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”. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the lower 48 United States.
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, Ohio 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, Ohio 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, Ohio and West Virginia are herein referred to as “Appalachia.” We also have drilling rigs located in Appalachia, and we provide certain oilfield products and services, principally serving our E&P operations though vertical integration.
On November 13, 2020, we closed on our Agreement and Plan of Merger (the “Merger agreement”) with Montage Resources Corporation (“Montage”) pursuant to which Montage merged with and into Southwestern, with Southwestern continuing as the surviving company (the “Merger”). The Merger expanded our footprint in Appalachia by supplementing our Northeast Appalachia and Southwest Appalachia operations and by expanding our operations into Ohio. See Note 3 to the consolidated financial statements of this Annual Report for more information on the Merger.
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.
Focus in 2020. We entered 2020 with a continued focus on optimizing our cost structure, maximizing margins in each of our core areas of business while further developing our knowledge of our asset base and looking for strategic transactions that take advantage of our core strengths. The recent Merger and the associated expected cost and operational synergies is a reflection of this strategy. While COVID-19 brought challenges of lower demand for certain of our products resulting in lower oil and NGL pricing (discussed below), we exercised our capital and operational agility by quickly shifting our investments to our higher return natural gas assets. We remained committed to our focus on creating sustainable value with the goal of generating cash flow above and beyond our operational needs, while at the same time maintaining our leading position as stewards of the environment. We continued to protect our financial strength through bond repurchases at a discount as well as a robust derivative program designed to ensure certain cash flow levels by reducing our exposure to commodity price volatility.
Lower natural gas, oil and NGL prices present challenges to our industry and our Company, as do changes in laws, regulations and investor sentiment and other key factors described under “Risk Factors” in Item 1A of this Annual Report. During the year ended December 31, 2020, the economic impact of the COVID-19 pandemic and related governmental and societal measures (discussed below), along with the disagreements between OPEC and Russia on production levels, caused oil prices to decrease significantly in the first and second quarters of 2020. While oil pricing partially recovered late in the second quarter and continued to improve toward the end of the year, gains on our settled derivatives offset a large portion of the impact of the overall decline in prices. Although we currently expect to maintain a robust rolling three-year derivative portfolio, there can be no
assurance that we will be able to add derivative positions to cover our expected production at favorable prices. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A and Note 6 - Derivatives and Risk Management, in the consolidated financial statements included in this Annual Report for further details.
Market Conditions and Commodity Prices
During 2020, we did not experience any material impact to our ability to operate or market our production due to the direct or indirect impacts of the COVID-19 pandemic. In early March 2020, we instituted additional health measures at our facilities and banned nonessential travel. In mid-March, in advance of state and local governments restricting business operations and imposing “stay-at-home” directives in Pennsylvania, West Virginia and Texas (where our operations and offices are located), we notified employees that those whose work does not require a physical presence should work from home. In late September 2020, based on the totality of the relevant data in each community, we reinstituted a phased return program of office-based employees, and we have instituted additional measures designed to prevent the possible spread of the virus, including social distancing and appropriate personal protective equipment. The U.S. Department of Homeland Security classifies individuals engaged in and supporting exploration for and production of natural gas, oil and NGLs as “essential critical infrastructure workforce,” and to date, state and local governments have followed this guidance and exempted these activities from business closures. Should this situation change, our access to supplies or workers to drill, complete and operate wells could be materially and adversely affected.
Beginning late in the first quarter and extending through most of 2020, decreased transportation, manufacturing and general economic activity levels prompted by governmental and societal actions to COVID-19 reduced the demand for refined products such as gasoline, distillate and jet fuel and other refined products, as well as NGLs. Reduced demand, along with geopolitical events such as the disagreements between OPEC and Russia on production levels, caused a significant decline in oil and NGL pricing late in the first quarter of 2020. Although WTI prices for oil were 31% lower in 2020, as compared to 2019, our average realized price received for oil, including the impact of our derivatives, was only 5% lower in 2020, compared to the previous year. We recognized an additional $0.36 per Mcf on our gas production through our derivative program for the year ended December 31, 2020, an increase of $0.16 per Mcf over the prior year, which partially offset a $0.55 decrease in the NYMEX price over the same period.
Late in the second quarter of 2020 and extending into the fourth quarter of 2020, certain states and local governments began the process of loosening restrictions, allowing businesses to reopen and lifting stay-at-home orders. In addition, OPEC and other countries instituted oil production curtailments. During this same period, oil and NGL prices have improved from historic lows in April due to lower industry-wide production levels and increased export demand, respectively. Further, although the reduced production of natural gas associated with oil wells dampened the effect of lower natural gas demand early in the second quarter, high natural gas storage inventories and lower LNG demand for U.S. cargoes led to a natural gas price decline late in the second quarter. During the third quarter of 2020, as more clarity emerged regarding the projected path for European natural gas storage, global LNG prices rallied substantially and signaled a resumption of U.S. LNG exports beginning in late September 2020. In addition, the recovery of U.S. natural gas production was less robust than most market estimates, which kept storage balances below capacity through the end of the injection season in October 2020. As a result of these events, the demand and related pricing for natural gas have improved from earlier in the year, and we continue to mitigate pricing risk for all of our commodities through our proactive derivative program.
The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the effectiveness of the vaccines and the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. We will continually monitor our 2021 capital investment program to take into account these changed conditions and proactively adjust our activities and plans. Therefore, while this continued matter could potentially disrupt our operations, the degree of the potentially adverse financial impact cannot be reasonably estimated at this time.
Recent Financial and Operating Results
Significant operating and financial highlights for 2020 include:
Total Company
•Completion of the Merger with Montage on November 13, 2020, acquiring approximately 1,375 producing wells and approximately 320,000 net acres.
•Completion of a public offering of 63,250,000 shares of common stock at $2.50 per share with net proceeds of approximately $152 million after underwriting discounts and offering expenses.
•Closed an offering of $350 million aggregate principal amount of 8.375% senior notes due 2028 with net proceeds of $345 million after underwriting discounts and offering expenses.
•Net loss of $3,112 million, or ($5.42) per diluted share, was down from a net income of $891 million, or $1.65 per diluted share, in 2019. The decrease in 2020 was primarily due to $2,825 million of non-cash full cost ceiling test impairments, an $818 million change in deferred tax provision and lower margins associated with reduced commodity prices.
•Operating loss was $2,871 million for the year ended December 31, 2020, compared to an operating income of $270 million in 2019, primarily due to a $2,825 million non-cash full cost ceiling test impairment in 2020. Excluding the non-cash impairment, operating loss of $46 million decreased $316 million as increased natural gas and liquids production, lower depreciation, depletion and amortization and general and administrative expense were more than offset by reduced commodity prices along with merger-related expenses.
•Net cash provided by operating activities of $528 million decreased 45% from $964 million in 2019 as an improvement in settled derivatives and the impact of higher production was more than offset by lower commodity prices and an increase in operating expenses associated with higher liquids production, along with decreases in capitalized interest expense and working capital.
•Total capital invested of $899 million decreased 21% from $1,140 million in 2019.
E&P
•E&P segment operating loss was $2,864 million in 2020, compared to an operating income of $283 million in 2019. The decrease in 2020 was primarily due to non-cash full cost ceiling impairments of $2,825 million in 2020 and reduced commodity prices.
•Year-end reserves of 11,990 Bcfe decreased 731 Bcfe, or 6%, from 12,721 Bcfe at the end of 2019, as 2,354 Bcfe of acquired reserves, 1,424 Bcfe of positive performance revisions and 741 Bcfe of additions were more than offset by 4,370 Bcfe of downward price revisions and 880 Bcfe of production.
•Total net production of 880 Bcfe, which was comprised of 79% natural gas, 17% NGLs and 4% oil, increased 13% from 778 in 2019, and our liquids production increased 10% over the same period.
•Excluding the effect of derivatives, our realized natural gas price of $1.34 per Mcf, realized oil price of $29.20 per barrel and realized NGL price of $10.24 per barrel decreased 32%, 38% and 12%, respectively, from 2019. Our weighted average realized price excluding the effect of derivatives of $1.53 per Mcfe decreased 30% from the same period in 2019.
•The E&P segment invested $899 million in capital; drilling 98 wells, completing 96 wells and placing 100 wells to sales.
Outlook
In 2021, we expect to continue to exercise capital discipline in our investment program by investing below cash flow from operations, net of changes in working capital, in a focused effort to generate free cash flow. In addition, we expect to continue maintaining our robust hedging program, looking for ways to optimize our cost structure and maximizing margins in each core area of our business while further developing our knowledge of our asset base. By carrying out these objectives, we expect to generate additional free cash flow, which we intend to use to further strengthen our balance sheet. We remain committed to our focus on optimizing our portfolio by concentrating our efforts on our highest return investment opportunities. 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 evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income 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 2020 and fiscal 2019. For the comparison of fiscal 2019 and fiscal 2018, see “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2019 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 27, 2020.
E&P
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
(in millions)
|
2020
|
|
2019
|
|
Revenues
|
$
|
1,348
|
|
(1)
|
$
|
1,703
|
|
(2)
|
Operating costs and expenses
|
4,212
|
|
(3)
|
1,420
|
|
(4)
|
Operating income (loss)
|
$
|
(2,864)
|
|
|
$
|
283
|
|
|
|
|
|
|
|
Gain on derivatives, settled (5)
|
$
|
362
|
|
|
$
|
180
|
|
|
(1)Includes $5 million related to gas balancing for the year ended December 31, 2020.
(2)Includes $2 million in third-party water sales for the year ended December 31, 2019.
