold Puts
|
|
Purchased Puts
|
|
Sold Calls
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
3,465
|
|
|
|
$
|
57.83
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
(2)
|
|
Two-way costless collars
|
966
|
|
|
|
—
|
|
|
—
|
|
|
|
56.89
|
|
|
59.81
|
|
|
|
—
|
|
Three-way costless collars
|
971
|
|
|
|
—
|
|
|
45.12
|
|
|
|
55.12
|
|
|
59.68
|
|
|
|
(1)
|
|
Total
|
5,402
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3)
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
1,584
|
|
|
|
$
|
53.20
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
(1)
|
|
Three-way costless collars
|
1,445
|
|
|
|
—
|
|
|
43.52
|
|
|
|
53.25
|
|
|
58.14
|
|
|
|
(1)
|
|
Total
|
3,029
|
|
|
|
|
|
|
|
|
|
|
$
|
(2)
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
438
|
|
|
|
$
|
51.74
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
4,746
|
|
|
|
$
|
23.90
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
21
|
|
Two-way costless collars
|
366
|
|
|
|
—
|
|
|
|
—
|
|
|
|
25.20
|
|
|
|
29.40
|
|
|
2
|
|
Total
|
5,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
2,460
|
|
|
|
$
|
21.77
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
—
|
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ethane
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
7,520
|
|
|
|
$
|
8.84
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
11
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
2,410
|
|
|
|
$
|
7.53
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Derivative Contracts
|
|
|
|
|
|
|
Volume
(Bcf)
|
|
Weighted Average Strike Price per MMBtu
|
|
Fair value at December 31, 2019
($ in millions)
|
Purchased Call Options – Natural Gas
|
|
|
|
|
|
2020
|
104
|
|
|
$
|
3.46
|
|
|
$
|
1
|
|
2021
|
57
|
|
|
3.52
|
|
|
2
|
|
Total
|
161
|
|
|
|
|
$
|
3
|
|
|
|
|
|
|
|
Sold Call Options – Natural Gas
|
|
|
|
|
|
2020
|
173
|
|
|
$
|
3.24
|
|
|
$
|
(3)
|
|
2021
|
115
|
|
|
3.33
|
|
|
(6)
|
|
2022
|
58
|
|
|
3.00
|
|
|
(5)
|
|
2023
|
6
|
|
|
3.00
|
|
|
(1)
|
|
2024
|
9
|
|
|
3.00
|
|
|
(3)
|
|
Total
|
361
|
|
|
|
|
$
|
(18)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(MBbls)
|
|
Weighted Average Strike Price per Bbl
|
|
Fair value at December 31, 2019
($ in millions)
|
Sold Call Options – Oil
|
|
|
|
|
|
2021
|
—
|
|
|
$
|
60.00
|
|
|
$
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Strike Price per MMBtu
|
|
|
|
Fair value at
December 31, 2019
($ in millions)
|
Natural Gas Storage (1)
|
Volume (Bcf)
|
|
Swaps
|
|
Basis Differential
|
|
|
2020
|
|
|
|
|
|
|
|
Purchased fixed price swap
|
—
|
|
|
$
|
2.37
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Purchased basis swap
|
—
|
|
|
—
|
|
|
(0.32)
|
|
|
—
|
|
Sold fixed price swap
|
1
|
|
|
3.06
|
|
|
—
|
|
|
1
|
|
Sold basis swap
|
—
|
|
|
—
|
|
|
(0.32)
|
|
|
—
|
|
Total
|
1
|
|
|
|
|
|
|
$
|
1
|
|
(1)The Company has entered into certain derivatives to protect the value of volumes of natural gas injected into a storage facility that will be withdrawn at a later date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(Bcf)
|
|
Weighted Average Strike Price per MMBtu
|
|
Fair value at December 31, 2019
($ in millions)
|
Purchased Fixed Price Swaps – Marketing (Natural Gas) (1)
|
|
|
|
|
|
2020
|
7
|
|
|
$
|
2.44
|
|
|
$
|
(1)
|
|
2021
|
6
|
|
|
2.44
|
|
|
—
|
|
Total
|
13
|
|
|
|
|
$
|
(1)
|
|
(1)The Company has entered into a limited number of derivatives to protect the value of certain long-term sales contracts.
At December 31, 2019, the net fair value of the Company’s financial instruments related to commodities was a $155 million asset.
As of December 31, 2019, 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 consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement 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. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives on the consolidated statements of operations.
The balance sheet classification of the assets and liabilities related to derivative financial instruments are summarized below as of December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets
|
|
|
|
|
|
|
Balance Sheet Classification
|
|
Fair Value
|
|
|
(in millions)
|
|
|
December 31, 2019
|
|
December 31, 2018
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
Fixed price swap – natural gas
|
Derivative assets
|
|
$
|
77
|
|
(1)
|
$
|
32
|
|
Fixed price swap – oil
|
Derivative assets
|
|
4
|
|
|
13
|
|
Fixed price swap – propane
|
Derivative assets
|
|
21
|
|
|
11
|
|
Fixed price swap – ethane
|
Derivative assets
|
|
11
|
|
|
7
|
|
Two-way costless collar – natural gas
|
Derivative assets
|
|
10
|
|
|
11
|
|
Two-way costless collar – oil
|
Derivative assets
|
|
5
|
|
|
6
|
|
Two-way costless collar – propane
|
Derivative assets
|
|
2
|
|
|
—
|
|
Three-way costless collar – natural gas
|
Derivative assets
|
|
126
|
|
|
41
|
|
Three-way costless collar – oil
|
Derivative assets
|
|
3
|
|
|
—
|
|
Basis swap – natural gas
|
Derivative assets
|
|
17
|
|
|
8
|
|
Purchased call option – natural gas
|
Derivative assets
|
|
1
|
|
|
—
|
|
Fixed price swap – natural gas storage
|
Derivative assets
|
|
1
|
|
|
—
|
|
Interest rate swap
|
Derivative assets
|
|
—
|
|
|
1
|
|
Fixed price swap – natural gas
|
Other long-term assets
|
|
7
|
|
|
6
|
|
Fixed price swap – oil
|
Other long-term assets
|
|
1
|
|
|
6
|
|
Fixed price swap – propane
|
Other long-term assets
|
|
3
|
|
|
—
|
|
Fixed price swap – ethane
|
Other long-term assets
|
|
—
|
|
|
1
|
|
Two-way costless collar – natural gas
|
Other long-term assets
|
|
4
|
|
|
—
|
|
Two-way costless collar – oil
|
Other long-term assets
|
|
—
|
|
|
5
|
|
Three-way costless collar – natural gas
|
Other long-term assets
|
|
74
|
|
|
34
|
|
Three-way costless collar – oil
|
Other long-term assets
|
|
7
|
|
|
—
|
|
Basis swap – natural gas
|
Other long-term assets
|
|
15
|
|
|
3
|
|
Purchased call options – natural gas
|
Other long-term assets
|
|
2
|
|
|
6
|
|
Total derivative assets
|
|
|
$
|
391
|
|
|
$
|
191
|
|
(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statements of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities
|
|
|
|
|
|
|
Balance Sheet Classification
|
|
Fair Value
|
|
|
(in millions)
|
|
|
December 31, 2019
|
|
December 31, 2018
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
Purchased fixed price swap – natural gas
|
Derivative liabilities
|
|
$
|
1
|
|
|
$
|
—
|
|
Purchased fixed price swap – oil
|
Derivative liabilities
|
|
—
|
|
|
6
|
|
Fixed price swap – natural gas
|
Derivative liabilities
|
|
1
|
|
|
9
|
|
Fixed price swap – oil
|
Derivative liabilities
|
|
6
|
|
|
—
|
|
Fixed price swap – ethane
|
Derivative liabilities
|
|
—
|
|
|
3
|
|
Two-way costless collar – natural gas
|
Derivative liabilities
|
|
4
|
|
|
7
|
|
Two-way costless collar – oil
|
Derivative liabilities
|
|
5
|
|
|
—
|
|
Three-way costless collar – natural gas
|
Derivative liabilities
|
|
84
|
|
|
33
|
|
Three-way costless collar – oil
|
Derivative liabilities
|
|
4
|
|
|
—
|
|
Basis swap – natural gas
|
Derivative liabilities
|
|
17
|
|
|
18
|
|
Sold call option – natural gas
|
Derivative liabilities
|
|
3
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swap – natural gas
|
Other long-term liabilities
|
|
—
|
|
|
1
|
|
Fixed price swap – oil
|
Other long-term liabilities
|
|
2
|
|
|
—
|
|
Two-way costless collar – natural gas
|
Other long-term liabilities
|
|
4
|
|
|
—
|
|
Two-way costless collar – oil
|
Other long-term liabilities
|
|
—
|
|
|
1
|
|
Three-way costless collar – natural gas
|
Other long-term liabilities
|
|
72
|
|
|
35
|
|
Three-way costless collar – oil
|
Other long-term liabilities
|
|
8
|
|
|
—
|
|
Basis swap – natural gas
|
Other long-term liabilities
|
|
9
|
|
|
4
|
|
Sold call option – natural gas
|
Other long-term liabilities
|
|
15
|
|
|
19
|
|
Sold call option – oil
|
Other long-term liabilities
|
|
1
|
|
|
—
|
|
Total derivative liabilities
|
|
|
$
|
236
|
|
|
$
|
139
|
|
The following tables summarize the before-tax effect of the Company’s derivative instruments on the consolidated statements of operations for the years ended December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unsettled Gain (Loss) on Derivatives Recognized in Earnings
|
|
|
|
|
|
|
|
|
|
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Unsettled
|
|
For the years ended
December 31,
|
|
|
|
Derivative Instrument
|
|
|
|
2019
|
|
2018
|
|
|
|
|
|
(in millions)
|
|
|
|
Purchased fixed price swap – natural gas
|
|
Gain (Loss) on Derivatives
|
|
$
|
(1)
|
|
|
$
|
—
|
|
|
Purchased fixed price swap – oil
|
|
Gain (Loss) on Derivatives
|
|
6
|
|
|
(6)
|
|
|
Fixed price swap – natural gas
|
|
Gain (Loss) on Derivatives
|
|
46
|
|
|
(27)
|
|
|
Fixed price swap – oil
|
|
Gain (Loss) on Derivatives
|
|
(22)
|
|
|
19
|
|
|
Fixed price swap – propane
|
|
Gain (Loss) on Derivatives
|
|
13
|
|
|
11
|
|
|
Fixed price swap – ethane
|
|
Gain (Loss) on Derivatives
|
|
6
|
|
|
5
|
|
|
Two-way costless collar – natural gas
|
|
Gain (Loss) on Derivatives
|
|
2
|
|
|
—
|
|
|
Two-way costless collar – oil
|
|
Gain (Loss) on Derivatives
|
|
(10)
|
|
|
10
|
|
|
Two-way costless collar – propane
|
|
Gain (Loss) on Derivatives
|
|
2
|
|
|
—
|
|
|
Three-way costless collar – natural gas
|
|
Gain (Loss) on Derivatives
|
|
37
|
|
|
(48)
|
|
|
Three-way costless collar – oil
|
|
Gain (Loss) on Derivatives
|
|
(2)
|
|
|
—
|
|
|
Basis swap – natural gas
|
|
Gain (Loss) on Derivatives
|
|
17
|
|
|
10
|
|
|
Purchased call option – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(3)
|
|
|
4
|
|
|
Sold call option – natural gas
|
|
Gain (Loss) on Derivatives
|
|
4
|
|
|
(4)
|
|
|
Sold call option – oil
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
—
|
|
|
Fixed price swap – natural gas storage
|
|
Gain (Loss) on Derivatives
|
|
1
|
|
|
—
|
|
|
Interest rate swap
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
2
|
|
|
Total gain (loss) on unsettled derivatives
|
|
|
|
$
|
94
|
|
|
$
|
(24)
|
|
|
|
|
|
|
|
|
|
|
Settled Gain (Loss) on Derivatives Recognized in Earnings (1)
|
|
|
|
|
|
|
|
|
|
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Settled
|
|
For the years ended
December 31,
|
|
|
|
Derivative Instrument
|
|
|
|
2019
|
|
2018
|
|
|
|
|
|
(in millions)
|
|
|
|
Purchased fixed price swap – oil
|
|
Gain (Loss) on Derivatives
|
|
$
|
(3)
|
|
|
$
|
—
|
|
|
Fixed price swap – natural gas
|
|
Gain (Loss) on Derivatives
|
|
78
|
|
|
(32)
|
|
|
Fixed price swap – oil
|
|
Gain (Loss) on Derivatives
|
|
10
|
|
|
—
|
|
|
Fixed price swap – propane
|
|
Gain (Loss) on Derivatives
|
|
29
|
|
|
(6)
|
|
|
Fixed price swap – ethane
|
|
Gain (Loss) on Derivatives
|
|
17
|
|
|
(8)
|
|
|
Two-way costless collar – natural gas
|
|
Gain (Loss) on Derivatives
|
|
16
|
|
|
(1)
|
|
|
Two-way costless collar – oil
|
|
Gain (Loss) on Derivatives
|
|
6
|
|
|
—
|
|
|
Two-way costless collar – propane
|
|
Gain (Loss) on Derivatives
|
|
2
|
|
|
—
|
|
|
Three-way costless collar – natural gas
|
|
Gain (Loss) on Derivatives
|
|
31
|
|
|
(9)
|
|
|
Basis swap – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(3)
|
|
|
(31)
|
|
|
Purchased call option – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
(2)
|
2
|
|
(2)
|
Sold call option – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
(7)
|
|
|
Sold call option – oil
|
|
Gain (Loss) on Derivatives
|
|
—
|
|
|
(2)
|
|
|
Purchased fixed price swap – natural gas storage
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
—
|
|
|
Total gain (loss) on settled derivatives
|
|
|
|
$
|
180
|
|
|
$
|
(94)
|
|
|
|
|
|
|
|
|
|
|
Total gain (loss) on derivatives
|
|
|
|
$
|
274
|
|
|
$
|
(118)
|
|
|
(1)The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.
(2)Includes $1 million amortization of premiums paid related to certain natural gas purchased call options for each of the years ended December 31, 2019 and 2018, which is included in gain (loss) on derivatives on the consolidated statement of operations.