(3)Includes $2,825 million of non-cash full-cost ceiling test impairments, $41 million in Montage merger-related expenses, $16 million of restructuring charges and $5 million of non-cash, non-full cost pool impairments for the year ended December 31, 2020.
(4)Includes $11 million of restructuring charges and $13 million of non-cash, non-full cost pool asset impairments for the year ended December 31, 2019.
(5)Includes $11 million and $1 million amortization of premiums paid related to certain natural gas settled derivatives for the years ended December 31, 2020 and 2019, respectively.
Operating Income
•E&P segment operating loss for the year ended December 31, 2020 was $2,864 million compared to an operating income of $283 million for the year ended December 31, 2019. Excluding $2,825 million of non-cash full cost ceiling test impairments recorded in 2020, our E&P segment operating loss was $39 million for the year ended December 31, 2020. This decrease is primarily due to lower margins associated with decreased commodity pricing.
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
|
2019 sales revenues (1)
|
$
|
1,207
|
|
|
$
|
220
|
|
|
$
|
274
|
|
|
$
|
1,701
|
|
Changes associated with prices
|
(447)
|
|
|
(91)
|
|
|
(36)
|
|
|
(574)
|
|
Changes associated with production volumes
|
168
|
|
|
21
|
|
|
27
|
|
|
216
|
|
2020 sales revenues (2)
|
$
|
928
|
|
|
$
|
150
|
|
|
$
|
265
|
|
|
$
|
1,343
|
|
Decrease from 2019
|
(23)
|
%
|
|
(32)
|
%
|
|
(3)
|
%
|
|
(21)
|
%
|
(1)Excludes $2 million in other operating revenues for the year ended December 31, 2019 related to third-party water sales.
(2)Excludes $5 million in other operating revenues for the year ended December 31, 2020 related to gas balancing.
Production Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
|
|
|
Increase/(Decrease)
|
|
2020
|
|
2019
|
|
Natural Gas (Bcf)
|
|
|
|
|
|
Northeast Appalachia
|
473
|
|
|
459
|
|
|
3%
|
Southwest Appalachia
|
221
|
|
|
150
|
|
|
47%
|
Other
|
—
|
|
|
—
|
|
|
—%
|
Total
|
694
|
|
|
609
|
|
|
14%
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
|
|
|
Southwest Appalachia
|
5,124
|
|
|
4,673
|
|
|
10%
|
Other
|
17
|
|
|
23
|
|
|
(26)%
|
Total
|
5,141
|
|
|
4,696
|
|
|
9%
|
|
|
|
|
|
|
NGL (MBbls)
|
|
|
|
|
|
Southwest Appalachia
|
25,923
|
|
|
23,611
|
|
|
10%
|
Other
|
4
|
|
|
9
|
|
|
(56)%
|
Total
|
25,927
|
|
|
23,620
|
|
|
10%
|
|
|
|
|
|
|
Production volumes by area (Bcfe):
|
|
|
|
|
|
Northeast Appalachia
|
473
|
|
|
459
|
|
|
3%
|
Southwest Appalachia
|
407
|
|
|
319
|
|
|
28%
|
Other
|
—
|
|
|
—
|
|
|
—%
|
Total (1)
|
880
|
|
|
778
|
|
|
13%
|
|
|
|
|
|
|
Production percentage:
|
|
|
|
|
|
Natural gas
|
79
|
%
|
|
78
|
%
|
|
|
Oil
|
4
|
%
|
|
4
|
%
|
|
|
NGL
|
17
|
%
|
|
18
|
%
|
|
|
(1)Approximately 878 Bcfe and 776 Bcfe for the years ended December 31, 2020 and 2019, respectively, were produced from the Marcellus Shale formation.
•Production volumes for our E&P segment increased 102 Bcfe for the year ended December 31, 2020, compared to the same period in 2019, primarily due to a 28% increase in production volumes in Southwest Appalachia.
•Oil and NGL production increased 9% and 10%, respectively, for the year ended December 31, 2020, compared to 2019.
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 can neither control nor predict, including increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events such as the response to the COVID-19 pandemic, 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 activity in order to maintain appropriate liquidity and financial flexibility.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
|
2020
|
|
2019
|
|
Increase/
(Decrease)
|
Natural Gas Price:
|
|
|
|
|
|
|
NYMEX Henry Hub Price ($/MMBtu) (1)
|
|
$
|
2.08
|
|
|
$
|
2.63
|
|
|
(21)%
|
Discount to NYMEX (2)
|
|
(0.74)
|
|
|
(0.65)
|
|
|
14%
|
Average realized gas price, excluding derivatives ($/Mcf)
|
|
$
|
1.34
|
|
|
$
|
1.98
|
|
|
(32)%
|
Gain on settled financial basis derivatives ($/Mcf)
|
|
0.11
|
|
|
—
|
|
|
|
Gain on settled commodity derivatives ($/Mcf)
|
|
0.25
|
|
|
0.20
|
|
|
|
Average realized gas price, including derivatives ($/Mcf)
|
|
$
|
1.70
|
|
|
$
|
2.18
|
|
|
(22)%
|
|
|
|
|
|
|
|
Oil Price:
|
|
|
|
|
|
|
WTI oil price ($/Bbl)
|
|
$
|
39.40
|
|
|
$
|
57.03
|
|
|
(31)%
|
Discount to WTI
|
|
(10.20)
|
|
|
(10.13)
|
|
|
1%
|
Average oil price, excluding derivatives ($/Bbl)
|
|
$
|
29.20
|
|
|
$
|
46.90
|
|
|
(38)%
|
Gain on settled derivatives ($/Bbl)
|
|
17.71
|
|
|
2.66
|
|
|
|
Average oil price, including derivatives ($/Bbl)
|
|
$
|
46.91
|
|
|
$
|
49.56
|
|
|
(5)%
|
|
|
|
|
|
|
|
NGL Price:
|
|
|
|
|
|
|
Average realized NGL price, excluding derivatives ($/Bbl)
|
|
$
|
10.24
|
|
|
$
|
11.59
|
|
|
(12)%
|
Gain on settled derivatives ($/Bbl)
|
|
0.91
|
|
|
2.05
|
|
|
|
Average realized NGL price, including derivatives ($/Bbl)
|
|
$
|
11.15
|
|
|
$
|
13.64
|
|
|
(18)%
|
Percentage of WTI, excluding derivatives
|
|
26
|
%
|
|
20
|
%
|
|
|
|
|
|
|
|
|
|
Total Weighted Average Realized Price:
|
|
|
|
|
|
|
Excluding derivatives ($/Mcfe)
|
|
$
|
1.53
|
|
|
$
|
2.18
|
|
|
(30)%
|
Including derivatives ($/Mcfe)
|
|
$
|
1.94
|
|
|
$
|
2.42
|
|
|
(20)%
|
(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 derivatives 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, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bcf)
|
|
Basis Differential
|
Basis Swaps – Natural Gas
|
|
|
|
2021
|
219
|
|
|
$
|
(0.21)
|
|
2022
|
139
|
|
|
(0.33)
|
|
2023
|
47
|
|
|
(0.45)
|
|
2024
|
11
|
|
|
(0.60)
|
|
2025
|
4
|
|
|
(0.59)
|
|
Total
|
420
|
|
|
|
|
|
|
|
Physical NYMEX Sales Arrangements – Natural Gas
|
|
|
|
2021
|
217
|
|
|
$
|
(0.24)
|
|
2022
|
65
|
|
|
(0.35)
|
|
2023
|
40
|
|
|
(0.37)
|
|
2024
|
18
|
|
|
(0.47)
|
|
2025
|
12
|
|
|
(0.50)
|
|
Total
|
352
|
|
|
|
In addition to protecting basis, the table below presents the amount of our future production in which price is financially protected as of December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
2022
|
|
2023
|
Natural gas (Bcf)
|
751
|
|
|
378
|
|
|
87
|
|
Oil (MBbls)
|
6,631
|
|
|
2,155
|
|
|
878
|
|
Ethane (MBbls)
|
6,473
|
|
|
1,710
|
|
|
—
|
|
Propane (MBbls)
|
6,974
|
|
|
2,120
|
|
|
—
|
|
Normal butane (MBbls)
|
2,004
|
|
|
667
|
|
|
—
|
|
Natural gasoline (MBbls)
|
1,936
|
|
|
643
|
|
|
—
|
|
Total financial protection on future production (Bcfe)
|
895
|
|
|
422
|
|
|
92
|
|
We refer you to Note 6 of 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)
|
2020
|
|
2019
|
|
Increase/(Decrease)
|
Lease operating expenses
|
$
|
815
|
|
|
$
|
722
|
|
|
13%
|
General & administrative expenses
|
108
|
|
(1)
|
150
|
|
(2)
|
(28)%
|
Montage merger-related expenses
|
41
|
|
|
—
|
|
|
100%
|
Restructuring charges
|
16
|
|
|
11
|
|
|
45%
|
Taxes, other than income taxes
|
54
|
|
|
62
|
|
|
(13)%
|
Full cost pool amortization
|
333
|
|
|
439
|
|
|
(24)%
|
Non-full cost pool DD&A
|
15
|
|
|
23
|
|
|
(35)%
|
Impairments
|
2,830
|
|
|
13
|
|
|
(62)%
|
|
|
|
|
|
|
Total operating costs
|
$
|
4,212
|
|
|
$
|
1,420
|
|
|
197%
|
(1)Includes $1 million of legal settlement charges for the year ended December 31, 2020.