(7) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
In 2019, changes in AOCI primarily related to settlements in the Company's pension and other postretirement benefits. The following tables detail the components of accumulated other comprehensive income (loss) and the related tax effects, for the year ended December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2019
|
|
|
|
|
(in millions)
|
Pension and Other Postretirement
|
|
Foreign Currency
|
|
Total
|
Beginning balance, December 31, 2018
|
$
|
(22)
|
|
|
$
|
(14)
|
|
|
$
|
(36)
|
|
Other comprehensive loss before reclassifications
|
(5)
|
|
|
—
|
|
|
(5)
|
|
Amounts reclassified from other comprehensive income (1)
|
8
|
|
|
—
|
|
|
8
|
|
Net current-period other comprehensive income
|
3
|
|
|
—
|
|
|
3
|
|
Ending balance, December 31, 2019
|
$
|
(19)
|
|
|
$
|
(14)
|
|
|
$
|
(33)
|
|
(1)See separate table below for details about these reclassifications.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Details about Accumulated Other
Comprehensive Income
|
|
Affected Line Item in the
Consolidated Statement of Operations
|
|
Amount Reclassified from/to Accumulated Other Comprehensive Income
|
|
|
|
|
For the year ended December 31, 2019
|
Pension and other postretirement:
|
|
|
|
(in millions)
|
Amortization of prior service cost and net loss (1)
|
|
Other Income, Net
|
|
$
|
10
|
|
|
|
Provision for income taxes
|
|
(2)
|
|
|
|
Net income
|
|
$
|
8
|
|
|
|
|
|
|
Total reclassifications for the period
|
|
Net income
|
|
$
|
8
|
|
(1)See Note 13 for additional details regarding the Company’s pension and other postretirement benefit plans.
(8) FAIR VALUE MEASUREMENTS
Assets and liabilities measured at fair value on a recurring basis
The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2019 and 2018 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
|
December 31, 2018
|
|
|
(in millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
Cash and cash equivalents
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
201
|
|
|
$
|
201
|
|
2018 revolving credit facility due April 2024 (1)
|
34
|
|
|
34
|
|
|
—
|
|
|
—
|
|
Senior notes (2)
|
2,228
|
|
|
2,085
|
|
|
2,342
|
|
|
2,190
|
|
Derivative instruments, net
|
155
|
|
(3)
|
155
|
|
(3)
|
52
|
|
|
|
52
|
|
(1)In October 2019, the Company amended its 2018 revolving credit facility agreement which, among other things, extended the maturity from 2023 to 2024.
(2)Excludes unamortized debt issuance costs and debt discounts.
(3)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet.
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 were 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. These instruments were previously classified as a Level 2 measurement but certain senior notes were updated to a Level 1 in the second quarter of 2018 as the market activity for a portion of the Company’s debt resulted in timely quoted prices. In 2019, the 4.10% Senior Notes due March 2022 were reclassified as a Level 2 measurement due to relative market inactivity. The 4.05% Senior Notes due January 2020, which were classified as a Level 2 measurement at December 31, 2018, were retired in December 2019.
The carrying value of the borrowings under the Company’s revolving credit facility (to the extent utilized) approximates fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its revolving credit facility to be a Level 1 measurement on the fair value hierarchy.
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 Company has classified its derivatives into the fair value hierarchy 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 New York Mercantile Exchange (“NYMEX”) futures index for natural gas and oil derivatives and Oil Price Information Service (“OPIS”) for ethane and propane derivatives. The Company utilizes 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 December 31, 2019 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’s interest rate derivative contracts expire in June 2020.
The Company’s call options, two-way costless collars and three-way costless collars (Level 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 2) are estimated using third-party calculations based upon forward commodity price curves. These instruments were previously classified as a Level 3 measurement in the fair value hierarchy but were updated to a Level 2 measurement in the second quarter of 2018 as a result of the Company’s ability to derive volatility inputs and forward commodity price curves from directly observable sources.
Inputs to the Black-Scholes model, including the volatility input 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.
Assets and liabilities measured at fair value on a recurring basis are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
|
|
|
|
|
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 swap – natural gas (1)
|
$
|
—
|
|
|
$
|
84
|
|
|
$
|
—
|
|
|
$
|
84
|
|
Fixed price swap – oil
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
Fixed price swap – propane
|
—
|
|
|
24
|
|
|
—
|
|
|
24
|
|
Fixed price swap – ethane
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Two-way costless collar – natural gas
|
—
|
|
|
14
|
|
|
—
|
|
|
14
|
|
Two-way costless collar – oil
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
Two-way costless collar – propane
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Three-way costless collar – natural gas
|
—
|
|
|
200
|
|
|
—
|
|
|
200
|
|
Three-way costless collar – oil
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
Basis swap – natural gas
|
—
|
|
|
32
|
|
|
—
|
|
|
32
|
|
Purchased call option – natural gas
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Fixed price swap – natural gas storage
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Purchased fixed price swap – natural gas
|
—
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Fixed price swap – natural gas
|
—
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Fixed price swap – oil
|
—
|
|
|
(8)
|
|
|
—
|
|
|
(8)
|
|
Two-way costless collar – natural gas
|
—
|
|
|
(8)
|
|
|
—
|
|
|
(8)
|
|
Two-way costless collar – oil
|
—
|
|
|
(5)
|
|
|
—
|
|
|
(5)
|
|
Three-way costless collar – natural gas
|
—
|
|
|
(156)
|
|
|
—
|
|
|
(156)
|
|
Three-way costless collar – oil
|
—
|
|
|
(12)
|
|
|
—
|
|
|
(12)
|
|
Basis swap – natural gas
|
—
|
|
|
(26)
|
|
|
—
|
|
|
(26)
|
|
Sold call option – natural gas
|
—
|
|
|
(18)
|
|
|
—
|
|
|
(18)
|
|
Sold call option – oil
|
—
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Total
|
$
|
—
|
|
|
$
|
155
|
|
|
$
|
—
|
|
|
$
|
155
|
|
(1)Includes $9 million in premiums paid related to certain natural gas fixed price swaps recognized as a component of derivative assets within current assets on the consolidated balance sheet at December 31, 2019. As certain natural gas fixed price swaps settle, the premium will be amortized and recognized as a component of gain (loss) on derivatives on the consolidated statement of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
|
|
|
|
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 swap – natural gas
|
$
|
—
|
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
38
|
|
Fixed price swap – oil
|
—
|
|
|
19
|
|
|
—
|
|
|
19
|
|
Fixed price swap – propane
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Fixed price swap – ethane
|
—
|
|
|
8
|
|
|
—
|
|
|
8
|
|
Two-way costless collar – natural gas
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Two-way costless collar – oil
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Three-way costless collar – natural gas
|
—
|
|
|
75
|
|
|
—
|
|
|
75
|
|
Basis swaps – natural gas
|
—
|
|
|
11
|
|
|
—
|
|
|
11
|
|
Purchased call option – natural gas
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
Interest rate swap
|
—
|
|
|
|
1
|
|
|
|
—
|
|
|
|
1
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Purchased fixed price swap – oil
|
—
|
|
|
(6)
|
|
|
—
|
|
|
(6)
|
|
Fixed price swap – natural gas
|
—
|
|
|
(10)
|
|
|
—
|
|
|
(10)
|
|
Fixed price swap – ethane
|
—
|
|
|
(3)
|
|
|
—
|
|
|
(3)
|
|
Two-way costless collar – natural gas
|
—
|
|
|
(7)
|
|
|
—
|
|
|
(7)
|
|
Two-way costless collar – oil
|
—
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Three-way costless collar – natural gas
|
—
|
|
|
(68)
|
|
|
—
|
|
|
(68)
|
|
Basis swap – natural gas
|
—
|
|
|
(22)
|
|
|
—
|
|
|
(22)
|
|
Sold call option – natural gas
|
—
|
|
|
(22)
|
|
|
—
|
|
|
(22)
|
|
Total
|
$
|
—
|
|
|
$
|
52
|
|
|
$
|
—
|
|
|
$
|
52
|
|
The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2019 and 2018. The fair values of Level 3 derivative instruments were estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consisted of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflected reasonable assumptions a marketplace participant would have used as of December 31, 2019 and 2018. Commodity derivatives previously presented as Level 3 were transferred to Level 2 in the second quarter of 2018 as the Company moved from using proprietary volatility inputs and forward curves to more widely available published information, increasing market observability.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
(in millions)
|
2019
|
|
2018
|
Balance at beginning of year
|
$
|
—
|
|
|
$
|
22
|
|
Total gains (losses):
|
|
|
|
Included in earnings
|
—
|
|
|
(17)
|
|
Settlements (1)
|
—
|
|
|
1
|
|
Transfers into/out of Level 3 (2)
|
—
|
|
|
(6)
|
|
Balance at end of period
|
$
|
—
|
|
|
$
|
—
|
|
Change in gains (losses) included in earnings relating to derivatives still held as of December 31
|
$
|
—
|
|
|
$
|
—
|
|
(1)Includes $1 million for amortization of premiums paid related to certain natural gas purchased call options for the year ended December 31, 2018.
(2)Commodity derivatives previously presented as Level 3 were transferred to Level 2 in the second quarter of 2018 as the Company moved from using proprietary volatility inputs and forward curves to more widely available published information, increasing market observability.
See Note 13 for a discussion of the fair value measurement of the Company’s pension plan assets.
Assets and liabilities measured at fair value on a nonrecurring basis
In accordance with accounting guidance for Property, Plant and Equipment, assets held for sale are measured at the lower of carrying value or fair value less costs to sell. Because the assets outside of the full cost pool included in the Fayetteville Shale sale met the criteria for held for sale accounting in the third quarter of 2018, the Company determined the carrying value of certain non-full cost pool assets exceeded the fair value less costs to sell. As a result, the Company recorded a non-cash
impairment charge of $161 million for the year ended December 31, 2018, of which $145 million related to midstream gathering assets and $15 million related to E&P which were both reflected as assets held for sale in the third quarter of 2018. Additionally, the Company recorded a $1 million non-cash impairment related to other non-core assets that were not included in the sale. The estimated fair value of the gathering assets was based on an estimated discounted cash flow model and market assumptions. The significant Level 3 assumptions used in the calculation of estimated discounted cash flows included future commodity prices, projections of estimated quantities of natural gas reserves, operating costs, projections of future rates of production, inflation factors and risk adjusted discount rates. In 2019, the Company determined that the $26 million carrying value of certain non-core assets exceeded their respective fair value less costs to sell and recognized a $16 million non-cash impairment. The Company used Level 3 measurements to determine the fair value of these assets.
(9) DEBT
The components of debt as of December 31, 2019 and 2018 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
|
|
|
|
(in millions)
|
Debt Instrument
|
|
Unamortized Issuance Expense
|
|
Unamortized
Debt Discount
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
Variable rate (4.310% at December 31, 2019) 2018 revolving credit facility, due April 2024
|
$
|
34
|
|
|
$
|
—
|
|
(1)
|
$
|
—
|
|
|
$
|
34
|
|
4.10% Senior Notes due March 2022
|
213
|
|
|
(1)
|
|
|
—
|
|
|
212
|
|
4.95% Senior Notes due January 2025 (2)
|
892
|
|
|
(5)
|
|
|
(1)
|
|
|
886
|
|
7.50% Senior Notes due April 2026
|
639
|
|
|
(7)
|
|
|
—
|
|
|
632
|
|
7.75% Senior Notes due October 2027
|
484
|
|
|
(6)
|
|
|
—
|
|
|
478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
$
|
2,262
|
|
|
$
|
(19)
|
|
|
$
|
(1)
|
|
|
$
|
2,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
|
|
|
(in millions)
|
Debt Instrument
|
|
Unamortized Issuance Expense
|
|
Unamortized Debt Discount
|
|
Total
|
Long-term debt:
|
|
|
|
|
|
|
|
Variable rate (3.920% at December 31, 2018) 2018 term loan facility, due April 2023
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
$
|
—
|
|
|
$
|
—
|
|
4.05% Senior Notes due January 2020 (2)
|
52
|
|
|
—
|
|
|
—
|
|
|
52
|
|
4.10% Senior Notes due March 2022
|
213
|
|
|
(1)
|
|
|
—
|
|
|
212
|
|
4.95% Senior Notes due January 2025 (2)
|
927
|
|
|
(7)
|
|
|
(1)
|
|
|
919
|
|
7.50% Senior Notes due April 2026
|
650
|
|
|
(8)
|
|
|
—
|
|
|
642
|
|
7.75% Senior Notes due October 2027
|
500
|
|
|
(7)
|
|
|
—
|
|
|
493
|
|
Total long-term debt
|
$
|
2,342
|
|
|
$
|
(23)
|
|
|
$
|
(1)
|
|
|
$
|
2,318
|
|
(1)At December 31, 2019 and 2018, unamortized issuance expense of $11 million associated with the 2018 revolving credit facility was classified as other long-term assets on the consolidated balance sheet.
(2)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 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. S&P and Moody’s upgraded certain senior notes in April and May 2018, respectively. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to the bondholders at the lower interest rate was paid in January 2019.
The following is a summary of scheduled debt maturities by year as of December 31, 2019:
|
|
|
|
|
|
(in millions)
|
|
2020
|
$
|
—
|
|
2021
|
—
|
|
2022
|
213
|
|
2023
|
—
|
|
2024 (1)
|
34
|
|
Thereafter
|
2,015
|
|
|
$
|
2,262
|
|
(1)The Company’s current revolving credit facility matures in 2024.
Credit Facilities
2016 Credit Facility
In June 2016, the Company reduced its $2.0 billion unsecured revolving credit facility entered into in December 2013 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, maturing in December 2020.
Concurrent with the closing of the 2018 credit facility agreement in April 2018, the Company repaid the $1,191 million secured term loan balance and recognized a loss on early debt extinguishment of $8 million on the consolidated income statement related to the unamortized issuance expense. In addition, approximately $4 million of unamortized issuance expense associated with the closed $743 million revolving credit facility was carried forward into the unamortized issuance expenses of the 2018 credit facility.
2018 Credit Facility
In April 2018, the Company replaced its credit facility entered into in 2016 with a new revolving credit facility (the “2018 credit facility”). The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion with a current aggregate commitment of $2.0 billion and borrowing base (limit on availability) that is redetermined at least each April and October. The 2018 credit facility is secured by substantially all of the assets owned by the Company and its subsidiaries. The permitted lien provisions in the senior notes indentures currently limit liens securing indebtedness to the greater of $2.0 billion and 25% of adjusted consolidated net tangible assets. On October 8, 2019, the Company entered into an amendment to the 2018 credit facility that, among other things, established the October 2019 borrowing base at $2.1 billion and extended the maturity date to April 2024.
Loans under the 2018 credit facility 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 for such interest period plus the applicable margin (as those terms are defined in the 2018 credit facility documentation). The applicable margin for Eurodollar loans under the 2018 credit facility ranges from 1.50% to 2.50% based on the Company’s utilization of the borrowing base under the 2018 credit facility. Alternate base rate loans bear interest at the alternate base rate plus the applicable margin. The applicable margin for alternate base rate loans under the 2018 credit facility ranges from 0.50% to 1.50% based on the Company’s utilization of the borrowing base under the 2018 credit facility.
The 2018 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, transactions with affiliates, or change of principal business; and
•maintenance of the following financial covenants, commencing with the fiscal quarter ended June 30, 2018:
(1)Minimum current ratio of no 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 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 no greater than (i) with respect to each fiscal quarter ending during the period from June 30, 2018 through March 31, 2019, 4.50 to 1.00, (ii) with respect to each fiscal quarter ending during the period from June 30, 2019 through March 31, 2020, 4.25 to 1.00, and (iii) with respect to each fiscal quarter ending on or after June 30, 2020, 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 Company’s 2018 credit agreement, 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 2018 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 2018 credit facility may become immediately due and payable. As of December 31, 2019, the Company was in compliance with all of the covenants of the credit agreement in all material respects.
Each United States domestic subsidiary of the Company for which the Company owns 100% of its equity guarantees the 2018 credit facility. Pursuant to requirements under the indentures governing its senior notes, each subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes. See Note 16 for the Company’s Condensed Consolidated Financial Information, presented in accordance with Rule 3-10 of Regulation S-X.
As of December 31, 2019, the Company had $172 million in letters of credit and $34 million in borrowings outstanding under the 2018 credit facility.
Senior Notes
In January 2015, the Company completed a public offering of $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 Notes due 2025 (the “2025 Notes” together with the 2020 Notes, the “Notes”). The interest rates on the Notes are determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 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 and S&P downgraded the Notes, increasing the interest rates by 175 basis points effective July 2016. As a result of these downgrades, interest rates increased to 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In the event of future downgrades, the coupons for this series of notes were capped at 6.05% and 6.95%, respectively. The first coupon payment to the bondholders at the higher interest rates was paid in January 2017. S&P and Moody’s subsequently upgraded the Notes in April and May 2018, respectively. As a result of these upgrades, interest rates decreased to 5.30% for the 2020 Notes and 6.20% for the 2025 Notes effective July 2018. The first coupon payment to bondholders at the lower interest rates was paid in January 2019.
As discussed in Note 3 above, in December 2018, the Company closed the Fayetteville Shale sale and used a portion of the proceeds to repurchase $40 million of its 4.05% Senior Notes due January 2020, $787 million of its 4.10% Senior Notes due March 2022 and $73 million of its 4.95% Senior Notes due January 2025. The Company recognized a loss on extinguishment of debt of $9 million, which included $2 million of premiums paid.
In the second half of 2019, the Company repurchased $35 million of its 4.95% senior notes due 2025, $11 million of its 7.50% Senior Notes due 2026 and $16 million of its 7.75% Senior Notes due 2027 at a discount for $54 million, and recognized an $8 million gain on extinguishment of debt. Additionally, in December 2019, the Company retired the remaining $52 million principal of its 4.05% Senior Notes due January 2020.
(10) COMMITMENTS AND CONTINGENCIES
Operating Commitments and Contingencies
As of December 31, 2019, 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 $8.5 billion, $1.1 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. The Company also had guarantee obligations of up to $293 million of that amount. As of December 31, 2019, future payments under non-cancelable firm transportation and gathering agreements are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Total
|
|
Less than 1 Year
|
|
1 to 3 Years
|
|
3 to 5 Years
|
|
5 to 8 Years
|
|
More than 8 Years
|
Infrastructure currently in service
|
$
|
7,414
|
|
|
$
|
767
|
|
|
$
|
1,200
|
|
|
$
|
1,066
|
|
|
$
|
1,531
|
|
|
$
|
2,850
|
|
Pending regulatory approval and/or construction (1)
|
1,056
|
|
|
1
|
|
|
35
|
|
|
103
|
|
|
208
|
|
|
709
|
|
Total transportation charges
|
$
|
8,470
|
|
|
$
|
768
|
|
|
$
|
1,235
|
|
|
$
|
1,169
|
|
|
$
|
1,739
|
|
|
$
|
3,559
|
|
(1)Based on the estimated in-service dates as of December 31, 2019.
In December 2018, the Company closed on the Fayetteville Shale sale and retained certain contractual commitments related to firm transportation, with the buyer obligated to pay the transportation provider directly for these charges. As of December 31,
2019, approximately $108 million of these contractual commitments remain of which the Company will reimburse the buyer for certain of these potential obligations up to approximately $58 million through December 2020 depending on the buyer’s actual use, and has recorded a $46 million liability for the estimated future payments, reduced from $88 million at December 31, 2018.
The Company leases pressure pumping equipment for its E&P operations under a single lease that expires in 2021. The current aggregate annual payment under this lease is approximately $6 million. The Company has seven leases for drilling rigs for its E&P operations that expire through 2024 with a current aggregate annual payment of approximately $13 million. The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners.
The Company leases office space, vehicles and equipment under non-cancelable operating leases expiring through 2029. As of December 31, 2019, future minimum payments under these non-cancelable leases accounted for as operating leases (including short-term) are approximately $33 million in 2020, $24 million in 2021, $18 million in 2022, $16 million in 2023, $12 million in 2024 and $45 million thereafter.
The Company also has commitments for compression services and compression rentals related to its E&P segment. As of December 31, 2019, future minimum payments under these non-cancelable agreements (including short-term obligations) are approximately $13 million in 2020, $13 million in 2021, $9 million in 2022 and $2 million in 2023.
In the first quarter of 2019, the Company agreed to purchase firm transportation with pipelines in the Appalachian basin starting in 2021 and running through 2032 totaling $357 million in total contractual commitments, which is presented in the table above; the seller has agreed to reimburse $133 million of these commitments.
In February 2020, the Company was notified that the proposed Constitution pipeline project was cancelled and that the Company was released from a firm transportation agreement with its sponsor. As of December 31, 2019, the Company had contractual commitments totaling $512 million over the next seventeen years related to the Constitution pipeline project that are reflected in the table above as pending regulatory approval and/or construction. These amounts are $6 million within one to three years, $68 million within three to five years, $102 million within five to eight years and $336 million more than eight years forward.
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, results of operations or cash flows of the Company.
Litigation
The Company is subject to various litigation, claims and proceedings, most of which have arisen in the ordinary course of business such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic accidents, pollution, contamination, encroachment on others’ property or nuisance. The Company accrues for litigation, claims and proceedings when a liability is both probable and the amount can be reasonably estimated. As of December 31, 2019, the Company does not currently have any material amounts accrued related to litigation matters. 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, 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 Litigation
The Company was a defendant in three certified class actions alleging that the Company underpaid lessors of lands in Arkansas by deducting from royalty payments costs for gathering, transportation and compression of natural gas in excess of what is permitted by the relevant leases. Two of these class actions were filed in Arkansas state courts and the third in the United States District court for the Eastern District of Arkansas. The Company denied liability in all three cases.
In 2017, the jury returned a verdict in favor of the Company on all counts in Smith v. SEECO, Inc. et al., the class action in the federal court, whose plaintiff class comprised the vast majority of the lessors in these cases. The plaintiff had 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. The trial court denied the plaintiff’s motion for a new trial, and the plaintiff appealed to the United States Court of Appeals for the Eighth Circuit. Independent of the plaintiff’s appeal, several different parties sought to intervene in the Smith case prior to or shortly after trial, and have appealed the trial court’s order denying their request to intervene. Oral argument occurred in January 2019. On April 23, 2019, the Court of Appeals affirmed the trial court’s order denying all requests to intervene in the case, and, in a separate order, affirmed the trial court’s judgment in favor of the Company on all claims. The Court of Appeals subsequently denied all requests for rehearing.
In 2018, the company entered into an agreement to settle another of the class actions, which was pending in the Circuit Court of Conway County, Arkansas under the caption Snow, et al v. SEECO, Inc., et al. The settlement received final approval by the court and the deadline to appeal the order approving the settlement passed without any appeals filed. The amount of the settlement was reflected in the Company’s consolidated statement of operations for 2018 and has been paid. The third class action was also dismissed in 2018.
As of December 31, 2019, some actions filed on behalf of mineral interest owners who opted out of the class actions mentioned above remain pending. The Company does not expect those cases to have a material adverse effect on the results of operations, financial position or cash flows of the Company. Additionally, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible.
St. Lucie County Fire District Firefighters’ Pension Trust
On October 17, 2016, the St. Lucie County Fire District Firefighters’ Pension Trust filed a putative class action in the 61st District Court in Harris County, Texas, against the Company, certain of its former officers and current and former directors and the underwriters on behalf of itself and others that purchased certain depositary shares from the Company’s January 2015 equity offering, alleging material misstatements and omissions in the registration statement for that offering. The Company removed the case to federal court, but after a decision by the United States Supreme Court in an unrelated case that these types of cases are not subject to removal, the federal court remanded the case to the Texas state court. The Texas trial court denied the Company’s motion to dismiss, and in February 2020, the court of appeals declined to exercise discretion to reverse the trial court’s decision. The Company carries insurance for the claims asserted against it and the officer and director defendants, and the carrier has accepted coverage. The Company denies all allegations and intend to continue to defend this case vigorously. The Company does not expect this case to have a material adverse effect on the results of operations, financial position or cash flows of the Company. Additionally, it is not possible at this time to estimate the amount of any additional loss, or range of loss, that is reasonably possible.
Indemnifications
The Company has provided certain indemnifications to various third parties, including in relation to asset and entity dispositions, securities offerings and other financings, such as the St. Lucie County Fire District Firefighters’ Pension Trust case described above. In the case of asset 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) INCOME TAXES
The provision (benefit) for income taxes included the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Current:
|
|
|
|
|
|
Federal
|
$
|
(1)
|
|
|
$
|
(5)
|
|
|
$
|
(22)
|
|
State
|
(1)
|
|
|
6
|
|
|
—
|
|
|
(2)
|
|
|
1
|
|
|
(22)
|
|
Deferred:
|
|
|
|
|
|
Federal
|
(431)
|
|
|
—
|
|
|
(71)
|
|
State
|
22
|
|
|
—
|
|
|
—
|
|
|
(409)
|
|
|
—
|
|
|
(71)
|
|
Provision (benefit) for income taxes
|
$
|
(411)
|
|
|
$
|
1
|
|
|
$
|
(93)
|
|
The provision for income taxes was an effective rate of (86)% in 2019, 0% in 2018 and (10)% in 2017. The Company’s effective tax rate decreased in 2019, as compared with 2018, primarily due to the release of a valuation allowance in 2019. The
following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Expected provision at federal statutory rate
|
$
|
101
|
|
|
$
|
113
|
|
|
$
|
333
|
|
Decrease resulting from:
|
|
|
|
|
|
State income taxes, net of federal income tax effect
|
11
|
|
|
13
|
|
|
16
|
|
Rate impacts due to tax reform
|
—
|
|
|
—
|
|
|
370
|
|
Changes to valuation allowance due to tax reform
|
—
|
|
|
—
|
|
|
(370)
|
|
AMT tax reform impact – valuation allowance release
|
—
|
|
|
—
|
|
|
(68)
|
|
Changes in uncertain tax positions
|
—
|
|
|
—
|
|
|
(5)
|
|
Change in valuation allowance
|
(522)
|
|
|
(121)
|
|
|
(364)
|
|
Removal of sequestration fee on AMT receivables
|
—
|
|
|
(5)
|
|
|
—
|
|
Other
|
(1)
|
|
|
1
|
|
|
(5)
|
|
Provision (benefit) for income taxes
|
$
|
(411)
|
|
|
$
|
1
|
|
|
$
|
(93)
|
|
The 2019 tax accrual calculated under the estimated annual effective tax rate method reflects the Tax Reform Act changes that took effect January 1, 2018. The components of the Company’s deferred tax balances as of December 31, 2019 and 2018 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
Deferred tax liabilities:
|
|
|
|
Differences between book and tax basis of property
|
$
|
312
|
|
|
$
|
226
|
|
Derivative activity
|
34
|
|
|
12
|
|
Right of use lease asset
|
37
|
|
|
—
|
|
Other
|
2
|
|
|
2
|
|
|
385
|
|
|
240
|
|
Deferred tax assets:
|
|
|
|
Accrued compensation
|
33
|
|
|
33
|
|
Accrued pension costs
|
9
|
|
|
10
|
|
Asset retirement obligations
|
13
|
|
|
15
|
|
Net operating loss carryforward
|
769
|
|
|
777
|
|
Future lease payments
|
37
|
|
|
—
|
|
Other
|
18
|
|
|
14
|
|
|
879
|
|
|
849
|
|
Valuation allowance
|
(87)
|
|
|
(609)
|
|
Net deferred tax asset
|
$
|
407
|
|
|
$
|
—
|
|
The Tax Reform Act made significant changes to the U.S. federal income tax law affecting the Company. Major changes in this legislation applicable to the Company relate to the reduction in the corporate tax rate to 21%, repeal of the alternative minimum tax, interest deductibility and net operating loss carryforward limitations, changes to certain executive compensation and full expensing provisions related to business assets. The adjustments required to deferred taxes as a result of the Tax Reform Act have been reflected in the Company’s tax provision.
As the Tax Reform Act repealed the corporate alternative minimum tax for tax years beginning on or after January 1, 2018 and provided for existing alternative minimum tax credit carryovers to be refunded beginning in 2018, the Company has approximately $30 million in refundable credits remaining that are expected to be fully refunded by 2021. Accordingly, in 2017 the valuation allowance in place prior to the Tax Reform Act related to these credits was released, and any credits remaining were reclassed to a receivable.
In 2019, the Company received refunds related to state income tax of $1.0 million. In 2018, the Company paid $6.3 million in state income tax. The Company’s net operating loss carryforward as of December 31, 2019 was $3.0 billion and $2.3 billion for federal and state reporting purposes, respectively, the majority of which will expire between 2035 and 2039. Additionally, the Company has an income tax net operating loss carryforward related to its Canadian operations of $29 million, with expiration dates of 2030 through 2038. The Company also had a statutory depletion carryforward of $13 million and $29 million related to interest deduction carryforward as of December 31, 2019.
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 assets will not be realized. To assess that likelihood, 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 current and forecasted business economics of the oil and gas industry.