(2)Includes a $6 million residual value guarantee shortfall payment to the previous lessor of our headquarters building and $6 million of legal settlement charges for the year ended December 31, 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
Average unit costs per Mcfe:
|
2020
|
|
2019
|
|
Increase/(Decrease)
|
Lease operating expenses (1)
|
$
|
0.93
|
|
|
$
|
0.92
|
|
|
1%
|
General & administrative expenses
|
$
|
0.12
|
|
(2)
|
$
|
0.18
|
|
(3)
|
(33)%
|
Taxes, other than income taxes
|
$
|
0.06
|
|
|
$
|
0.08
|
|
|
(25)%
|
Full cost pool amortization
|
$
|
0.38
|
|
|
$
|
0.56
|
|
|
(32)%
|
(1)Includes post-production costs such as gathering, processing, fractionation and compression.
(2)Excludes $41 million in Montage merger-related expenses $16 million in restructuring charges and $1 million in legal settlement charges for the year ended December 31, 2020.
(3)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.
Lease Operating Expenses
•Lease operating expenses per Mcfe increased $0.01 for the year ended December 31, 2020, compared to 2019, as an increase in liquids production, which includes processing fees, was only partially offset by a decrease related to temporarily reduced gathering and transportation rates in Southwest Appalachia that became effective late in the second quarter of 2020.
General and Administrative Expenses
•General and administrative expenses in 2020 included $1 million in legal settlement charges. 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. Excluding these amounts, general and administrative expenses decreased $31 million for the year ended December 31, 2020, compared to 2019, primarily due to decreased personnel costs and the implementation of cost reduction initiatives.
•On a per Mcfe basis, excluding restructuring, Montage merger-related expenses, legal settlement charges and the residual value guarantee short-fall payment, general and administrative expenses per Mcfe decreased by $0.06 for the year ended December 31, 2020, compared to 2019, due to a 28% decrease in expenses and a 13% increase in production volumes.
Montage Merger-Related Expenses
•Montage merger-related expenses for the year ended December 31, 2020 included $18 million in bank, legal and consulting fees; $17 million in employee severance and related costs; and $5 million related to the settlement of contracts inherited from Montage that had no future value to our ongoing business. We refer you to Note 3 of the consolidated financial statements included in this Annual Report for additional details about the Merger.
Restructuring Charges
•In February 2020, employees were notified of a workforce reduction plan as a result of a strategic realignment of our 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 unvested long-term incentive awards that were forfeited. We also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring. For the year ended December 31, 2020, we recognized a total restructuring expense of $16 million primarily related to cash severance, including payroll taxes.
•As of December 31, 2020, a $3 million liability for restructuring charges to be paid in 2021 has been recorded.
See Note 2 of the consolidated financial statements included in this Annual Report for additional details about our restructuring charges.
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 $0.02 per Mcfe for the year ended December 31, 2020, compared to the same period in 2019, primarily due to lower commodity pricing and lower effective tax rates in Southwest Appalachia.
Full Cost Pool Amortization
•Our full cost pool amortization rate decreased $0.18 per Mcfe for the year ended December 31, 2020, as compared to 2019. The average amortization rate decreased primarily as a result of the impact of $2,825 million in non-cash full cost ceiling test impairments recorded in 2020.
•No impairment expense was recorded for the year ended December 31, 2020 in relation to our recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, we determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021 as long as we can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, we are required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had we not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020.
•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 $1,472 million at December 31, 2020 compared to $1,506 million at December 31, 2019. The unevaluated costs excluded from amortization decreased, as compared to 2019, as the evaluation of previously unevaluated properties totaling $262 million in 2020 was only partially offset by the impact of $228 million of unevaluated capital invested, which included $90 million for Montage properties acquired during the same period.
Impairments
•We recognized $2,825 million in non-cash full cost ceiling test impairments for the year ended December 31, 2020 primarily due to decreased commodity pricing over the prior 12 months. Additionally, we recognized a $5 million impairment to non-core assets.
•During the year ended December 31, 2019, we recognized non-cash impairments of $13 million associated with non-core E&P assets.
Marketing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions except percentages)
|
2020
|
|
2019
|
|
Increase/(Decrease)
|
Marketing revenues
|
$
|
2,145
|
|
|
$
|
2,849
|
|
|
(25)%
|
|
|
|
|
|
|
Other operating revenues
|
—
|
|
|
1
|
|
|
(100)%
|
Marketing purchases
|
2,129
|
|
|
2,833
|
|
|
(25)%
|
Operating costs and expenses
|
23
|
|
|
25
|
|
|
(8)%
|
Impairments
|
—
|
|
|
3
|
|
|
(100)%
|
Loss on sale of assets, net
|
—
|
|
|
2
|
|
|
(100)%
|
Operating income (loss)
|
$
|
(7)
|
|
|
$
|
(13)
|
|
|
(46)%
|
|
|
|
|
|
|
Volumes marketed (Bcfe)
|
1,138
|
|
|
1,101
|
|
|
3%
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent natural gas production marketed from affiliated E&P operations
|
89
|
%
|
|
79
|
%
|
|
|
Affiliated E&P oil and NGL production marketed
|
81
|
%
|
|
61
|
%
|
|
|
Operating Loss
•Marketing operating loss decreased $6 million for the year ended December 31, 2020, compared to 2019, as 2019 included a $3 million impairment of non-core gathering assets, a $2 million loss on the sale of operating assets and $1 million in gas storage gains recorded in other operating revenues. Additionally, marketing operating loss for 2020 included a $2 million decrease in operating costs and expenses. For the year ended December 31, 2020, the marketing margin remained flat, compared to the prior year.
•The margin generated from marketing activities was $16 million for both years ended December 31, 2020 and 2019, 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 revenues due to changes in commodity prices and volumes marketed are largely offset by corresponding changes in purchase expenses. Efforts to optimize the cost of our transportation can result in greater expenses and therefore lower marketing margins.
Revenues
•Revenues from our marketing activities decreased $704 million for the year ended December 31, 2020, compared to 2019, as a 27% decrease in the price received for volumes marketed more than offset a 37 Bcfe increase in the volumes marketed.
Operating Costs and Expenses
•Marketing operating costs and expenses decreased $2 million for the year ended December 31, 2020, compared to the year ended December 31, 2019, primarily due to decreased general and administrative expenses associated with decreased personnel costs and the implementation of cost reduction initiatives.
Consolidated
Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions except percentages)
|
|
2020
|
|
2019
|
|
Increase/
(Decrease)
|
Gross interest expense:
|
|
|
|
|
|
|
Senior notes
|
|
$
|
155
|
|
|
$
|
155
|
|
|
—%
|
Credit arrangements
|
|
16
|
|
|
11
|
|
|
45%
|
Amortization of debt costs
|
|
11
|
|
|
8
|
|
|
38%
|
Total gross interest expense
|
|
182
|
|
|
174
|
|
|
5%
|
Less: capitalization
|
|
(88)
|
|
|
(109)
|
|
|
(19)%
|
Net interest expense
|
|
$
|
94
|
|
|
$
|
65
|
|
|
45%
|
•Interest expense related to our senior notes remained flat for the year ended December 31, 2020, as compared to 2019, as the interest savings from the repurchase of $107 million and $114 million of our outstanding senior notes in the first half of 2020 and the second half of 2019, respectively, was offset by the interest associated with the August 2020 public offering of $350 million aggregate principal amount of our 8.375% Senior Notes due 2028.
•Capitalized interest decreased $21 million for the year ended December 31, 2020, compared to 2019, due to the evaluation of natural gas and oil properties over the past twelve months.
•Capitalized interest decreased as a percentage of gross interest expense for the year ended December 31, 2020 as compared to 2019 primarily due to a larger percentage decrease in our unevaluated natural gas and oil properties balance as compared to the smaller percentage decrease in our gross interest expense over the same period.
Gain (Loss) on Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
(in millions)
|
2020
|
|
2019
|
|
Gain (loss) on unsettled derivatives
|
$
|
(138)
|
|
|
$
|
94
|
|
|
Gain on settled derivatives
|
362
|
|
|
180
|
|
|
Total gain on derivatives
|
$
|
224
|
|
|
$
|
274
|
|
|
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 2020, we recorded a gain on early extinguishment of debt of $35 million as a result of our repurchase of $107 million in aggregate principal amount of our outstanding senior notes for $72 million.
•In 2019, we recorded a gain of $8 million on early extinguishment of debt as a result of our repurchase 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.
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions except percentages)
|
2020
|
|
2019
|
Income tax expense (benefit)
|
$
|
407
|
|
|
$
|
(411)
|
|
Effective tax rate
|
(15)
|
%
|
|
(86)
|
%
|
•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 asset would be realized and released substantially all of the valuation allowance. This resulted in a discrete tax benefit of $411 million being recorded for the year ended December 31, 2019. However, due to commodity price declines during 2020 and the write-down of the current value of our natural gas and oil properties, in addition to other negative evidence, we concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in our valuation allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. We also continue to retain a valuation allowance of $87 million related to net operating losses in jurisdictions in which we no longer operate.
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 2018 credit facility, our cash and cash equivalents balance and capital markets as our primary sources of liquidity. In October 2020, the banks participating in our 2018 credit facility reaffirmed our elected borrowing base and aggregate commitments to be $1.8 billion. Upon the closing of the Merger in November 2020 and satisfaction of related conditions, the elected borrowing base and total aggregate commitments increased from $1.8 billion to $2.0 billion, the maximum permitted lien amount based on provisions in certain of our senior notes indentures. As of February 25, 2021, we had approximately $1.3 billion of total available liquidity, which exceeds our currently modeled needs, and looking forward in 2021, we remain committed to our strategy of free cash flow generation through capital discipline. 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 2018 credit facility and related covenant requirements.
Our cash flow from operating activities is highly dependent upon our ability to sell and the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See "Market Conditions and Commodity Prices" in the Overview section of Item 7 in Part II for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity derivative program. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. In 2020, $362 million in realized gains on derivatives have offset a large portion of the impact of lower commodity prices, and although we are continually adding additional derivative positions for portions of our expected 2021, 2022 and 2023 production, 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 in 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 owners could adversely impact our cash flows.
Due to these 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 credit facility entered into in 2016 with a new revolving credit facility (the "2018 credit facility") with a group of banks that, as amended, has a maturity date of April 2024. The 2018 credit facility has an aggregate maximum revolving credit amount of $3.5 billion and, in October 2020, the banks participating in our 2018 credit facility reaffirmed the borrowing base to be $1.8 billion, which also reflected our aggregate commitments. Upon the closing of the Merger in November 2020, the borrowing base and total aggregate commitments were increased from $1.8 billion to $2.0 billion. The borrowing base is subject to redetermination at least twice a year, in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. On October 8, 2020, we entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters, limit our unrestricted cash and cash equivalents to $200 million when loans under the 2018 credit facility are outstanding, subject to certain exceptions, and to increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility. The 2018 credit facility is secured by substantially all of our assets, including most of our subsidiaries. The permitted lien provisions in certain senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of
adjusted consolidated net tangible assets. We may utilize the 2018 credit facility in the form of loans and letters of credit. As of December 31, 2020, we had $700 million borrowings on our revolving credit facility and $233 million in outstanding letters of credit. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our revolving credit facility.
As of December 31, 2020, we were in compliance with all of the covenants contained in the credit agreement governing our revolving credit facility. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and 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.
Our exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and Southwestern. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (or “SOFR”).
In contemplation of the Merger with Montage, in August 2020, we completed a public offering of $350 million aggregate principal amount of our 2028 Notes, with net proceeds from the offering totaling approximately $345 million after underwriting discounts and offering expenses.
In August 2020, we completed a public offering of 63,250,000 shares of our common stock with an offering price to the public of $2.50 per share. Net proceeds, after deducting underwriting discounts and offering expenses, were approximately $152 million. The proceeds from the common stock offering, in conjunction with the issuance of the 2028 Notes and additional borrowings on our revolving credit facility were used to fund a redemption of $510 million aggregate principal amount of Montage Notes in connection with the closing of the Merger.
In 2020, we repurchased $6 million of our 4.10% Senior Notes due 2022, $36 million of our 4.95% Senior Notes due 2025, $21 million of our 7.50% Senior Notes due 2026 and $44 million of our 7.75% Senior Notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.
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. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our senior notes.
Because of the focused work on refinancing and repayment of our debt during the last three years, only $207 million, or 7%, of our outstanding debt balance as of December 31, 2020 is scheduled to become due prior to 2024.
At February 25, 2021, we had a long-term issuer credit rating of Ba2 by Moody’s (rating and stable outlook affirmed on April 2, 2020), a long-term debt rating of BB- by S&P (rating affirmed and outlook upgraded to stable on October 15, 2020) and a long-term issuer default rating of BB by Fitch Ratings (rating affirmed and outlook upgraded to stable on January 29, 2021). In April 2020, S&P downgraded our bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% in July 2020. The first coupon payment to the bondholders at the higher interest rate was January 2021. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively.
Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
Net cash provided by operating activities
|
$
|
528
|
|
|
$
|
964
|
|
Net cash used in investing activities
|
(881)
|
|
|
(1,045)
|
|
Net cash provided by (used in) financing activities
|
361
|
|
|
(115)
|
|
Cash Flow from Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
Net cash provided by operating activities
|
$
|
528
|
|
|
$
|
964
|
|
Add back (subtract): changes in working capital
|
77
|
|
|
(69)
|
|
Net cash provided by operating activities, net of changes in working capital
|
$
|
605
|
|
|
$
|
895
|
|
•Net cash provided by operating activities decreased 45% or $436 million for the year ended December 31, 2020, compared to the same period in 2019, primarily due to a $574 million decrease resulting from lower commodity prices, a $146 million decreased impact of working capital, an $85 million increase in operating costs and a $29 million increase in interest expense. The decreases were partially offset by a $216 million increase associated with increased production and a $182 million increase in our settled derivatives.
•Net cash generated from operating activities, net of changes in working capital, provided 67% of our cash requirements for capital investments for the year ended December 31, 2020, compared to providing 79% of our cash requirements for capital investments for the same period in 2019.
Cash Flow from Investing Activities
•Total E&P capital investing decreased $239 million for the year ended December 31, 2020, compared to the same period in 2019, due to a $197 million decrease in direct E&P capital investing, a $21 million decrease in capitalized internal costs and a $21 million decrease in capitalized interest.
•The decrease in capitalized interest for the year ended December 31, 2020, as compared to the same period in 2019, was primarily due to the evaluation of natural gas and oil properties over the past twelve months.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
Additions to properties and equipment
|
$
|
896
|
|
|
$
|
1,099
|
|
Adjustments for capital investments:
|
|
|
|
Changes in capital accruals
|
(3)
|
|
|
35
|
|
Other (1)
|
6
|
|
|
6
|
|
Total capital investing
|
$
|
899
|
|
|
$
|
1,140
|
|
(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)
|
2020
|
|
2019
|
|
Increase/
(Decrease)
|
E&P capital investing
|
$
|
899
|
|
|
$
|
1,138
|
|
|
|
|
|
|
|
|
|
Other capital investing (1)
|
—
|
|
|
2
|
|
|
|
Total capital investing
|
$
|
899
|
|
|
$
|
1,140
|
|
|
(21)%
|
(1)Other capital investing was immaterial for the year ended December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
E&P Capital Investments by Type:
|
|
|
|
Exploratory and development, including workovers
|
$
|
692
|
|
|
$
|
838
|
|
Acquisition of properties
|
37
|
|
|
55
|
|
Seismic expenditures
|
—
|
|
|
3
|
|
Water infrastructure project
|
9
|
|
|
35
|
|
Other
|
17
|
|
|
21
|
|
Capitalized interest and expenses
|
144
|
|
|
186
|
|
Total E&P capital investments
|
$
|
899
|
|
|
$
|
1,138
|
|
|
|
|
|
E&P Capital Investments by Area
|
|
|
|
Northeast Appalachia
|
$
|
362
|
|
|
$
|
365
|
|
Southwest Appalachia
|
510
|
|
|
710
|
|
|
|
|
|
Other E&P (1)
|
27
|
|
|
63
|
|
Total E&P capital investments
|
$
|
899
|
|
|
$
|
1,138
|
|
(1)Includes $9 million and $35 million for the years ended December 31, 2020 and 2019, respectively, related to our water infrastructure project.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
2020
|
|
2019
|
Gross Operated Well Count Summary:
|
|
|
|
Drilled
|
98
|
|
|
105
|
|
Completed
|
96
|
|
|
116
|
|
Wells to sales
|
100
|
|
|
113
|
|
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
•Net cash provided by financing activities for the year ended December 31, 2020 was $361 million, compared to net cash used in financing activities of $115 million for the same period in 2019.
•In August 2020, we completed debt and equity offerings resulting in $345 million and $152 million in net proceeds, respectively.
•In November 2020, we paid $522 million to retire the Montage senior notes, and repaid the outstanding balance of $200 million related to Montage’s revolving credit facility.
•In 2020, we repurchased $107 million in aggregate principal amount of our outstanding senior notes at a discount for $72 million and recognized a $35 million gain on the extinguishment of debt.
•In 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 2019, we repurchased approximately 5 million shares of common stock for approximately $21 million.
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 and to Note 1 for additional discussion of our equity offering.
Working Capital
•We had negative working capital of $341 million at December 31, 2020, a $172 million decrease from December 31, 2019, as an $8 million increase in cash and cash equivalents was more than offset by a $70 million increase in various payables and a $157 million net reduction in the current mark-to-market value of our derivative position related to improved forward strip pricing across all commodities as compared to December 2019. Additionally, other current liabilities at December 31, 2020 decreased $34 million, compared to December 31, 2019, as a $43 million decrease in our accrued firm transportation liability related to the Fayetteville Shale sale was only partially offset by a prepayment that we received for an unrelated firm transportation assumption. We believe that our existing cash and cash equivalents, our anticipated cash flow from operations and our available credit facility will be sufficient to meet our working capital and operational spending requirements.
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, 2020, our material off-balance sheet arrangements and transactions include operating service arrangements, $233 million in letters of credit outstanding against our 2018 revolving credit facility and $221 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, 2020, 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)
|
$
|
8,544
|
|
|
$
|
862
|
|
|
$
|
1,562
|
|
|
$
|
1,323
|
|
|
$
|
1,901
|
|
|
$
|
2,896
|
|
Debt
|
3,171
|
|
|
—
|
|
|
207
|
|
|
1,556
|
|
|
1,408
|
|
|
—
|
|
Interest on debt (2)
|
1,070
|
|
|
199
|
|
|
382
|
|
|
310
|
|
|
179
|
|
|
—
|
|
Operating leases (3)
|
131
|
|
|
30
|
|
|
39
|
|
|
26
|
|
|
30
|
|
|
6
|
|
Compression services (4)
|
37
|
|
|
20
|
|
|
14
|
|
|
3
|
|
|
—
|
|
|
—
|
|
Operating agreements
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchase obligations
|
45
|
|
|
45
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other obligations (5)
|
12
|
|
|
9
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
13,014
|
|
|
$
|
1,169
|
|
|
$
|
2,207
|
|
|
$
|
3,218
|
|
|
$
|
3,518
|
|
|
$
|
2,902
|
|
(1)As of December 31, 2020, 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, $531 million related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and/or 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 $923 million.