For the years ended December 31, 2018 and 2017, 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, 2018, primarily due to non-cash impairments of proved natural gas and oil properties recognized in 2015 and 2016. As of the first quarter of 2019, the Company had sustained a three-year cumulative level of profitability. Based on this factor and other positive evidence including forecasted taxable income, the Company concluded that it was more likely than not that the deferred tax assets would be realized and determined that $522 million of the valuation allowance would be released during 2019. Accordingly, a tax benefit of $522 million was recorded. As of December 31, 2019, the Company expects to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates. The Company is continually evaluating deferred tax asset realizability, and if pricing changes occur that would significantly affect the forecast, the Company will reconsider the need for a valuation allowance at such time.
A reconciliation of the changes to the valuation allowance is as follows:
|
|
|
|
|
|
(in millions)
|
|
Valuation allowance as of December 31, 2018
|
$
|
609
|
|
|
|
Release of valuation allowance in 2019
|
(522)
|
|
|
|
|
|
Valuation allowance as of December 31, 2019
|
$
|
87
|
|
A tax position must meet certain thresholds for any of the benefit of the uncertain tax position to be recognized in the financial statements. As of December 31, 2019, there were no unrecognized tax positions identified that would have a material effect on the effective tax rate. All positions booked as of December 31, 2018 were released in 2019 due to audit completion and statute expirations.
A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
Unrecognized tax benefits at beginning of year
|
$
|
7
|
|
|
$
|
12
|
|
Additions based on tax positions related to the current year
|
—
|
|
|
—
|
|
Additions to tax positions of prior years
|
—
|
|
|
—
|
|
Reductions to tax positions of prior years
|
(7)
|
|
|
(5)
|
|
Unrecognized tax benefits at end of year
|
$
|
—
|
|
|
$
|
7
|
|
The Internal Revenue Service closed the 2014 audit of the Company’s federal return in 2019 with no change and is currently auditing the Company’s 2016 and 2017 tax periods. The income tax years 2016 to 2019 remain open to examination by the major taxing jurisdictions to which the Company is subject.
(12) ASSET RETIREMENT OBLIGATIONS
The following table summarizes the Company’s 2019 and 2018 activity related to asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
Asset retirement obligation at January 1
|
$
|
61
|
|
|
$
|
165
|
|
Accretion of discount
|
3
|
|
|
9
|
|
Obligations incurred
|
2
|
|
|
1
|
|
Obligations settled/removed (1)
|
(9)
|
|
|
(116)
|
|
Revisions of estimates
|
—
|
|
|
2
|
|
Asset retirement obligation at December 31
|
$
|
57
|
|
|
$
|
61
|
|
|
|
|
|
Current liability
|
$
|
6
|
|
|
$
|
6
|
|
Long-term liability
|
51
|
|
|
55
|
|
Asset retirement obligation at December 31
|
$
|
57
|
|
|
$
|
61
|
|
(1)Obligations settled/removed include $111 million related to asset divestitures in 2018, of which $107 million related to the Fayetteville Shale sale.
(13) RETIREMENT AND EMPLOYEE BENEFIT PLANS
401(k) Defined Contribution Plan
The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $2 million, $3 million and $3 million of contribution expense in 2019, 2018 and 2017, respectively. Additionally, the Company capitalized $1 million of contributions in 2019 and $2 million in both 2018 and 2017, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
Defined Benefit Pension and Other Postretirement Plans
Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.
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 are covered by the defined benefit pension and 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.
In June 2018, the Company notified affected employees of a workforce reduction plan, which resulted primarily from a previously announced study of structural, process and organizational changes to enhance shareholder value. In December 2018, the Company closed the sale of the equity in certain of its subsidiaries that owned and operated its Fayetteville Shale E&P and related midstream gathering assets in Arkansas. As part of this transaction, many employees associated with those assets were either transferred to the buyer or their employment was terminated. As a result of the restructurings, the Company recognized a curtailment on its pension and other postretirement benefit plans and recognized a non-cash gain of $4 million on its consolidated statements of operations for the year ended December 31, 2018. In 2019, the Company recognized a $6 million non-cash settlement loss related to $21 million of lump sum payments as a result of these restructuring events.
The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
Other Postretirement Benefits
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Change in benefit obligations:
|
|
|
|
|
|
|
|
Benefit obligation at January 1
|
$
|
125
|
|
|
$
|
143
|
|
|
$
|
13
|
|
|
$
|
17
|
|
Service cost
|
7
|
|
|
10
|
|
|
1
|
|
|
2
|
|
Interest cost
|
5
|
|
|
5
|
|
|
—
|
|
|
1
|
|
Participant contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Actuarial (gain) loss
|
15
|
|
|
(14)
|
|
|
1
|
|
|
—
|
|
Benefits paid
|
(2)
|
|
|
(14)
|
|
|
(2)
|
|
|
(1)
|
|
Plan amendments
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Curtailments
|
—
|
|
|
(5)
|
|
|
—
|
|
|
(6)
|
|
Settlements
|
(24)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefit obligation at December 31
|
$
|
126
|
|
|
$
|
125
|
|
|
$
|
13
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
Other Postretirement Benefits
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Change in plan assets:
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
$
|
91
|
|
|
$
|
101
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
16
|
|
|
(8)
|
|
|
—
|
|
|
—
|
|
Employer contributions
|
12
|
|
|
12
|
|
|
2
|
|
|
1
|
|
Participant contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefits paid
|
(2)
|
|
|
(14)
|
|
|
(2)
|
|
|
(1)
|
|
Settlements
|
(21)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Fair value of plan assets at December 31
|
$
|
96
|
|
|
$
|
91
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Funded status of plans at December 31
|
$
|
(30)
|
|
|
$
|
(34)
|
|
|
$
|
(13)
|
|
|
$
|
(13)
|
|
The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above.
The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2019 and 2018 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
Projected benefit obligation
|
$
|
126
|
|
|
$
|
125
|
|
Accumulated benefit obligation
|
124
|
|
|
122
|
|
Fair value of plan assets
|
96
|
|
|
91
|
|
Pension and other postretirement benefit costs include the following components for 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
|
|
Other Postretirement Benefits
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
|
2019
|
|
2018
|
|
2017
|
Service cost
|
$
|
7
|
|
|
$
|
10
|
|
|
$
|
9
|
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Interest cost
|
5
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
1
|
|
|
—
|
|
Expected return on plan assets
|
(6)
|
|
|
(7)
|
|
|
(6)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of transition obligation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
2
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net periodic benefit cost
|
8
|
|
|
10
|
|
|
10
|
|
|
1
|
|
|
3
|
|
|
2
|
|
Curtailment gain
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
Settlement loss
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total benefit cost (benefit)
|
$
|
14
|
|
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
1
|
|
|
$
|
(1)
|
|
|
$
|
2
|
|
Service cost is classified as general and administrative expenses on the consolidated statements of operations. All other components of total benefit cost (benefit) are classified as other income (loss), net on the consolidated statements of operations.
Amounts recognized in other comprehensive income for the years ended December 31, 2019 and 2018 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
Other Postretirement Benefits
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Net actuarial loss arising during the year
|
$
|
(5)
|
|
|
$
|
(2)
|
|
|
$
|
(1)
|
|
|
$
|
—
|
|
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Settlements
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Curtailments
|
—
|
|
|
5
|
|
|
—
|
|
|
3
|
|
Tax effect (1)
|
(1)
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
(1)
|
|
|
$
|
2
|
|
(1)For the year ended December 31, 2018, deferred tax activity related to pension and other postretirement benefits was offset by a valuation allowance, resulting in no tax expense presented on the consolidated statements of operations.
Included in accumulated other comprehensive income as of December 31, 2019 and 2018 was a $30 million loss ($22 million net of tax) and a $34 million loss ($20 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2019, $3 million was classified from accumulated other comprehensive income, primarily driven by settlement losses. Amortization of prior period service cost reclassified from accumulated other comprehensive income to general and administrative expenses for the year was immaterial.
The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2020 is a $1 million expense.
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2019 and 2018 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
Other Postretirement Benefits
|
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Discount rate
|
3.70
|
%
|
|
4.35
|
%
|
|
3.50
|
%
|
|
4.35
|
%
|
Rate of compensation increase
|
3.50
|
%
|
|
3.50
|
%
|
|
n/a
|
|
n/a
|
The assumptions used in the measurement of the Company’s net periodic benefit cost for 2019, 2018 and 2017 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
|
|
Other Postretirement Benefits
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
2019
|
|
2018
|
|
2017
|
Discount rate
|
3.70
|
%
|
|
4.35
|
%
|
|
4.20
|
%
|
|
4.35
|
%
|
|
4.35
|
%
|
|
4.20
|
%
|
Expected return on plan assets
|
7.00
|
%
|
|
7.00
|
%
|
|
7.00
|
%
|
|
n/a
|
|
n/a
|
|
n/a
|
Rate of compensation increase
|
3.50
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
|
n/a
|
|
n/a
|
|
n/a
|
The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification.
For measurement purposes, the following trend rates were assumed for 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
Health care cost trend assumed for next year
|
7
|
%
|
|
7
|
%
|
Rate to which the cost trend is assumed to decline
|
5
|
%
|
|
5
|
%
|
Year that the rate reaches the ultimate trend rate
|
2037
|
|
2036
|
Assumed health care cost trend rates have a significant effect on the amounts for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
1% Increase
|
|
1% Decrease
|
Effect on the total service and interest cost components
|
$
|
2
|
|
|
$
|
(1)
|
|
Effect on postretirement benefit obligations
|
$
|
2
|
|
|
$
|
(2)
|
|
Pension Payments and Asset Management
In 2019, the Company contributed $12 million to its pension plans and $2 million to its other postretirement benefit plan. The Company expects to contribute $13 million to its pension and other postretirement benefit plans in 2020.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
(in millions)
|
|
|
|
|
|
2020
|
$
|
5
|
|
|
2020
|
|
$
|
1
|
|
2021
|
5
|
|
|
2021
|
|
1
|
|
2022
|
6
|
|
|
2022
|
|
1
|
|
2023
|
6
|
|
|
2023
|
|
1
|
|
2024
|
7
|
|
|
2024
|
|
1
|
|
Years 2025-2029
|
34
|
|
|
Years 2025-2029
|
|
5
|
|
The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term payment of benefit obligations to participants, retirees and beneficiaries. The Benefits Administration Committee of the Company, appointed by the Compensation Committee of the Board of Directors, administers the Company’s pension plan assets. The Benefits Administration Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets.
The table below presents the allocations targeted by the Benefits Administration Committee and the actual weighted-average asset allocation of the Company’s pension plan as of December 31, 2019, by asset category. The asset allocation targets are subject to change and the Benefits Administration Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions. Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range.
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan Asset Allocations
|
|
|
Asset category:
|
Target
|
|
Actual
|
Equity securities:
|
|
|
|
U.S. equity (1)
|
35
|
%
|
|
34
|
%
|
Non-U.S. equity (2)
|
35
|
%
|
|
33
|
%
|
|
|
|
|
Fixed income (3)
|
28
|
%
|
|
31
|
%
|
Cash (4)
|
2
|
%
|
|
2
|
%
|
Total
|
100
|
%
|
|
100
|
%
|
(1)Includes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity.
(2)Includes Non-U.S. equity securities in the table below.
(3)Includes fixed income pension plan assets in the table below.
(4)Includes Cash and cash equivalent pension plan assets in the table below.
Utilizing the fair value hierarchy described in Note 8, the Company’s fair value measurement of pension plan assets as of December 31, 2019 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Total
|
|
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
|
Significant Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
Measured within fair value hierarchy
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
U.S. large cap growth equity (1)
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
U.S. large cap value equity (2)
|
6
|
|
|
6
|
|
|
—
|
|
|
—
|
|
U.S. small cap equity (3)
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Non-U.S. equity (4)
|
32
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Fixed income (6)
|
22
|
|
|
22
|
|
|
—
|
|
|
—
|
|
Cash and cash equivalents
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Total measured within fair value hierarchy
|
$
|
67
|
|
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Measured at net asset value (8)
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
U.S. large cap growth equity (9)
|
3
|
|
|
|
|
|
|
|
U.S. large cap core equity (10)
|
18
|
|
|
|
|
|
|
|
Fixed income (6)
|
8
|
|
|
|
|
|
|
|
Total measured at net asset value
|
$
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total plan assets at fair value
|
$
|
96
|
|
|
|
|
|
|
|
Note: Footnotes are located after the prior year comparative table below.
Utilizing the fair value hierarchy described in Note 8, the Company’s fair value measurement of pension plan assets at December 31, 2018 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Total
|
|
Quoted Prices in Active Markets for Identical Assets (Level 1)
|
|
Significant Observable Inputs
(Level 2)
|
|
Significant Unobservable Inputs
(Level 3)
|
Measured within fair value hierarchy
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
U.S. large cap growth equity (1)
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
U.S. large cap value equity (2)
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
U.S. small cap equity (3)
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Non-U.S. equity (4)
|
20
|
|
|
20
|
|
|
—
|
|
|
—
|
|
Emerging markets equity (5)
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
|
Fixed income (6)
|
14
|
|
|
14
|
|
|
—
|
|
|
—
|
|
Cash and cash equivalents (7)
|
23
|
|
|
23
|
|
|
—
|
|
|
—
|
|
Total measured within fair value hierarchy
|
$
|
72
|
|
|
$
|
72
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Measured at net asset value (8)
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
U.S. large cap core equity (10)
|
12
|
|
|
|
|
|
|
|
Fixed income (6)
|
7
|
|
|
|
|
|
|
|
Total measured at net asset value
|
$
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total plan assets at fair value
|
$
|
91
|
|
|
|
|
|
|
|
(1)Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2)Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3)Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(4)Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(5)An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(6)Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
(7)Included approximately $21 million for anticipated lump sum distributions resulting from the Fayetteville Shale sale in December 2018.
(8)Plan assets for which fair value was measured using net asset value as a practical expedient.
(9)An institutional fund that seeks to invest in companies with sustainable competitive advantages, as identified through proprietary research.
(10)An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
The Company’s pension plan assets that are classified as Level 1 are the investments comprised of either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair value measurement as Level 1. Due to the Company’s implementation of Accounting Standards Update No. 2015-07, assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy. No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund.
(14) STOCK-BASED COMPENSATION
The Southwestern Energy Company 2013 Incentive Plan was adopted in February 2013, approved by stockholders in May 2013 and amended and restated per stockholders’ approval in May 2016 and further amended in May 2017 and May 2019 (the “2013 Plan”). The 2013 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries.
The 2013 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers and directors that, in the aggregate, do not exceed 88,700,000 shares. The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s Board of Directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2013 Plan.