With the close of the Montage Merger we acquired firm transportation commitments of approximately $1,100 million. These commitments approximate $99 million within the next year, $197 million from 1 to 3 years, $196 million from 3 to 5 years, $284 million from 5 to 8 years and $324 million beyond 8 years.
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.
(2)Interest payments on our senior notes were calculated utilizing the fixed rates associated with our fixed rate notes outstanding at December 31, 2020. Senior note interest rates were based on our credit ratings as of December 31, 2020.
(3)Operating leases include costs for compressors, drilling rigs, pressure pumping equipment, office space and other equipment under non-cancelable operating leases expiring through 2036.
(4)As of December 31, 2020, 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.
Supplemental Guarantor Financial Information
As discussed in Note 9, in April 2018 the Company entered into the 2018 credit facility. Pursuant to requirements under the indentures governing our senior notes, each 100% owned subsidiary that became a guarantor of the 2018 credit facility also became a guarantor of each of our senior notes (the “Guarantor Subsidiaries”). The Guarantor Subsidiaries also granted liens and security interests to support their guarantees under the 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 our operating units which are accounted for on a consolidated basis do not guarantee the 2018 credit facility and senior notes.
Upon the November 2020 closing of the Merger with Montage, certain Montage entities owning oil and gas properties became guarantors to the 2018 credit facility.
The Company and the Guarantor Subsidiaries jointly and severally, and fully and unconditionally, guarantee the payment of the principal and premium, if any, and interest on the senior notes when due, whether at stated maturity of the senior notes, by acceleration, by call for redemption or otherwise, together with interest on the overdue principal, if any, and interest on any overdue interest, to the extent lawful, and all other obligations of the Company to the holders of the senior notes.
SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company. The Parent and Guarantor Subsidiaries comprise the material operations of the Company. Therefore, the Company concluded that the presentation of the Summarized Financial Information is not required as the Summarized Financial Information of the Company’s Guarantors is not materially different from our consolidated financial statements.
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 quarterly 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 designated for hedge accounting, 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, 2020, we had approximately $1,472 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, 2020, 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 $1.98 per MMBtu, for West Texas Intermediate oil of $39.57 per barrel and NGLs of $10.27 per barrel, adjusted for market differentials. The net book value of our natural gas and oil properties exceeded the ceiling amount in each quarter of 2020 resulting in total non-cash full cost ceiling test write-downs of $2,825 million. We had no derivative positions that were designated for hedge accounting as of December 31, 2020. Future decreases in market prices, as well as changes in production rates, levels of reserves, evaluation costs excluded from amortization, future development costs and production costs may result in further non-cash impairments to our natural gas and oil properties.
No impairment expense was recorded for the year ended December 31, 2020 in relation to our recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, we determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021 as long as we can continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, we are required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and we affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had we not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020.
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 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, 2019. We had no derivative positions that were designated for hedge accounting as of December 31, 2019.
Changes 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. Our reserve base as of December 31, 2020 was approximately 76% natural gas, 3% NGLs and 21% oil, and our standardized measure and reserve quantities as of December 31, 2020, were $1.85 billion and 12.0 Tcfe, respectively.
Proved natural gas, oil and NGL reserves are a major component of the full cost ceiling test. 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 26 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 32 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 23 years and over 19 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 12 years and over 19 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 68% of our total reserve base as of December 31, 2020. 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 future 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 97% 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, 2020, 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 9, 2021, NSAI issued its audit opinion as to the reasonableness of our reserve estimates for the year-ended December 31, 2020 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.
Business Combinations
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. Fair value of proved natural gas and oil properties as of the acquisition date was based on estimated proved natural gas, oil and NGL reserves and related discounted net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future
commodity prices and a weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of natural gas and oil properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities.
The Merger with Montage qualified as a business combination, and as such, we estimated the fair value of the assets acquired and liabilities assumed as of the November 13, 2020 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. We used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of natural gas and oil reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 8 – Fair Value Measurements. We recorded the net assets acquired and liabilities assumed in the Montage Merger at their estimated fair value of approximately $213 million, which we consider to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.
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 2020 and 2019, we financially protected 83% and 69%, respectively, 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 are 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, 2020, 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, 2020.
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, 2020 benefit obligation the initial discount rate assumed is 3.10%. This compares to an initial discount rate of 3.70% for the benefit obligation and periodic benefit cost recorded in 2020. As part of ongoing effort to reduce costs, we have elected to freeze our pension plan effective January 1, 2021. Employees that were participants in the
pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive the service component. For the 2021 periodic benefit cost, the expected return assumed was reduced from 6.50% to 5.10%.
Using the assumed rates discussed above, we recorded total benefit cost of $9 million in 2020 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 2020 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, 2020, we recognized a liability of $46 million, compared to $43 million at December 31, 2019, related to our pension and other postretirement benefit plans. During 2020, we made cash contributions totaling $13 million to fund our pension and other postretirement benefit plans.
Long-term Incentive Compensation
Our long-term incentive compensation plans consist of a combination of stock-based awards that derive their value directly or indirectly from our common stock price, and cash-based awards that are fixed in amount, but subject to meeting annual performance thresholds. In March 2020, we issued our first long-term fixed cash-based awards.
We account for long-term incentive compensation transactions using a fair value method and recognize an amount equal to the fair value of the stock-based awards and cash-based awards 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. The performance cash awards granted in 2020 include a performance condition determined annually by the Company. If we, in our sole discretion, determine that the threshold was not met, the amount for that vesting period will not vest and will be cancelled.
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. See Note 14 to the consolidated financial statements included in this Annual Report for further discussion and disclosures regarding our long-term incentive compensation.
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 Securities 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 are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.
Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this 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,” “model,” “target” or similar words. Statements may be forward-looking even in the absence of these particular words.
You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. 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) and the impact of reduced demand for our production and products in which our production is a component due to governmental and societal actions taken in response to the COVID-19 or other pandemic;
•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 impact of COVID-19 or other diseases;
•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, including the Merger;
•costs in connection with the Merger;
•integration of operations and results subsequent to the Merger;
•our ability to transport our production to the most favorable markets or at all;
•availability and costs of personnel and of products and services provided by third parties;
•the impact of government regulation, including changes in law, the ability to obtain and maintain permits, any increase in severance or similar taxes, and legislation or regulation relating to hydraulic fracturing or other drilling and completing techniques, 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 or power outages;
•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 update publicly 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, 2020, 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, 2020.
Management’s assessment and conclusion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2020 excludes an assessment of the internal control over financial reporting of Montage Resources, which was acquired in a business combination on November 13, 2020. Montage represents approximately 22% of our consolidated total assets at December 31, 2020 and 3% of our consolidated revenues for the fiscal year ended December 31, 2020.
The effectiveness of our internal control over financial reporting as of December 31, 2020 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, 2020 and 2019, 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, 2020, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 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, 2020, 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.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Montage Resources, Inc. (“Montage”) from its assessment of internal control over financial reporting as of December 31, 2020 because it was acquired by the Company in a purchase business combination during 2020. We have also excluded Montage from our audit of internal control over financial reporting. Montage is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent 22% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2020.
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 matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Proved Natural Gas, Oil and NGL Reserves on Natural Gas and Oil Properties, Net
As described in Note 1 to the consolidated financial statements, the Company’s consolidated natural gas and oil properties balance was $27,261 million as of December 31, 2020, and depreciation, depletion, and amortization (DD&A) expense for the year ended December 31, 2020 was $357 million. The Company utilizes the full cost method of accounting for its natural gas and oil 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 quarterly 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%. For the year ended December 31, 2020, pre-tax impairment charges of $2,825 million were recognized. As disclosed by management, proved natural gas, oil and NGL reserves are a major component of the full cost ceiling test. Estimates of 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 future 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, and audited by independent petroleum engineers (together referred to as “management’s specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved natural gas, oil and NGL reserves on natural gas and oil properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved natural gas, oil and NGL reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management’s specialists in developing the estimates of proved natural gas, oil and NGL reserves and the assumption applied to the full cost ceiling test calculations related to 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 and the calculations of the full cost ceiling impairment test.
These procedures also included, among others, testing the full cost ceiling impairment test calculation. 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 and the reasonableness of future production volumes applied in the full cost ceiling test. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by management’s specialists, tests of the data used by management’s specialists, and an evaluation of management’s specialists’ findings.
Acquisition of Montage Resources – Valuation of Proved Natural Gas and Oil Properties
As described in Note 3 to the consolidated financial statements, $1,102 million of the purchase price from the November 2020 business combination of Montage Resources, Inc. was allocated to natural gas and oil properties, net, including $1,012 million related to proved properties. As disclosed by management, the Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Fair value of proved natural gas and oil properties as of the acquisition date was based on estimated proved natural gas, oil, and NGL reserves and related discounted net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices and a weighted average cost of capital rate. Estimates of reserves require extensive judgments of reservoir engineering data and projections of costs 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 future 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, and audited by independent petroleum engineers (together referred to as “management’s specialists”).
The principal considerations for our determination that performing procedures relating to the acquisition of Montage Resources – valuation of proved natural gas and oil properties is a critical audit matter are the (i) significant judgment by management, including the use of management’s specialists, when developing the fair value measurement of proved natural gas and oil properties; (ii) a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes and commodity prices, as well as the weighted average cost of capital; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
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 the valuation of the acquired proved natural gas and oil properties. These procedures also included, among others (i) testing management’s process for developing the fair value measurement of proved natural gas and oil properties; (ii) evaluating the appropriateness of the discounted cash flow model; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions used by management related to future production volumes and commodity prices, as well as the weighted average cost of capital. Evaluating the reasonableness of management’s assumption related to future commodity prices involved comparing the prices against observable market data and evaluating differentials through inspection of the underlying contracts. Professionals with specialized skill and knowledge were used to assist in the evaluation of reasonableness of the weighted average cost of capital assumption and the appropriateness of the discounted cash flow model. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved natural gas, oil and NGL reserve volumes as stated in the Critical Audit Matter titled “The Impact of Proved Natural Gas, Oil and NGL Reserves on Natural Gas and Oil Properties, Net” and the reasonableness of the future production volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2021
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)
|
2020
|
|
2019
|
|
2018
|
Operating Revenues:
|
|
|
|
|
|
Gas sales
|
$
|
967
|
|
|
$
|
1,241
|
|
|
$
|
1,998
|
|
Oil sales
|
154
|
|
|
223
|
|
|
196
|
|
NGL sales
|
265
|
|
|
274
|
|
|
352
|
|
Marketing
|
917
|
|
|
1,297
|
|
|
1,222
|
|
Gas gathering
|
—
|
|
|
—
|
|
|
89
|
|
Other
|
5
|
|
|
3
|
|
|
5
|
|
|
2,308
|
|
|
3,038
|
|
|
3,862
|
|
Operating Costs and Expenses:
|
|
|
|
|
|
Marketing purchases
|
946
|
|
|
1,320
|
|
|
1,229
|
|
Operating expenses
|
813
|
|
|
720
|
|
|
785
|
|
General and administrative expenses
|
121
|
|
|
166
|
|
|
209
|
|
Montage merger-related expenses
|
41
|
|
|
—
|
|
|
—
|
|
Restructuring charges
|
16
|
|
|
11
|
|
|
39
|
|
(Gain) loss on sale of operating assets
|
—
|
|
|
2
|
|
|
(17)
|
|
Depreciation, depletion and amortization
|
357
|
|
|
471
|
|
|
560
|
|
Impairments
|
2,830
|
|
|
16
|
|
|
171
|
|
Taxes, other than income taxes
|
55
|
|
|
62
|
|
|
89
|
|
|
5,179
|
|
|
2,768
|
|
|
3,065
|
|
Operating Income (Loss)
|
(2,871)
|
|
|
270
|
|
|
797
|
|
Interest Expense:
|
|
|
|
|
|
Interest on debt
|
171
|
|
|
166
|
|
|
231
|
|
Other interest charges
|
11
|
|
|
8
|
|
|
8
|
|
Interest capitalized
|
(88)
|
|
|
(109)
|
|
|
(115)
|
|
|
94
|
|
|
65
|
|
|
124
|
|
|
|
|
|
|
|
Gain (Loss) on Derivatives
|
224
|
|
|
274
|
|
|
(118)
|
|
Gain (Loss) on Early Extinguishment of Debt
|
35
|
|
|
8
|
|
|
(17)
|
|
Other Income (Loss), Net
|
1
|
|
|
(7)
|
|
|
—
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
(2,705)
|
|
|
480
|
|
|
538
|
|
Provision (Benefit) for Income Taxes
|
|
|
|
|
|
Current
|
(2)
|
|
|
(2)
|
|
|
1
|
|
Deferred
|
409
|
|
|
(409)
|
|
|
—
|
|
|
407
|
|
|
(411)
|
|
|
1
|
|
Net Income (Loss)
|
$
|
(3,112)
|
|
|
$
|
891
|
|
|
$
|
537
|
|
|
|
|
|
|
|
Participating securities – mandatory convertible preferred stock
|
—
|
|
|
—
|
|
|
2
|
|
Net Income (Loss) Attributable to Common Stock
|
$
|
(3,112)
|
|
|
$
|
891
|
|
|
$
|
535
|
|
|
|
|
|
|
|
Earnings (Loss) Per Common Share
|
|
|
|
|
|
Basic
|
$
|
(5.42)
|
|
|
$
|
1.65
|
|
|
$
|
0.93
|
|
Diluted
|
$
|
(5.42)
|
|
|
$
|
1.65
|
|
|
$
|
0.93
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding:
|
|
|
|
|
|
Basic
|
573,889,502
|
|
|
539,345,343
|
|
|
574,631,756
|
|
Diluted
|
573,889,502
|
|
|
540,382,914
|
|
|
576,642,808
|
|
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)
|
2020
|
|
2019
|
|
2018 (1)
|
Net income (loss)
|
$
|
(3,112)
|
|
|
$
|
891
|
|
|
$
|
537
|
|
|
|
|
|
|
|
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)
|
3
|
|
|
8
|
|
|
10
|
|
Net actuarial loss incurred in period (3)
|
(8)
|
|
|
(5)
|
|
|
(2)
|
|
Total change in value of pension and postretirement liabilities
|
(5)
|
|
|
3
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
$
|
(3,117)
|
|
|
$
|
894
|
|
|
$
|
545
|
|
(1)In 2018, deferred tax activity incurred in other comprehensive income was offset by a valuation allowance.
(2)Net of $1 million and $2 million in taxes for the years ended December 31, 2020 and 2019, respectively.
(3)Net of ($2) million and ($1) million in taxes for the year ended December 31, 2020 and 2019, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2020
|
|
December 31,
2019
|
ASSETS
|
(in millions, except share amounts)
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$
|
13
|
|
|
$
|
5
|
|
Accounts receivable, net
|
368
|
|
|
345
|
|
Derivative assets
|
241
|
|
|
278
|
|
Other current assets
|
49
|
|
|
51
|
|
Total current assets
|
671
|
|
|
679
|
|
Natural gas and oil properties, using the full cost method, including $1,472 million as of December 31, 2020 and $1,506 million as of December 31, 2019 excluded from amortization
|
27,261
|
|
|
25,250
|
|
Other
|
523
|
|
|
520
|
|
Less: Accumulated depreciation, depletion and amortization
|
(23,673)
|
|
|
(20,503)
|
|
Total property and equipment, net
|
4,111
|
|
|
5,267
|
|
Operating lease assets
|
163
|
|
|
159
|
|
Deferred tax assets
|
—
|
|
|
407
|
|
Other long-term assets
|
215
|
|
|
205
|
|
Total long-term assets
|
378
|
|
|
771
|
|
TOTAL ASSETS
|
$
|
5,160
|
|
|
$
|
6,717
|
|
LIABILITIES AND EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
Accounts payable
|
$
|
573
|
|
|
$
|
525
|
|
Taxes payable
|
74
|
|
|
59
|
|
Interest payable
|
58
|
|
|
51
|
|
Derivative liabilities
|
245
|
|
|
125
|
|
Current operating lease liabilities
|
42
|
|
|
34
|
|
Other current liabilities
|
20
|
|
|
54
|
|
Total current liabilities
|
1,012
|
|
|
848
|
|
Long-term debt
|
3,150
|
|
|
2,242
|
|
Long-term operating lease liabilities
|
117
|
|
|
119
|
|
Long-term derivative liabilities
|
183
|
|
|
111
|
|
Pension and other postretirement liabilities
|
45
|
|
|
43
|
|
Other long-term liabilities
|
156
|
|
|
108
|
|
Total long-term liabilities
|
3,651
|
|
|
2,623
|
|
Commitments and contingencies (Note 10)
|
|
|
|
Equity:
|
|
|
|
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 718,795,700 shares as of December 31, 2020 and 585,555,923 as of December 31, 2019
|
7
|
|
|
6
|
|
Additional paid-in capital
|
5,093
|
|
|
4,726
|
|
Accumulated deficit
|
(4,363)
|
|
|
(1,251)
|
|
Accumulated other comprehensive loss
|
(38)
|
|
|
(33)
|
|
Common stock in treasury, 44,353,224 shares as of December 31, 2020 and 2019
|
(202)
|
|
|
(202)
|
|
Total equity
|
497
|
|
|
3,246
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
5,160
|
|
|
$
|
6,717
|
|
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)
|
2020
|
|
2019
|
|
2018
|
Cash Flows From Operating Activities:
|
|
|
|
|
|
Net income (loss)
|
$
|
(3,112)
|
|
|
$
|
891
|
|
|
$
|
537
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
357
|
|
|
471
|
|
|
560
|
|
Amortization of debt issuance costs
|
9
|
|
|
8
|
|
|
8
|
|
Impairments
|
2,830
|
|
|
16
|
|
|
171
|
|
Deferred income taxes
|
409
|
|
|
(409)
|
|
|
—
|
|
(Gain) loss on derivatives, unsettled
|
138
|
|
|
(94)
|
|
|
24
|
|
Stock-based compensation
|
3
|
|
|
8
|
|
|
14
|
|
(Gain) loss on early extinguishment of debt
|
(35)
|
|
|
(8)
|
|
|
17
|
|
(Gain) loss on sale of assets
|
—
|
|
|
2
|
|
|
(17)
|
|
|
|
|
|
|
|
Other
|
6
|
|
|
10
|
|
|
(1)
|
|
Change in assets and liabilities:
|
|
|
|
|
|
Accounts receivable
|
50
|
|
|
234
|
|
|
(153)
|
|
Accounts payable
|
(131)
|
|
|
(141)
|
|
|
65
|
|
Taxes payable
|
(7)
|
|
|
—
|
|
|
2
|
|
Interest payable
|
(11)
|
|
|
—
|
|
|
(10)
|
|
Inventories
|
2
|
|
|
(7)
|
|
|
(13)
|
|
Other assets and liabilities
|
20
|
|
|
(17)
|
|
|
19
|
|
Net cash provided by operating activities
|
528
|
|
|
964
|
|
|
1,223
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities:
|
|
|
|
|
|
Capital investments
|
(896)
|
|
|
(1,099)
|
|
|
(1,290)
|
|
Proceeds from sale of property and equipment
|
12
|
|
|
54
|
|
|
1,643
|
|
Cash acquired in Montage merger
|
3
|
|
|
—
|
|
|
—
|
|
Other
|
—
|
|
|
—
|
|
|
6
|
|
Net cash provided by (used in) investing activities
|
(881)
|
|
|
(1,045)
|
|
|
359
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities:
|
|
|
|
|
|
Payments on current portion of long-term debt
|
—
|
|
|
(52)
|
|
|
—
|
|
Payments on long-term debt
|
(72)
|
|
|
(54)
|
|
|
(2,095)
|
|
Payments on revolving credit facility
|
(1,671)
|
|
|
(532)
|
|
|
(1,983)
|
|
Borrowings under revolving credit facility
|
2,337
|
|
|
566
|
|
|
1,983
|
|
Change in bank drafts outstanding
|
1
|
|
|
(19)
|
|
|
17
|
|
Repayment of Montage revolving credit facility
|
(200)
|
|
|
—
|
|
|
—
|
|
Repayment of Montage senior notes
|
(522)
|
|
|
—
|
|
|
—
|
|
Proceeds from issuance of long-term debt
|
350
|
|
|
—
|
|
|
—
|
|
Debt issuance and other financing costs
|
(10)
|
|
|
(3)
|
|
|
(9)
|
|
Proceeds from issuance of common stock
|
152
|
|
|
—
|
|
|
—
|
|
Purchase of treasury stock
|
—
|
|
|
(21)
|
|
|
(180)
|
|
Preferred stock dividend
|
—
|
|
|
—
|
|
|
(27)
|
|
Cash paid for tax withholding
|
(4)
|
|
|
(1)
|
|
|
(3)
|
|
Other
|
—
|
|
|
1
|
|
|
—
|
|
Net cash provided by (used in) financing activities
|
361
|
|
|
(115)
|
|
|
(2,297)
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents
|
8
|