The Company’s stock-based compensation is classified as either equity 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 and capitalized expense on a straight-line basis over the vesting period of the award. 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 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 property and equipment. Generally, stock options granted to employees and directors vest ratably over three years from the grant date and expire seven years from the date of grant. The Company issues shares of restricted stock or restricted stock units to employees and directors which generally vest over four years. Restricted stock, restricted stock units and stock options granted to participants under the 2013 Plan, as amended and restated, immediately vest upon death, disability or retirement (subject to a minimum of three years of service). The Company issues performance units which have historically vested over three years to employees. The performance units granted in 2018 and 2019 cliff-vest at the end of three years.
In June 2018, the Company announced a workforce reduction. Unvested stock-based awards of the affected employees were subsequently cancelled and the approximate fair value of a portion of those cancelled awards was included in a cash severance payment that was paid in the third quarter of 2018. Stock-based compensation costs recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments were subsequently recognized as restructuring charges for the year ended December 31, 2018 on the consolidated statements of operations.
In December 2018, the Company closed the Fayetteville Shale sale. As part of this transaction, most employees associated with those assets became employees of the buyer although the employment of some was terminated. All affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of equity awards that were forfeited. Stock-based compensation costs recognized prior to the cancellation as either general and administrative expense or capitalized expense were reversed and the severance payments were subsequently recognized as restructuring charges for the years ended December 31, 2019 and 2018 on the consolidated statements of operations.
Equity-Classified Awards
Equity-Classified Stock Options
The Company recorded the following compensation costs related to stock options for the years ended December 31, 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Stock options – general and administrative expense
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
3
|
|
Stock options – general and administrative expense capitalized
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
The Company also recorded a reduction in the deferred tax asset of less than $1 million related to stock options for the year ended December 31, 2019, compared to deferred tax assets of less than $1 million and $1 million for the years ended December 31, 2018 and 2017, respectively. Unrecognized compensation cost related to the Company’s unvested stock options totaled less than $1 million at December 31, 2019. This cost is expected to be recognized over a weighted-average period of less than one year.
The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on the exercise of stock options, post-vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant. The Company did not issue equity-classified stock options in 2019 or 2018.
|
|
|
|
|
|
|
|
|
|
Assumptions
|
|
|
|
|
2017
|
Risk-free interest rate
|
|
|
|
|
1.9
|
%
|
Expected dividend yield
|
|
|
|
|
—
|
|
Expected volatility
|
|
|
|
|
50.5
|
%
|
Expected term
|
|
|
|
|
5 years
|
The following tables summarize stock option activity for the years 2019, 2018 and 2017, and provide information for options outstanding at December 31 of each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
|
|
Number
of Shares
|
|
Weighted Average Exercise Price
|
|
Number
of Shares
|
|
Weighted Average Exercise Price
|
|
Number
of Shares
|
|
Weighted Average Exercise Price
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
Options outstanding at January 1
|
5,178
|
|
|
$
|
17.06
|
|
|
6,020
|
|
|
$
|
19.43
|
|
|
5,416
|
|
|
$
|
23.46
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
1,604
|
|
|
$
|
8.00
|
|
Exercised
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Forfeited or expired
|
(543)
|
|
|
$
|
32.38
|
|
|
(842)
|
|
|
$
|
33.99
|
|
|
(1,000)
|
|
|
$
|
22.93
|
|
Options outstanding at December 31
|
4,635
|
|
|
$
|
15.26
|
|
|
5,178
|
|
|
$
|
17.06
|
|
|
6,020
|
|
|
$
|
19.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
|
|
|
Options Exercisable
|
|
|
|
|
Range of
Exercise Prices
|
Options Outstanding at December 31, 2019
|
|
Weighted Average Exercise Price
|
|
Weighted Average Remaining Contractual Life
|
|
Options Exercisable at December 31, 2019
|
|
Weighted Average Exercise Price
|
|
Weighted Average Remaining Contractual Life
|
|
(in thousands)
|
|
|
|
(years)
|
|
(in thousands)
|
|
|
|
(years)
|
$5.22-$29.42
|
3,467
|
|
|
$
|
8.63
|
|
|
3.4
|
|
3,045
|
|
|
$
|
8.74
|
|
|
3.3
|
$30.59-$35.64
|
644
|
|
|
$
|
30.60
|
|
|
1.9
|
|
644
|
|
|
$
|
30.60
|
|
|
1.9
|
$38.20-$38.97
|
434
|
|
|
$
|
38.97
|
|
|
0.9
|
|
434
|
|
|
$
|
38.97
|
|
|
0.9
|
$46.55-$46.55
|
90
|
|
|
$
|
46.55
|
|
|
1.4
|
|
90
|
|
|
$
|
46.55
|
|
|
1.4
|
|
4,635
|
|
|
$
|
15.26
|
|
|
2.9
|
|
4,213
|
|
|
$
|
16.01
|
|
|
2.8
|
No options were granted in 2019 or 2018. The weighted-average grant date fair value of options granted during 2017 was $3.47. No options were exercised in 2019, 2018 or 2017.
Equity-Classified Restricted Stock
The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Restricted stock grants – general and administrative expense
|
$
|
6
|
|
|
$
|
9
|
|
|
$
|
16
|
|
Restricted stock grants – general and administrative expense capitalized
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
11
|
|
The Company also recorded a reduction in the deferred tax asset of less than $1 million related to restricted stock for the year ended December 31, 2019, compared to deferred tax assets of $2 million and $9 million for 2018 and 2017, respectively. As of December 31, 2019, there was $6 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of one year.
The following table summarizes the restricted stock activity for the years 2019, 2018 and 2017, and provides information for restricted stock outstanding at December 31 of each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
|
|
Number of
Shares
|
|
Weighted Average Fair Value
|
|
Number of
Shares
|
|
Weighted Average Fair Value
|
|
Number of
Shares
|
|
Weighted Average Fair Value
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
Unvested shares at January 1
|
2,717
|
|
|
$
|
7.91
|
|
|
6,254
|
|
|
$
|
8.85
|
|
|
3,321
|
|
|
$
|
11.85
|
|
Granted
|
493
|
|
|
$
|
3.06
|
|
|
350
|
|
|
$
|
4.72
|
|
|
5,055
|
|
|
$
|
8.38
|
|
Vested
|
(1,516)
|
|
|
$
|
7.16
|
|
|
(2,058)
|
|
|
$
|
9.24
|
|
|
(1,380)
|
|
|
$
|
13.28
|
|
Forfeited
|
(214)
|
|
(1)
|
$
|
8.38
|
|
|
(1,829)
|
|
(2)
|
$
|
9.01
|
|
|
(742)
|
|
|
$
|
10.04
|
|
Unvested shares at December 31
|
1,480
|
|
|
$
|
7.00
|
|
|
2,717
|
|
|
$
|
7.91
|
|
|
6,254
|
|
|
$
|
8.85
|
|
(1)Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019.
(2)Includes 1,287,636 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2018.
The fair values of the grants were $2 million for 2019, $2 million for 2018 and $42 million for 2017. The total fair value of shares vested were $11 million for 2019, $19 million for 2018 and $18 million for 2017.
Equity-Classified Performance Units
The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2019, 2018 and 2017. The performance units awarded in 2017 included a market condition based on relative Total Shareholder Return (“TSR”). The grant date fair value is calculated using the closing price of the Company’s common stock at the grant date and a Monte Carlo model to estimate the TSR market condition. The estimated fair value is amortized to compensation expense on a straight-line basis over the vesting period of the award. There were no equity-classified performance units awarded in 2019 and 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Performance units – general and administrative expense
|
$
|
1
|
|
|
$
|
3
|
|
|
$
|
5
|
|
Performance units – general and administrative expense capitalized
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
2
|
|
The Company also recorded a deferred tax asset of less than $1 million related to equity-classified performance units for the year ended December 31, 2019, compared to deferred tax assets of $1 million and $3 million in 2018 and 2017, respectively. As of December 31, 2019, there was less than $1 million of total unrecognized compensation cost related to unvested equity-classified performance units that is expected to be recognized over a weighted-average period of less than one year.
The following table summarizes equity-classified performance unit activity to be paid out in Company stock for the years ended December 31, 2019, 2018 and 2017, and provides information for unvested units as of December 31, 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
|
|
Number of
Units (1)
|
|
Weighted
Average Fair Value
|
|
Number of
Units (1)
|
|
Weighted
Average Fair Value
|
|
Number of
Units (1)
|
|
Weighted
Average Fair Value
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
Unvested shares at January 1
|
598
|
|
|
$
|
10.01
|
|
|
1,084
|
|
|
$
|
10.12
|
|
|
719
|
|
|
$
|
11.46
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
1,197
|
|
|
$
|
10.47
|
|
Vested
|
(378)
|
|
|
$
|
9.59
|
|
|
(290)
|
|
|
$
|
10.47
|
|
|
(325)
|
|
|
$
|
12.21
|
|
Forfeited
|
(42)
|
|
(2)
|
$
|
10.47
|
|
|
(196)
|
|
(3)
|
$
|
9.94
|
|
|
(507)
|
|
|
$
|
9.53
|
|
Unvested shares at December 31
|
178
|
|
|
$
|
10.47
|
|
|
598
|
|
|
$
|
10.01
|
|
|
1,084
|
|
|
$
|
10.12
|
|
(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 TSR. 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.
(2)Includes 41,761 units related to the reduction in workforce for the year ended December 31, 2019.
(3)Includes 144,927 units related to the reduction in workforce for the year ended December 31, 2018.
Liability-Classified Awards
Liability-Classified Restricted Stock Units
In the first quarter of 2019 and 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 of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the award.
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
Restricted stock units – general and administrative expense
|
$
|
7
|
|
|
|
$
|
4
|
|
Restricted stock units – general and administrative expense capitalized
|
$
|
5
|
|
|
|
$
|
3
|
|
The Company also recorded deferred tax assets of less than $1 million and $2 million related to liability-classified restricted stock units for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2019, there was $24 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 three years. The amount of unrecognized compensation cost for liability-classified awards will fluctuate over time as they are marked to market.
The following table summarizes restricted stock unit activity to be paid out in cash for the years ended December 31, 2019 and 2018 and provides information for unvested units as of December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
2018
|
|
|
|
Number
of Units
|
|
Weighted Average Fair Value
|
|
Number
of Units
|
|
Weighted Average Fair Value
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
Unvested units at January 1
|
8,202
|
|
|
$
|
3.41
|
|
|
—
|
|
|
|
$
|
—
|
|
Granted
|
8,659
|
|
|
$
|
4.34
|
|
|
12,216
|
|
|
|
$
|
3.69
|
|
Vested
|
(2,624)
|
|
|
$
|
4.09
|
|
|
(232)
|
|
|
|
$
|
5.14
|
|
Forfeited
|
(1,245)
|
|
(1)
|
$
|
3.48
|
|
|
(3,782)
|
|
(2)
|
$
|
4.86
|
|
Unvested units at December 31
|
12,992
|
|
|
$
|
2.42
|
|
|
8,202
|
|
|
|
$
|
3.41
|
|
(1)Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019.
(2)Includes 2,766,610 units related to the reduction in workforce for the year ended December 31, 2018.
Liability-Classified Performance Units
In 2019 and 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 at the option of the Compensation Committee of the Company’s Board of Directors. The Company has accounted for these as liability-classified awards, and accordingly changes in the fair market value of the instruments will be recorded to general and administrative expense and capitalized expense over the vesting period of the awards. The performance unit awards granted in 2018 include a performance condition based on cash flow per debt-adjusted share and two market conditions, one based on absolute TSR and the other on relative TSR as compared to a group of the Company’s peers. The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis. The performance unit awards granted in 2019 include a performance condition based on return on average capital employed and two market conditions, one based on absolute TSR and the other on relative TSR. The fair values of the two market conditions are calculated by Monte Carlo models on a quarterly basis.
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
Liability-classified performance units – general and administrative expense
|
$
|
2
|
|
|
|
$
|
2
|
|
Liability-classified performance units – general and administrative expense capitalized
|
$
|
1
|
|
|
|
$
|
—
|
|
The Company also recorded a reduction in the deferred tax assets of less than $1 million related to liability-classified performance units for the year ended December 31, 2019, compared to a deferred tax asset of $1 million for the year ended December 31, 2018. As of December 31, 2019, 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 two 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 the Performance Measures.
The following table summarizes liability-classified performance unit activity to be paid out in cash for the years ended December 31, 2019 and 2018 and provides information for unvested units as of December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
|
2018
|
|
|
|
Number
of Shares
|
|
Weighted Average
Fair Value
|
|
Number
of Shares
|
|
Weighted Average
Fair Value
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
Unvested units at January 1
|
2,803
|
|
|
$
|
3.41
|
|
|
|
—
|
|
|
|
$
|
—
|
|
Granted
|
2,757
|
|
|
$
|
4.34
|
|
|
|
3,200
|
|
|
|
$
|
3.70
|
|
Vested
|
(43)
|
|
|
$
|
2.42
|
|
|
|
—
|
|
|
|
$
|
—
|
|
Forfeited
|
(375)
|
|
(1)
|
$
|
3.12
|
|
|
|
(397)
|
|
(2)
|
$
|
4.55
|
|
Unvested units at December 31
|
5,142
|
|
|
$
|
2.42
|
|
|
|
2,803
|
|
|
|
$
|
3.41
|
|
(1)Includes 375,086 units related to the reduction in workforce for the year ended December 31, 2019.
(2)Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018.
(15) 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 Marketing segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes.
Prior to December 2018, the Marketing segment included the Company’s natural gas gathering business in its Fayetteville Shale assets. With the closing of the Fayetteville Shale sale in December 2018, the Company's marketing business comprises substantially all of the Company’s Marketing segment.