|
|
(196)
|
|
|
(715)
|
|
Cash and cash equivalents at beginning of year
|
5
|
|
|
201
|
|
|
916
|
|
Cash and cash equivalents at end of year
|
$
|
13
|
|
|
$
|
5
|
|
|
$
|
201
|
|
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
Preferred
Stock
|
|
Additional
Paid-In
Capital
|
|
Accumulated
Deficit
|
|
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, 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
|
|
Preferred stock dividend
|
|
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
|
|
Comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,112)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,112)
|
|
Other comprehensive loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5)
|
|
|
—
|
|
|
—
|
|
|
(5)
|
|
Total comprehensive loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,117)
|
|
Stock-based compensation
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Issuance of common stock
|
|
63,250,000
|
|
|
—
|
|
|
—
|
|
|
152
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
152
|
|
Issuance of restricted stock
|
|
311,446
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Cancellation of restricted stock
|
|
(1,274,802)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Restricted units granted
|
|
2,697,170
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Montage merger exchange
|
|
69,740,848
|
|
|
1
|
|
|
—
|
|
|
212
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax withholding – stock compensation
|
|
(1,484,885)
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
Balance at December 31, 2020
|
|
718,795,700
|
|
|
$
|
7
|
|
|
—
|
|
|
$
|
5,093
|
|
|
$
|
(4,363)
|
|
|
$
|
(38)
|
|
|
44,353,224
|
|
|
$
|
(202)
|
|
|
$
|
497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
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, Ohio 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, Ohio 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, Ohio and West Virginia as “Appalachia.” The Company also operates drilling rigs located in Appalachia, and provides oilfield products and services, principally serving the Company's E&P operations through vertical integration.
In August 2020, the Company entered into an Agreement and Plan of Merger (the "Merger Agreement") with Montage Resources Corporation ("Montage") pursuant to which Montage will merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Merger"). The Company acquired at the effective time of the merger all of the outstanding shares of common stock in Montage in exchange for 1.8656 shares of Southwestern common stock per share of Montage common stock. The transaction closed on November 13, 2020. The Merger expanded the Company's footprint in Appalachia by supplementing the Northeast Appalachia and Southwest Appalachia operations and by expanding the Company's operations into Ohio. See Note 3 for more information about the Merger.
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, 2020, 2019 and 2018 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. Customers include major energy companies, utilities and industrial purchasers of Natural gas. For the year ended December 31, 2020, one purchaser accounted for 10% of total revenues. A default on this account could have a material impact on the Company, but the Company does not believe that there is a material risk of default. No other purchasers accounted for greater than 10% of consolidated revenues. For the year ended December 31, 2019, no single customer accounted for 10% or greater of total sales. The Company believes that the loss of any one customer would not have an adverse effect on its ability to sell its natural gas, oil and NGL production.
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, 2020, and December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
December 31, 2020
|
|
December 31, 2019
|
Cash
|
$
|
13
|
|
|
$
|
5
|
|
Marketable securities (1)
|
—
|
|
|
—
|
|
Total
|
$
|
13
|
|
|
$
|
5
|
|
(1)Consists of government stable value money market funds. Immaterial as of December 31, 2020 and 2019.
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 $16 million and $15 million as of December 31, 2020 and 2019, 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, 2020, the Company had a total of $1,472 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.
In the first, second and third quarters of 2020, the net book value of the Company's United States natural gas and oil properties exceeded the ceiling by approximately $1,479 million, $650 million and $361 million, respectively, and resulted in non-cash ceiling test impairments. At December 31, 2020, using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $1.98 per MMBtu, West Texas Intermediate oil of $39.57 per barrel and NGLs of $10.27 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by approximately $335 million and resulted in an additional non-cash ceiling test impairment. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2020.
No impairment expense was recorded for the year ended December 31, 2020 in relation to the Company’s recently acquired Montage natural gas and oil properties. These properties were recorded at fair value as of November 13, 2020, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired at the closing of the Merger clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired in the Merger from the ceiling test calculation. This waiver was granted for all reporting periods through and including the quarter ending September 30, 2021 as long as the Company can
continue to demonstrate that the fair value of properties acquired clearly exceeds the full cost ceiling limitation beyond a reasonable doubt in each reporting period. As part of the waiver received from the SEC, the Company is required to disclose what the full cost ceiling test impairment amounts for all periods presented in each applicable quarterly and annual filing would have been if the waiver had not been granted. The fair value of the properties acquired in the Merger was based on forward strip natural gas and oil pricing existing at the date of the Merger, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the Merger. The properties acquired in the Merger have an unamortized cost at December 31, 2020 of $1,087 million. Had management not received the waiver from the SEC, the impairment charge recorded would have been an additional $539 million for the year ended December 31, 2020.
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 did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2019. 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 results 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.
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.
Other Property and Equipment. 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 estimated useful lives of those assets depreciated under the straight-line method are as follows:
|
|
|
|
|
|
Water facilities
|
5 – 10 years
|
Gathering systems
|
15 – 25 years
|
Technology infrastructure
|
3 – 7 years
|
Drilling rigs and equipment
|
3 years
|
Buildings and leasehold improvements
|
10 – 30 years
|
Other property, plant and equipment is comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
December 31, 2020
|
|
December 31, 2019
|
Water facilities
|
$
|
228
|
|
|
$
|
217
|
|
Gathering systems
|
54
|
|
|
32
|
|
Technology infrastructure
|
133
|
|
|
154
|
|
Drilling rigs and equipment
|
26
|
|
|
32
|
|
Land, buildings and leasehold improvements
|
41
|
|
|
41
|
|
Other
|
41
|
|
|
44
|
|
Less: Accumulated depreciation and impairment
|
(311)
|
|
|
(300)
|
|
Total
|
$
|
212
|
|
|
$
|
220
|
|
Impairment of Long-Lived Assets. 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 years ended December 31, 2020 and 2019 the Company recognized non-cash impairments of $5 million and $16 million, respectively, for non-core assets. During 2018, the Company recognized a non-cash impairment charge of $160 million related to gathering and other E&P assets sold in the Fayetteville Shale sale and $11 million related to other non-core assets.
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, 2020 and 2019, the Company had $48 million and $56 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, 2020, 2019 and 2018, and expects to amortize $8 million in 2021 and $5 million per year for the four years thereafter.
Leases
The Company determines if a contract contains a lease at inception or as a result of an acquisition. 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, 2020. 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 and other equipment under non-cancelable operating leases expiring through 2036. 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.
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 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.
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, restricted stock units and performance units. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.
In August 2020, the Company completed an underwritten public offering of 63,250,000 shares of its common stock with an offering price to the public of $2.50 per share. Net proceeds after deducting underwriting discounts and offering expenses were approximately $152 million. See Note 3 for additional details regarding the Company's use of proceeds from the equity offering.
Under the Agreement and Plan of Merger, Montage shareholders received 1.8656 shares of Southwestern common stock for each share of Montage common stock issued and outstanding immediately prior to the date of Merger. On November 13, 2020, the Company issued 69,740,848 shares of its common stock, or approximately $213 million in value (based on Southwestern common stock closing price as of November 13, 2020 of $3.05), as Merger consideration.
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.