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. 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 (loss), interest expense, gain (loss) on derivatives, gain (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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Exploration
and
Production
|
|
Marketing
|
|
Other
|
|
Total
|
2019
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
1,740
|
|
|
$
|
1,298
|
|
|
$
|
—
|
|
|
$
|
3,038
|
|
Intersegment revenues
|
(37)
|
|
|
1,552
|
|
|
—
|
|
|
1,515
|
|
Depreciation, depletion and amortization expense
|
462
|
|
|
9
|
|
|
—
|
|
|
471
|
|
Impairments
|
13
|
|
|
3
|
|
|
—
|
|
|
16
|
|
Operating income (loss)
|
283
|
|
(1)
|
(13)
|
|
|
—
|
|
|
270
|
|
Interest expense (2)
|
65
|
|
|
—
|
|
|
—
|
|
|
65
|
|
Gain on derivatives
|
274
|
|
|
—
|
|
|
—
|
|
|
274
|
|
Gain on early extinguishment of debt
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
Other income (loss), net
|
(9)
|
|
|
—
|
|
|
2
|
|
|
(7)
|
|
Benefit from income taxes (2)
|
(411)
|
|
|
—
|
|
|
—
|
|
|
(411)
|
|
Assets
|
6,235
|
|
(3)
|
314
|
|
|
168
|
|
(4)
|
6,717
|
|
Capital investments (5)
|
1,138
|
|
|
—
|
|
|
2
|
|
|
1,140
|
|
|
|
|
|
|
|
|
|
2018 (6)
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
2,551
|
|
|
$
|
1,311
|
|
|
$
|
—
|
|
|
$
|
3,862
|
|
Intersegment revenues
|
(26)
|
|
|
2,434
|
|
|
—
|
|
|
2,408
|
|
Depreciation, depletion and amortization expense
|
514
|
|
|
46
|
|
|
—
|
|
|
560
|
|
Impairments
|
15
|
|
|
155
|
|
(8)
|
1
|
|
|
171
|
|
Operating income (loss)
|
794
|
|
(7)
|
4
|
|
(9)
|
(1)
|
|
|
797
|
|
Interest expense (2)
|
124
|
|
|
—
|
|
|
—
|
|
|
124
|
|
Loss on derivatives
|
(118)
|
|
|
—
|
|
|
—
|
|
|
(118)
|
|
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
(17)
|
|
|
(17)
|
|
Other income (loss), net
|
2
|
|
|
(2)
|
|
|
—
|
|
|
—
|
|
Provision for income taxes (2)
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Assets
|
4,872
|
|
(3)
|
539
|
|
|
386
|
|
(4)
|
5,797
|
|
Capital investments (5)
|
1,231
|
|
|
9
|
|
|
8
|
|
|
1,248
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
2,105
|
|
|
$
|
1,098
|
|
|
$
|
—
|
|
|
$
|
3,203
|
|
Intersegment revenues
|
(19)
|
|
|
2,100
|
|
|
—
|
|
|
2,081
|
|
Depreciation, depletion and amortization expense
|
440
|
|
|
64
|
|
|
—
|
|
|
504
|
|
Operating income (loss)
|
549
|
|
|
183
|
|
|
(1)
|
|
|
731
|
|
Interest expense (2)
|
135
|
|
|
—
|
|
|
—
|
|
|
135
|
|
Gain on derivatives
|
421
|
|
|
1
|
|
|
—
|
|
|
422
|
|
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
(70)
|
|
|
(70)
|
|
Other income, net
|
4
|
|
|
1
|
|
|
—
|
|
|
5
|
|
Benefit from income taxes (2)
|
(93)
|
|
|
—
|
|
|
—
|
|
|
(93)
|
|
Assets
|
5,109
|
|
(3)
|
1,288
|
|
|
1,124
|
|
(4)
|
7,521
|
|
Capital investments (5)
|
1,248
|
|
|
32
|
|
|
13
|
|
|
1,293
|
|
(1)Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019.
(2)Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
(3)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.
(4)Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2019, 2018 and 2017, other assets included approximately $5 million, $205 million and $914 million, respectively, in cash and cash equivalents, $30 million, $89 million and $89 million, respectively, in income taxes receivable, $27 million, $60 million and $95 million, respectively, in property, plant and equipment, $11 million, $11 million and $5 million, respectively, in unamortized debt expense, $8 million, $8 million and $11 million, respectively, in prepayments and $7 million, $8 million and $10 million, respectively, in a non-qualified retirement plan. Additionally, the December 31, 2019 asset balance includes $80 million in right-of-use lease assets and the December 31, 2018 asset balance includes $4 million of accounts receivable and $1 million of current hedging assets.
(5)Capital investments include an increase of $34 million for 2019 and a decrease of $53 million for 2018 related to the change in accrued expenditures between years. There was no impact to 2017.
(6)Includes the impact of approximately eleven months of Fayetteville Shale-related E&P and midstream gathering operations which were divested in December 2018.
(7)Operating income for the E&P segment includes $37 million related to restructuring charges for the year ended December 31, 2018.
(8)Marketing includes a $10 million non-cash impairment related to certain non-core midstream gathering assets at December 31, 2018.
(9)Operating income for the Marketing segment includes $2 million related to restructuring charges for the year ended December 31, 2018.
Included in intersegment revenues of the Marketing segment are $1.6 billion, $2.3 billion and $1.9 billion for 2019, 2018 and 2017, 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.
(16) CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In April 2018, the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing the Company’s senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of the Company’s senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 2018 credit facility but not of the senior notes. These guarantees are full and unconditional and joint and several among the Guarantor Subsidiaries. Certain of the Company’s operating units which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes (“Non-Guarantor Subsidiaries”). See Note 9 for additional information on the Company’s 2018 revolving credit facility and senior notes. At the closing of the Fayetteville Shale sale in December 2018, its subsidiaries being sold were released from these guarantees. See Note 3 for additional information on the divestiture of the Company’s Fayetteville Shale-related subsidiaries.
The following financial information reflects consolidating financial information of Southwestern Energy Company (the parent and issuer company), its Guarantor Subsidiaries on a combined basis and the Non-Guarantor Subsidiaries on a combined basis, prepared on the equity basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Parent
|
|
Guarantors
|
|
Non-Guarantors
|
|
Eliminations
|
|
Consolidated
|
Year ended December 31, 2019
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
Gas sales
|
$
|
—
|
|
|
$
|
1,241
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,241
|
|
Oil sales
|
—
|
|
|
223
|
|
|
—
|
|
|
—
|
|
|
223
|
|
NGL sales
|
—
|
|
|
274
|
|
|
—
|
|
|
—
|
|
|
274
|
|
Marketing
|
—
|
|
|
1,297
|
|
|
—
|
|
|
—
|
|
|
1,297
|
|
Other
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
3,038
|
|
|
—
|
|
|
—
|
|
|
3,038
|
|
Operating Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
Marketing purchases
|
—
|
|
|
1,320
|
|
|
—
|
|
|
—
|
|
|
1,320
|
|
Operating expenses
|
—
|
|
|
720
|
|
|
1
|
|
|
(1)
|
|
|
720
|
|
General and administrative expenses
|
—
|
|
|
166
|
|
|
—
|
|
|
—
|
|
|
166
|
|
Restructuring charges
|
—
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
11
|
|
Depreciation, depletion and amortization
|
—
|
|
|
470
|
|
|
1
|
|
|
—
|
|
|
471
|
|
Impairments
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
16
|
|
Loss on sale of assets, net
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Taxes, other than income taxes
|
—
|
|
|
62
|
|
|
—
|
|
|
—
|
|
|
62
|
|
|
—
|
|
|
2,767
|
|
|
2
|
|
|
(1)
|
|
|
2,768
|
|
Operating Income (Loss)
|
—
|
|
|
271
|
|
|
(2)
|
|
|
1
|
|
|
270
|
|
Interest Expense, Net
|
65
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65
|
|
Gain on Derivatives
|
—
|
|
|
274
|
|
|
—
|
|
|
—
|
|
|
274
|
|
Gain on Early Extinguishment of Debt
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Other Loss, Net
|
—
|
|
|
(7)
|
|
|
—
|
|
|
—
|
|
|
(7)
|
|
Equity in Earnings of Subsidiaries
|
947
|
|
|
(2)
|
|
|
—
|
|
|
(945)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
890
|
|
|
536
|
|
|
(2)
|
|
|
(944)
|
|
|
480
|
|
Benefit from Income Taxes
|
—
|
|
|
(411)
|
|
|
—
|
|
|
—
|
|
|
(411)
|
|
Net Income (Loss)
|
$
|
890
|
|
|
$
|
947
|
|
|
$
|
(2)
|
|
|
$
|
(944)
|
|
|
$
|
891
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
$
|
890
|
|
|
$
|
947
|
|
|
$
|
(2)
|
|
|
$
|
(944)
|
|
|
$
|
891
|
|
Other comprehensive income
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Comprehensive Income (Loss)
|
$
|
893
|
|
|
$
|
947
|
|
|
$
|
(2)
|
|
|
$
|
(944)
|
|
|
$
|
894
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Parent
|
|
Guarantors
|
|
Non-Guarantors
|
|
Eliminations
|
|
Consolidated
|
Year ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
Gas sales
|
$
|
—
|
|
|
$
|
1,998
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,998
|
|
Oil sales
|
—
|
|
|
196
|
|
|
—
|
|
|
—
|
|
|
196
|
|
NGL sales
|
—
|
|
|
352
|
|
|
—
|
|
|
—
|
|
|
352
|
|
Marketing
|
—
|
|
|
1,222
|
|
|
—
|
|
|
—
|
|
|
1,222
|
|
Gas gathering
|
—
|
|
|
89
|
|
|
—
|
|
|
—
|
|
|
89
|
|
Other
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
3,862
|
|
|
—
|
|
|
—
|
|
|
3,862
|
|
Operating Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
Marketing purchases
|
—
|
|
|
1,229
|
|
|
—
|
|
|
—
|
|
|
1,229
|
|
Operating expenses
|
—
|
|
|
785
|
|
|
—
|
|
|
—
|
|
|
785
|
|
General and administrative expenses
|
—
|
|
|
209
|
|
|
—
|
|
|
—
|
|
|
209
|
|
Restructuring charges
|
—
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
39
|
|
Depreciation, depletion and amortization
|
—
|
|
|
560
|
|
|
—
|
|
|
—
|
|
|
560
|
|
Impairments
|
—
|
|
|
171
|
|
|
—
|
|
|
—
|
|
|
171
|
|
Gain on sale of assets, net
|
—
|
|
|
(17)
|
|
|
—
|
|
|
—
|
|
|
(17)
|
|
Taxes, other than income taxes
|
—
|
|
|
89
|
|
|
—
|
|
|
—
|
|
|
89
|
|
|
—
|
|
|
3,065
|
|
|
—
|
|
|
—
|
|
|
3,065
|
|
Operating Income
|
—
|
|
|
797
|
|
|
—
|
|
|
—
|
|
|
797
|
|
Interest Expense, Net
|
124
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
124
|
|
Loss on Derivatives
|
—
|
|
|
(118)
|
|
|
—
|
|
|
—
|
|
|
(118)
|
|
Loss on Early Extinguishment of Debt
|
(17)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17)
|
|
|
|
|
|
|
|
|
|
|
|
Equity in Earnings of Subsidiaries
|
678
|
|
|
—
|
|
|
—
|
|
|
(678)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
537
|
|
|
679
|
|
|
—
|
|
|
(678)
|
|
|
538
|
|
Provision for Income Taxes
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Net Income (Loss)
|
$
|
537
|
|
|
$
|
678
|
|
|
$
|
—
|
|
|
$
|
(678)
|
|
|
$
|
537
|
|
|
|
|
|
|
|
|
|
|
|
Participating securities – mandatory convertible preferred stock
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Net Income (Loss) Attributable to Common Stock
|
$
|
535
|
|
|
$
|
678
|
|
|
$
|
—
|
|
|
$
|
(678)
|
|
|
$
|
535
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
$
|
537
|
|
|
$
|
678
|
|
|
$
|
—
|
|
|
$
|
(678)
|
|
|
$
|
537
|
|
Other comprehensive income
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Comprehensive Income (Loss)
|
$
|
545
|
|
|
$
|
678
|
|
|
$
|
—
|
|
|
$
|
(678)
|
|
|
$
|
545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Parent
|
|
Guarantors
|
|
Non-Guarantors
|
|
Eliminations
|
|
Consolidated
|
Year ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
Operating Revenues:
|
|
|
|
|
|
|
|
|
|
Gas sales
|
$
|
—
|
|
|
$
|
1,793
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,793
|
|
Oil sales
|
—
|
|
|
102
|
|
|
—
|
|
|
—
|
|
|
102
|
|
NGL sales
|
—
|
|
|
206
|
|
|
—
|
|
|
—
|
|
|
206
|
|
Marketing
|
—
|
|
|
972
|
|
|
—
|
|
|
—
|
|
|
972
|
|
Gas gathering
|
—
|
|
|
126
|
|
|
—
|
|
|
—
|
|
|
126
|
|
Other
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
3,203
|
|
|
—
|
|
|
—
|
|
|
3,203
|
|
Operating Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
Marketing purchases
|
—
|
|
|
976
|
|
|
—
|
|
|
—
|
|
|
976
|
|
Operating expenses
|
—
|
|
|
671
|
|
|
—
|
|
|
—
|
|
|
671
|
|
General and administrative expenses
|
—
|
|
|
233
|
|
|
—
|
|
|
—
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
—
|
|
|
504
|
|
|
—
|
|
|
—
|
|
|
504
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of assets, net
|
—
|
|
|
(6)
|
|
|
—
|
|
|
—
|
|
|
(6)
|
|
Taxes, other than income taxes
|
—
|
|
|
94
|
|
|
—
|
|
|
—
|
|
|
94
|
|
|
—
|
|
|
2,472
|
|
|
—
|
|
|
—
|
|
|
2,472
|
|
Operating Income
|
—
|
|
|
731
|
|
|
—
|
|
|
—
|
|
|
731
|
|
Interest Expense, Net
|
135
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
135
|
|
Gain on Derivatives
|
—
|
|
|
422
|
|
|
—
|
|
|
—
|
|
|
422
|
|
Loss on Early Extinguishment of Debt
|
(70)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(70)
|
|
Other Income, Net
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
Equity in Earnings of Subsidiaries
|
1,251
|
|
|
—
|
|
|
—
|
|
|
(1,251)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
1,046
|
|
|
1,158
|
|
|
—
|
|
|
(1,251)
|
|
|
953
|
|
Benefit from Income Taxes
|
—
|
|
|
(93)
|
|
|
—
|
|
|
—
|
|
|
(93)
|
|
Net Income (Loss)
|
$
|
1,046
|
|
|
$
|
1,251
|
|
|
$
|
—
|
|
|
$
|
(1,251)
|
|
|
$
|
1,046
|
|
Mandatory convertible preferred stock dividend
|
108
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
108
|
|
Participating securities – mandatory convertible preferred stock
|
123
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
123
|
|
Net Income (Loss) Attributable to Common Stock
|
$
|
815
|
|
|
$
|
1,251
|
|
|
$
|
—
|
|
|
$
|
(1,251)
|
|
|
$
|
815
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
$
|
1,046
|
|
|
$
|
1,251
|
|
|
$
|
—
|
|
|
$
|
(1,251)
|
|
|
$
|
1,046
|
|
Other comprehensive income (loss)
|
(5)
|
|
|
6
|
|
|
6
|
|
|
(12)
|
|
|
(5)
|
|
Comprehensive Income (Loss)
|
$
|
1,041
|
|
|
$
|
1,257
|
|
|
$
|
6
|
|
|
$
|
(1,263)
|
|
|
$
|
1,041
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Parent
|
|
Guarantors
|
|
Non-Guarantors
|
|
Eliminations
|
|
Consolidated
|
December 31, 2019
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
Accounts receivable, net
|
—
|
|
|
345
|
|
|
—
|
|
|
—
|
|
|
345
|
|
Other current assets
|
7
|
|
|
322
|
|
|
—
|
|
|
—
|
|
|
329
|
|
Total current assets
|
12
|
|
|
667
|
|
|
—
|
|
|
—
|
|
|
679
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany receivables
|
7,922
|
|
|
—
|
|
|
—
|
|
|
(7,922)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and oil properties, using the full cost method
|
—
|
|
|
25,195
|
|
|
55
|
|
|
—
|
|
|
25,250
|
|
Other
|
169
|
|
|
322
|
|
|
29
|
|
|
—
|
|
|
520
|
|
Less: Accumulated depreciation, depletion and amortization
|
(144)
|
|
|
(20,300)
|
|
|
(59)
|
|
|
—
|
|
|
(20,503)
|
|
Total property and equipment, net
|
25
|
|
|
5,217
|
|
|
25
|
|
|
—
|
|
|
5,267
|
|
|
|
|
|
|
|
|
|
|
|
Investments in subsidiaries (equity method)
|
—
|
|
|
23
|
|
|
—
|
|
|
(23)
|
|
|
—
|
|
Operating lease assets
|
80
|
|
|
79
|
|
|
—
|
|
|
—
|
|
|
159
|
|
Deferred tax assets
|
—
|
|
|
407
|
|
|
—
|
|
|
—
|
|
|
407
|
|
Other long-term assets
|
19
|
|
|
186
|
|
|
—
|
|
|
—
|
|
|
205
|
|
TOTAL ASSETS
|
$
|
8,058
|
|
|
$
|
6,579
|
|
|
$
|
25
|
|
|
$
|
(7,945)
|
|
|
$
|
6,717
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
79
|
|
|
$
|
446
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
525
|
|
Current operating lease liabilities
|
8
|
|
|
26
|
|
|
—
|
|
|
—
|
|
|
34
|
|
Other current liabilities
|
108
|
|
|
181
|
|
|
—
|
|
|
—
|
|
|
289
|
|
Total current liabilities
|
195
|
|
|
653
|
|
|
—
|
|
|
—
|
|
|
848
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany payables
|
—
|
|
|
7,920
|
|
|
2
|
|
|
(7,922)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
2,242
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,242
|
|
Long-term operating lease liabilities
|
66
|
|
|
53
|
|
|
—
|
|
|
—
|
|
|
119
|
|
Pension and other postretirement liabilities
|
43
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
43
|
|
Other long-term liabilities
|
11
|
|
|
208
|
|
|
—
|
|
|
—
|
|
|
219
|
|
Negative carrying amount of subsidiaries, net
|
2,255
|
|
|
—
|
|
|
—
|
|
|
(2,255)
|
|
|
—
|
|
Total long-term liabilities
|
4,617
|
|
|
261
|
|
|
—
|
|
|
(2,255)
|
|
|
2,623
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
Total equity (accumulated deficit)
|
3,246
|
|
|
(2,255)
|
|
|
23
|
|
|
2,232
|
|
|
3,246
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
8,058
|
|
|
$
|
6,579
|
|
|
$
|
25
|
|
|
$
|
(7,945)
|
|
|
$
|
6,717
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Parent
|
|
Guarantors
|
|
Non-Guarantors
|
|
Eliminations
|
|
Consolidated
|
December 31, 2018
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
201
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
201
|
|
Accounts receivable, net
|
4
|
|
|
577
|
|
|
—
|
|
|
—
|
|
|
581
|
|
Other current assets
|
8
|
|
|
166
|
|
|
—
|
|
|
—
|
|
|
174
|
|
Total current assets
|
213
|
|
|
743
|
|
|
—
|
|
|
—
|
|
|
956
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany receivables
|
7,932
|
|
|
—
|
|
|
—
|
|
|
(7,932)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas and oil properties, using the full cost method
|
—
|
|
|
24,128
|
|
|
52
|
|
|
—
|
|
|
24,180
|
|
Other
|
197
|
|
|
301
|
|
|
27
|
|
|
—
|
|
|
525
|
|
Less: Accumulated depreciation, depletion and amortization
|
(154)
|
|
|
(19,840)
|
|
|
(55)
|
|
|
—
|
|
|
(20,049)
|
|
Total property and equipment, net
|
43
|
|
|
4,589
|
|
|
24
|
|
|
—
|
|
|
4,656
|
|
|
|
|
|
|
|
|
|
|
|
Investments in subsidiaries (equity method)
|
—
|
|
|
24
|
|
|
—
|
|
|
(24)
|
|
|
—
|
|
Other long-term assets
|
19
|
|
|
166
|
|
|
—
|
|
|
—
|
|
|
185
|
|
TOTAL ASSETS
|
$
|
8,207
|
|
|
$
|
5,522
|
|
|
$
|
24
|
|
|
$
|
(7,956)
|
|
|
$
|
5,797
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
113
|
|
|
$
|
496
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
609
|
|
Other current liabilities
|
115
|
|
|
122
|
|
|
—
|
|
|
—
|
|
|
237
|
|
Total current liabilities
|
228
|
|
|
618
|
|
|
—
|
|
|
—
|
|
|
846
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany payables
|
—
|
|
|
7,932
|
|
|
—
|
|
|
(7,932)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
2,318
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,318
|
|
Pension and other postretirement liabilities
|
46
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46
|
|
Other long-term liabilities
|
54
|
|
|
171
|
|
|
—
|
|
|
—
|
|
|
225
|
|
Negative carrying amount of subsidiaries, net
|
3,199
|
|
|
—
|
|
|
—
|
|
|
(3,199)
|
|
|
—
|
|
Total long-term liabilities
|
5,617
|
|
|
171
|
|
|
—
|
|
|
(3,199)
|
|
|
2,589
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
|
Total equity (accumulated deficit)
|
2,362
|
|
|
(3,199)
|
|
|
24
|
|
|
3,175
|
|
|
2,362
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
8,207
|
|
|
$
|
5,522
|
|
|
$
|
24
|
|
|
$
|
(7,956)
|
|
|
$
|
5,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Parent
|
|
Guarantors
|
|
Non-Guarantors
|
|
Eliminations
|
|
Consolidated
|
Year ended December 31, 2019
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
$
|
1,280
|
|
|
$
|
629
|
|
|
$
|
—
|
|
|
$
|
(945)
|
|
|
$
|
964
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
Capital investments
|
(4)
|
|
|
(1,093)
|
|
|
(2)
|
|
|
—
|
|
|
(1,099)
|
|
Proceeds from the sale of property and equipment
|
—
|
|
|
54
|
|
|
—
|
|
|
—
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
(4)
|
|
|
(1,039)
|
|
|
(2)
|
|
|
—
|
|
|
(1,045)
|
|
Financing activities
|
|
|
|
|
|
|
|
|
|
Intercompany activities
|
(1,357)
|
|
|
410
|
|
|
2
|
|
|
945
|
|
|
—
|
|
Payments on current portion of long-term debt
|
(52)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(52)
|
|
Payments on long-term debt
|
(54)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(54)
|
|
Payments on revolving credit facility
|
(532)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(532)
|
|
Borrowings under revolving credit facility
|
566
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
566
|
|
Change in bank drafts outstanding
|
(19)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(19)
|
|
Debt issuance costs
|
(3)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3)
|
|
Purchase of treasury stock
|
(21)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21)
|
|
Cash paid for tax withholding
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
Other
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
(1,472)
|
|
|
410
|
|
|
2
|
|
|
945
|
|
|
(115)
|
|
Decrease in cash and cash equivalents
|
(196)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(196)
|
|
Cash and cash equivalents at beginning of year
|
201
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
201
|
|
Cash and cash equivalents at end of year
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
$
|
304
|
|
|
$
|
1,595
|
|
|
$
|
—
|
|
|
$
|
(676)
|
|
|
$
|
1,223
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
Capital investments
|
(20)
|
|
|
(1,270)
|
|
|
—
|
|
|
—
|
|
|
(1,290)
|
|
Proceeds from the sale of property and equipment
|
—
|
|
|
1,643
|
|
|
—
|
|
|
—
|
|
|
1,643
|
|
Other
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
Net cash used in investing activities
|
(20)
|
|
|
379
|
|
|
—
|
|
|
—
|
|
|
359
|
|
Financing activities
|
|
|
|
|
|
|
|
|
|
Intercompany activities
|
1,300
|
|
|
(1,976)
|
|
|
—
|
|
|
676
|
|
|
—
|
|
Payments on long-term debt
|
(2,095)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,095)
|
|
Payments on revolving credit facility
|
(1,983)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,983)
|
|
Borrowings under revolving credit facility
|
1,983
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,983
|
|
Change in bank drafts outstanding
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
Debt issuance costs
|
(9)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9)
|
|
Purchase of treasury stock
|
(180)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(180)
|
|
Preferred stock dividend
|
(27)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(27)
|
|
Cash paid for tax withholding
|
(3)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3)
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
(997)
|
|
|
(1,976)
|
|
|
—
|
|
|
676
|
|
|
(2,297)
|
|
Decrease in cash and cash equivalents
|
(713)
|
|
|
(2)
|
|
|
—
|
|
|
—
|
|
|
(715)
|
|
Cash and cash equivalents at beginning of year
|
914
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
916
|
|
Cash and cash equivalents at end of year
|
$
|
201
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
(in millions)
|
Parent
|
|
Guarantors
|
|
Non-Guarantors
|
|
Eliminations
|
|
Consolidated
|
Year ended December 31, 2017
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
$
|
1,019
|
|
|
$
|
1,327
|
|
|
$
|
—
|
|
|
$
|
(1,249)
|
|
|
$
|
1,097
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
Capital investments
|
(13)
|
|
|
(1,250)
|
|
|
(5)
|
|
|
—
|
|
|
(1,268)
|
|
Proceeds from the sale of property and equipment
|
1
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
10
|
|
Other
|
1
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
6
|
|
Net cash used in investing activities
|
(11)
|
|
|
(1,236)
|
|
|
(5)
|
|
|
—
|
|
|
(1,252)
|
|
Financing activities
|
|
|
|
|
|
|
|
|
|
Intercompany activities
|
(1,158)
|
|
|
(96)
|
|
|
5
|
|
|
1,249
|
|
|
—
|
|
Payments on short-term debt
|
(328)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(328)
|
|
Payments on long-term debt
|
(1,139)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,139)
|
|
Proceeds from issuance of long-term debt
|
1,150
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,150
|
|
Change in bank drafts outstanding
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
Debt issuance costs
|
(24)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(24)
|
|
Cash paid for tax withholding
|
(2)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2)
|
|
Preferred stock dividend
|
(16)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16)
|
|
Other
|
(2)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2)
|
|
Net cash provided by (used in) financing activities
|
(1,510)
|
|
|
(96)
|
|
|
5
|
|
|
1,249
|
|
|
(352)
|
|
Decrease in cash and cash equivalents
|
(502)
|
|
|
(5)
|
|
|
—
|
|
|
—
|
|
|
(507)
|
|
Cash and cash equivalents at beginning of year
|
1,416
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
1,423
|
|
Cash and cash equivalents at end of year
|
$
|
914
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
916
|
|
(17) SUBSEQUENT EVENTS
On February 4, 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of its organizational structure. Affected employees were offered a severance package, which included a one-time cash payment depending on length of service and, if applicable, the current value of a portion of their unvested long-term incentive awards that were forfeited. The plan is expected to be substantially implemented by the end of the first quarter of 2020. The Company expects to record a pre-tax charge to earnings of approximately $9 million in the first quarter of 2020 related to the severance payments.
SUPPLEMENTAL QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the years ended December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions, except share amounts)
|
1st Quarter
|
|
2nd Quarter
|
|
3rd Quarter
|
|
4th Quarter
|
|
2019
|
|
|
|
|
|
|
Operating revenues
|
$
|
990
|
|
|
$
|
667
|
|
|
$
|
636
|
|
|
$
|
745
|
|
Operating income (loss)
|
213
|
|
|
22
|
|
|
(29)
|
|
|
64
|
|
Net income attributable to common stock
|
594
|
|
|
138
|
|
|
49
|
|
|
110
|
|
Earnings per share – Basic
|
1.10
|
|
|
0.26
|
|
|
0.09
|
|
|
0.20
|
|
Earnings per share – Diluted
|
1.10
|
|
|
0.26
|
|
|
0.09
|
|
|
0.20
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
Operating revenues
|
$
|
920
|
|
|
$
|
816
|
|
|
$
|
951
|
|
|
$
|
1,175
|
|
Operating income
|
255
|
|
|
124
|
|
|
66
|
|
|
352
|
|
Net income (loss) attributable to common stock
|
205
|
|
|
51
|
|
|
(29)
|
|
|
307
|
|
Earnings (loss) per share – Basic
|
0.36
|
|
|
0.09
|
|
|
(0.05)
|
|
|
0.54
|
|
Earnings (loss) per share – Diluted
|
0.36
|
|
|
0.09
|
|
|
(0.05)
|
|
|
0.54
|
|
SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
The Company’s operating natural gas and oil properties are located solely in the United States. The Company also has licenses to properties in Canada, the development of which is subject to an indefinite moratorium. See “Our Operations – Other – New Brunswick, Canada” in Item 1 of Part 1 of this Annual Report.
Net Capitalized Costs
The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
Proved properties
|
$
|
23,744
|
|
|
$
|
22,425
|
|
Unproved properties
|
1,506
|
|
|
1,755
|
|
Total capitalized costs
|
25,250
|
|
|
24,180
|
|
Less: Accumulated depreciation, depletion and amortization
|
(20,203)
|
|
|
(19,761)
|
|
Net capitalized costs
|
$
|
5,047
|
|
|
$
|
4,419
|
|
Natural gas and oil properties not subject to amortization represent investments in unproved properties and major development projects in which the Company owns an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress. The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
|
Prior
|
|
Total
|
Property acquisition costs
|
$
|
45
|
|
|
$
|
40
|
|
|
$
|
32
|
|
|
$
|
1,106
|
|
|
$
|
1,223
|
|
Exploration and development costs
|
53
|
|
|
23
|
|
|
16
|
|
|
12
|
|
|
104
|
|
Capitalized interest
|
67
|
|
|
47
|
|
|
27
|
|
|
38
|
|
|
179
|
|
|
$
|
165
|
|
|
$
|
110
|
|
|
$
|
75
|
|
|
$
|
1,156
|
|
|
$
|
1,506
|
|
Of the total net unevaluated costs excluded from amortization as of December 31, 2019, approximately $1.2 billion is related to undeveloped properties in Southwest Appalachia (acquired in 2014 and 2015) and approximately $10 million is related to the acquisition of undeveloped properties in Northeast Appalachia. Additionally, the Company has approximately $179 million of unevaluated capitalized interest and $95 million of unevaluated costs related to wells in progress. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.
Costs Incurred in Natural Gas and Oil Exploration and Development
The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions, except per Mcfe amounts)
|
2019
|
|
2018
|
|
2017
|
Unproved property acquisition costs
|
$
|
162
|
|
|
$
|
164
|
|
|
$
|
194
|
|
Exploration costs
|
2
|
|
|
5
|
|
|
22
|
|
Development costs
|
936
|
|
|
1,014
|
|
|
1,024
|
|
Capitalized costs incurred
|
$
|
1,100
|
|
|
$
|
1,183
|
|
|
$
|
1,240
|
|
Full cost pool amortization per Mcfe
|
$
|
0.56
|
|
|
$
|
0.51
|
|
|
$
|
0.45
|
|
Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $109 million, $115 million and $113 million during 2019, 2018 and 2017, respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $77 million, $90 million and $99 million during 2019, 2018 and 2017, respectively, which were directly related to the acquisition, exploration and development of the Company’s natural gas and oil properties.
Results of Operations from Natural Gas and Oil Producing Activities
The table below sets forth the results of operations from natural gas and oil producing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Sales
|
$
|
1,703
|
|
|
$
|
2,525
|
|
|
$
|
2,086
|
|
Production (lifting) costs
|
(781)
|
|
|
(974)
|
|
|
(891)
|
|
Depreciation, depletion and amortization
|
(462)
|
|
|
(514)
|
|
|
(440)
|
|
|
|
|
|
|
|
|
460
|
|
|
1,037
|
|
|
755
|
|
Provision for income taxes (1)
|
110
|
|
|
—
|
|
|
—
|
|
Results of operations (2)
|
$
|
350
|
|
|
$
|
1,037
|
|
|
$
|
755
|
|
(1)Prior to the recognition of a valuation allowance, in 2018 and 2017 the Company recognized income tax provisions of $254 million and $287 million, respectively.
(2)Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 6.
The results of operations shown above exclude general and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.
Natural Gas and Oil Reserve Quantities
The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties, and accounted for approximately 99% of the present worth of the Company’s total proved reserves as of December 31 of 2019, 2018 and 2017. A reserve audit is not the same as a financial audit, and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates are inherently imprecise, and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, historical prices of natural gas and crude oil and analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business – Exploration and Production” in Item 1 of this Annual Report.
The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2019, 2018 and 2017, all of which were located in the United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(Bcf)
|
|
Oil
(MBbls)
|
|
NGL
(MBbls)
|
|
Total
(Bcfe)
|
December 31, 2016
|
4,866
|
|
|
10,523
|
|
|
53,931
|
|
|
5,253
|
|
Revisions of previous estimates due to price
|
1,327
|
|
|
3,197
|
|
|
57,447
|
|
|
1,691
|
|
Revisions of previous estimates other than price
|
571
|
|
|
(1,529)
|
|
|
13,102
|
|
|
641
|
|
Extensions, discoveries and other additions (1)
|
5,159
|
|
|
55,772
|
|
|
432,220
|
|
|
8,087
|
|
Production
|
(797)
|
|
|
(2,327)
|
|
|
(14,245)
|
|
|
(897)
|
|
Acquisition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Disposition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2017
|
11,126
|
|
|
65,636
|
|
|
542,455
|
|
|
14,775
|
|
Revisions of previous estimates due to price
|
96
|
|
|
788
|
|
|
8,912
|
|
|
154
|
|
Revisions of previous estimates other than price
|
316
|
|
|
410
|
|
|
8,855
|
|
|
372
|
|
Extensions, discoveries and other additions
|
753
|
|
|
5,830
|
|
|
36,823
|
|
|
1,009
|
|
Production
|
(807)
|
|
|
(3,407)
|
|
|
(19,706)
|
|
|
(946)
|
|
Acquisition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Disposition of reserves in place (2)
|
(3,440)
|
|
|
(250)
|
|
|
(276)
|
|
|
(3,443)
|
|
December 31, 2018
|
8,044
|
|
|
69,007
|
|
|
577,063
|
|
|
11,921
|
|
Revisions of previous estimates due to price
|
(480)
|
|
|
(2,041)
|
|
|
(37,492)
|
|
|
(717)
|
|
Revisions of previous estimates other than price (3)
|
685
|
|
|
3,707
|
|
|
65,869
|
|
|
1,102
|
|
Extensions, discoveries and other additions
|
992
|
|
|
6,948
|
|
|
26,941
|
|
|
1,195
|
|
Production
|
(609)
|
|
|
(4,696)
|
|
|
(23,620)
|
|
|
(778)
|
|
Acquisition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Disposition of reserves in place
|
(2)
|
|
|
—
|
|
|
—
|
|
|
(2)
|
|
December 31, 2019
|
8,630
|
|
|
72,925
|
|
|
608,761
|
|
|
12,721
|
|
(1)The 2017 PUD additions are primarily associated with the increase in commodity prices.
(2)The 2018 disposition is primarily associated with the Fayetteville Shale sale.
(3)Revisions of previous estimates other than price includes 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(Bcf)
|
|
Oil
(MBbls)
|
|
NGL
(MBbls)
|
|
Total
(Bcfe)
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
6,979
|
|
|
14,513
|
|
|
142,213
|
|
|
7,920
|
|
December 31, 2018
|
4,395
|
|
|
18,037
|
|
|
175,480
|
|
|
5,557
|
|
December 31, 2019
|
4,906
|
|
|
26,124
|
|
|
226,271
|
|
|
6,421
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
4,147
|
|
|
51,123
|
|
|
400,242
|
|
|
6,855
|
|
December 31, 2018
|
3,649
|
|
|
50,970
|
|
|
401,583
|
|
|
6,364
|
|
December 31, 2019
|
3,724
|
|
|
46,801
|
|
|
382,490
|
|
|
6,300
|
|
The Company’s estimated proved natural gas, oil and NGL reserves were 12,721 Bcfe at December 31, 2019, compared to 11,921 Bcfe at December 31, 2018. The Company’s reserves increased in 2019, compared to 2018, as positive extensions, discoveries, other additions and non-price revisions in Appalachia were only partially offset by negative price revisions. The decrease in the Company’s reserves in 2018 primarily resulted from the disposition of the reserves related to the Fayetteville Shale and was only partially offset by positive extensions, discoveries, other additions and revisions in Appalachia. The increase in the Company’s reserves in 2017 was primarily due to extensions, discoveries and other additions in Appalachia along with increases in both price and performance revisions across the portfolio.
The following table summarizes the changes in reserves for 2017, 2018 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia
|
|
|
|
Fayetteville
|
|
|
|
|
(in Bcfe)
|
Northeast
|
|
Southwest
|
|
Shale (1)
|
|
Other (2)
|
|
Total
|
December 31, 2016
|
1,574
|
|
|
677
|
|
|
2,997
|
|
|
5
|
|
|
5,253
|
|
Net revisions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price revisions
|
903
|
|
|
738
|
|
|
49
|
|
|
1
|
|
|
1,691
|
|
Performance and production revisions
|
154
|
|
|
125
|
|
|
358
|
|
|
4
|
|
|
641
|
|
Total net revisions
|
1,057
|
|
|
863
|
|
|
407
|
|
|
5
|
|
|
2,332
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
790
|
|
|
419
|
|
|
48
|
|
|
1
|
|
|
1,258
|
|
Proved undeveloped
|
1,100
|
|
|
5,186
|
|
|
543
|
|
|
—
|
|
|
6,829
|
|
Total reserve additions
|
1,890
|
|
|
5,605
|
|
|
591
|
|
|
1
|
|
|
8,087
|
|
Production
|
(395)
|
|
|
(183)
|
|
|
(316)
|
|
|
(3)
|
|
|
(897)
|
|
Acquisition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Disposition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2017
|
4,126
|
|
|
6,962
|
|
|
3,679
|
|
|
8
|
|
|
14,775
|
|
Net revisions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price revisions
|
41
|
|
|
106
|
|
|
6
|
|
|
1
|
|
|
154
|
|
Performance and production revisions
|
107
|
|
|
272
|
|
|
(6)
|
|
|
(1)
|
|
|
372
|
|
Total net revisions
|
148
|
|
|
378
|
|
|
—
|
|
|
—
|
|
|
526
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
154
|
|
|
22
|
|
|
1
|
|
|
—
|
|
|
177
|
|
Proved undeveloped
|
397
|
|
|
435
|
|
|
—
|
|
|
—
|
|
|
832
|
|
Total reserve additions
|
551
|
|
|
457
|
|
|
1
|
|
|
—
|
|
|
1,009
|
|
Production
|
(459)
|
|
|
(243)
|
|
|
(243)
|
|
|
(1)
|
|
|
(946)
|
|
Acquisition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Disposition of reserves in place
|
—
|
|
|
—
|
|
|
(3,437)
|
|
|
(6)
|
|
|
(3,443)
|
|
December 31, 2018
|
4,366
|
|
|
7,554
|
|
|
—
|
|
|
1
|
|
|
11,921
|
|
Net revisions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price revisions
|
(57)
|
|
|
(660)
|
|
|
—
|
|
|
—
|
|
|
(717)
|
|
Performance and production revisions (3)
|
127
|
|
|
975
|
|
|
—
|
|
|
—
|
|
|
1,102
|
|
Total net revisions
|
70
|
|
|
315
|
|
|
—
|
|
|
—
|
|
|
385
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
185
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
191
|
|
Proved undeveloped
|
677
|
|
|
327
|
|
|
—
|
|
|
—
|
|
|
1,004
|
|
Total reserve additions
|
862
|
|
|
333
|
|
|
—
|
|
|
—
|
|
|
1,195
|
|
Production
|
(459)
|
|
|
(319)
|
|
|
—
|
|
|
—
|
|
|
(778)
|
|
Acquisition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Disposition of reserves in place
|
(2)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2)
|
|
December 31, 2019
|
4,837
|
|
|
7,883
|
|
|
—
|
|
|
1
|
|
|
12,721
|
|
(1)The Fayetteville Shale E&P assets and associated reserves were divested in December 2018.
(2)Other includes properties outside of Appalachia and Fayetteville Shale.
(3)Performance and production revisions includes 109 Bcfe of proved undeveloped reserves reclassified to unproved due to changes in the drilling plan, in accordance with the SEC five-year rule.
The Company’s December 31, 2019 proved reserves included 929 Bcfe of proved undeveloped reserves from 90 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties had a negative present value of $50 million when discounted at 10%. The Company made a final investment decision and is committed to developing these reserves within the next five years from the date of initial booking.
The Company’s December 31, 2018 proved reserves included 190 Bcfe of proved undeveloped reserves from 30 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $24 million present value when discounted at 10%. The Company’s December 31, 2017 proved reserves included 1,375
Bcfe of proved undeveloped reserves from 330 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $124 million present value when discounted at 10%.
The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis, offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.
Standardized Measure of Discounted Future Net Cash Flows
The following standardized measures of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2019, 2018 and 2017 are calculated after income taxes, discounted using a 10% annual discount rate and do not purport to present the fair market value of the Company’s proved gas, oil and NGL reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Future cash inflows
|
$
|
27,003
|
|
|
$
|
34,523
|
|
|
$
|
36,576
|
|
Future production costs
|
(14,981)
|
|
|
(15,347)
|
|
|
(18,390)
|
|
Future development costs (1)
|
(3,246)
|
|
|
(4,095)
|
|
|
(4,676)
|
|
Future income tax expense
|
(476)
|
|
|
(2,079)
|
|
|
(1,342)
|
|
Future net cash flows
|
8,300
|
|
|
13,002
|
|
|
12,168
|
|
10% annual discount for estimated timing of cash flows
|
(4,600)
|
|
|
(7,003)
|
|
|
(6,606)
|
|
Standardized measure of discounted future net cash flows
|
$
|
3,700
|
|
|
$
|
5,999
|
|
|
$
|
5,562
|
|
(1)Includes abandonment costs.
Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure above were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Natural gas (per MMBtu)
|
$
|
2.58
|
|
|
$
|
3.10
|
|
|
$
|
2.98
|
|
Oil (per Bbl)
|
55.69
|
|
|
65.56
|
|
|
47.79
|
|
NGLs (per Bbl)
|
11.58
|
|
|
17.64
|
|
|
14.41
|
|
Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.
Following is an analysis of changes in the standardized measure during 2019, 2018 and 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2019
|
|
2018
|
|
2017
|
Standardized measure, beginning of year
|
$
|
5,999
|
|
|
$
|
5,562
|
|
|
$
|
1,665
|
|
Sales and transfers of natural gas and oil produced, net of production costs
|
(923)
|
|
|
(1,564)
|
|
|
(1,191)
|
|
Net changes in prices and production costs
|
(3,510)
|
|
|
2,162
|
|
|
1,963
|
|
Extensions, discoveries, and other additions, net of future production and development costs
|
234
|
|
|
335
|
|
|
1,715
|
|
Acquisition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
Sales of reserves in place
|
(2)
|
|
|
(2,022)
|
|
|
—
|
|
Revisions of previous quantity estimates
|
152
|
|
|
361
|
|
|
1,721
|
|
Net change in income taxes
|
491
|
|
|
(304)
|
|
|
(222)
|
|
Changes in estimated future development costs
|
621
|
|
|
(166)
|
|
|
(6)
|
|
Previously estimated development costs incurred during the year
|
704
|
|
|
536
|
|
|
55
|
|
Changes in production rates (timing) and other
|
(718)
|
|
|
521
|
|
|
(304)
|
|
Accretion of discount
|
652
|
|
|
578
|
|
|
166
|
|
Standardized measure, end of year
|
$
|
3,700
|
|
|
$
|
5,999
|
|
|
$
|
5,562
|
|