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, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions, except share/per share amounts)
|
2020
|
|
2019
|
|
2018
|
Net income (loss)
|
$
|
(3,112)
|
|
|
$
|
891
|
|
|
$
|
537
|
|
|
|
|
|
|
|
Participating securities – mandatory convertible preferred stock
|
—
|
|
|
—
|
|
|
2
|
|
Net income (loss) attributable to common stock
|
$
|
(3,112)
|
|
|
$
|
891
|
|
|
$
|
535
|
|
|
|
|
|
|
|
Number of common shares:
|
|
|
|
|
|
Weighted average outstanding
|
573,889,502
|
|
|
539,345,343
|
|
|
574,631,756
|
|
Issued upon assumed exercise of outstanding stock options
|
—
|
|
|
—
|
|
|
—
|
|
Effect of issuance of non-vested restricted common stock
|
—
|
|
|
361,380
|
|
|
698,103
|
|
Effect of issuance of non-vested restricted units
|
—
|
|
|
—
|
|
|
—
|
|
Effect of issuance of non-vested performance units
|
—
|
|
|
676,191
|
|
|
1,312,949
|
|
Weighted average and potential dilutive outstanding
|
573,889,502
|
|
|
540,382,914
|
|
|
576,642,808
|
|
|
|
|
|
|
|
Earnings (loss) per common share:
|
|
|
|
|
|
Basic
|
$
|
(5.42)
|
|
|
$
|
1.65
|
|
|
$
|
0.93
|
|
Diluted
|
$
|
(5.42)
|
|
|
$
|
1.65
|
|
|
$
|
0.93
|
|
The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2020, 2019 and 2018, as they would have had an antidilutive effect:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Unexercised stock options
|
4,427,040
|
|
|
5,078,253
|
|
|
5,909,082
|
|
Unvested share-based payment
|
962,662
|
|
|
1,728,264
|
|
|
3,692,794
|
|
Restricted units
|
4,452,876
|
|
|
—
|
|
|
—
|
|
Performance units
|
2,818,653
|
|
|
271,268
|
|
|
642,568
|
|
Mandatory convertible preferred stock
|
—
|
|
|
—
|
|
|
2,465,708
|
|
Total
|
12,661,231
|
|
|
7,077,785
|
|
|
12,710,152
|
|
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, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Cash paid during the year for interest, net of amounts capitalized
|
$
|
75
|
|
|
$
|
58
|
|
|
$
|
135
|
|
Cash paid (received) during the year for income taxes
|
(32)
|
|
|
(52)
|
|
|
6
|
|
Increase (decrease) in noncash property additions
|
1,084
|
|
(1)
|
41
|
|
|
(42)
|
|
(1)Includes $1,097 million in noncash additions related to the Montage Merger.
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 and 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, operating expense and 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 (“TSR”) and the other on relative TSR 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 liability-based performance unit awards granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. The fair values of the market conditions discussed above are calculated by Monte Carlo models on a quarterly basis. See Note 14 for a discussion of the Company’s stock-based compensation.
Cash-Based Compensation
The Company classifies certain awards that will be settled in cash as cash-based compensation. The Company recognizes the cost of these awards as general and administrative expense, operating expense and capitalized expense over the vesting period of the awards. The performance cash awards include a performance condition determined annually by the Company. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be canceled.
Treasury Stock
In 2018, the Company repurchased 39,061,268 shares of its outstanding common stock per a previously announced share repurchase program at an average price of $4.63 per share for approximately $180 million. In 2019, the Company completed its share repurchase program by purchasing another 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 frozen legacy non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants could 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, 2020 and 2019, 3,632 shares and 5,115 shares, respectively, were held in the Rabbi Trust and were accounted for 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 August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Management (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements ("ASU 2018-13"), which modifies the disclosure requirements on fair value measurements. ASU 2018-13 became effective for public business entities for annual and interim periods in the fiscal years beginning after December 15, 2019. As a result of this adoption, this standard did not have a material impact on the Company's consolidated financial statements.
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 replaced 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 became 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 and recently acquired credit portfolios, which include trade receivables from commodity sales, joint interest billings due from partners and 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 counterparties. Update 2016-13 did not have a significant impact on the Company's consolidated financial statements or related control environment upon adoption on January 1, 2020.
New Accounting Standards Not Yet Adopted in this Report
In August 2018, the FASB issued ASU 2018-14, Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans ("ASU 2018-14"). This ASU amends, adds and removes certain disclosure requirements under FASB ASC Topic 715 – Compensation – Retirement Benefits. The guidance in ASU 2018-14 is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. This ASU will result in expanded disclosures within the Company's interim
and annual footnote disclosures, however, the adoption of ASU 2018 is not expected to have a material impact on the Company's consolidated financial statements.
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform, as a new Accounting Standards Codification (“ASC”) Topic, ASC 848. The purpose of ASC 848 is to provide optional guidance to ease the potential effects on financial reporting of the market-wide migration away from Interbank Offered Rates, such as LIBOR, which is expected to be phased out at the end of calendar year 2021, to alternative reference rates. ASC 848 applies only to contracts, hedging relationships, debt arrangements and other transactions that reference a benchmark reference rate expected to be discontinued because of reference rate reform. ASC 848 contains optional expedients and exceptions for applying U.S. GAAP to transactions affected by this reform. The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022. The Company is currently assessing the impact of adopting this new guidance.
(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, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
|
2020
|
|
2019
|
|
2018 (1)
|
Reduction in workforce (not Fayetteville Shale sale-related)
|
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
23
|
|
Fayetteville Shale sale-related
|
|
—
|
|
|
11
|
|
|
16
|
|
Total restructuring charges
|
|
$
|
16
|
|
|
$
|
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, 2020, which are reflected in accounts payable on the consolidated balance sheet:
|
|
|
|
|
|
(in millions)
|
|
Liability at December 31, 2019
|
$
|
2
|
|
Additions
|
16
|
|
Distributions
|
(15)
|
|
Liability at December 31, 2020
|
$
|
3
|
|
Reduction in Workforce (Not Fayetteville Shale Sale-Related)
In February 2020, the Company notified employees of a workforce reduction plan as a result of a strategic realignment of the Company's organizational structure. This reduction was substantially complete by the end of the first quarter of 2020. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. These costs were recognized as restructuring charges for the year ended December 31, 2020. The Company also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring for which a liability of $3 million has been accrued as of December 31, 2020.
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, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Severance (including payroll taxes)
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outplacement services, other
|
—
|
|
|
—
|
|
|
2
|
|
Total reduction in workforce-related restructuring charges (1)
|
$
|
16
|
|
|
$
|
—
|
|
|
$
|
23
|
|
(1)Total restructuring charges were $16 million for the Company's E&P segment for the year ended December 31, 2020. 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. The Company had substantially completed the Fayetteville Shale sale-related employment terminations by December 31, 2019.
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. Approximately $2 million in charges related to office consolidation and reorganization were 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 and $1 million in other office consolidation expenses 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. 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.
See Note 3 for a discussion of the Company’s Fayetteville Shale sale.
(3) ACQUISITIONS AND DIVESTITURES
Montage Resources Merger
On August 12, 2020, Southwestern entered into an Agreement and Plan of Merger with Montage Resources Corporation (“Montage”) whereby Montage would merge with and into Southwestern, with Southwestern continuing as the surviving company (the "Merger"). On November 12, 2020, Montage’s stockholders voted to approve the Merger and it was made effective on November 13, 2020. The Merger added to Southwestern’s oil and gas portfolio in Appalachia.
In exchange for each share of Montage common stock, Montage stockholders received 1.8656 shares of Southwestern common stock, plus cash in lieu of any fractional share of Southwestern common stock that otherwise would have been issued, based on the average price of $3.05 per share of Southwestern common stock on the NYSE on November 13, 2020. Following the closing of the Merger, Southwestern's existing shareholders and Montage's existing shareholders owned approximately 90% and 10%, respectively, of the outstanding shares of the combined company.
In anticipation of the Merger, in August 2020 Southwestern issued $350 million of new senior unsecured notes and 63,250,000 shares of common stock for $152 million after deducting underwriting discounts and offering expenses. The
Company used the net proceeds from the debt and common stock offerings and borrowings under its revolving credit facility to fund a redemption of $510 million aggregate principal amount of Montage's outstanding 8.875% senior notes due 2023 (the "Montage Notes") and related accrued interest in connection with the closing of the Merger. See Note 1 and Note 9 for additional information.
The Merger constitutes a business combination and was accounted for using the acquisition method of accounting. The following table presents the fair value of consideration transferred to Montage stockholders as a result of the Merger:
|
|
|
|
|
|
(in millions, except share, per share amounts)
|
As of November 13, 2020
|
Shares of Southwestern common stock issued in respect of outstanding Montage common stock
|
67,311,166
|
|
Shares of Southwestern common stock issued in respect of Montage stock-based awards
|
2,429,682
|
|
|
69,740,848
|
|
NYSE closing price per share of Southwestern common shares on November 13, 2020
|
$
|
3.05
|
|
Total consideration (fair value of Southwestern common shares issued)
|
$
|
213
|
|
Increase in Southwestern common stock ($0.01 par value per share)
|
1
|
|
Increase in Southwestern additional paid-in capital
|
$
|
212
|
|
The following table sets forth the fair value of the assets acquired and liabilities assumed as of the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the Company’s natural gas and oil properties. These amounts will be finalized no later than one year from the acquisition date.
|
|
|
|
|
|
(in millions)
|
As of November 13, 2020
|
Consideration:
|
|
Fair value of Southwestern’s stock issued on November 13, 2020
|
$
|
213
|
|
Fair value of assets acquired:
|
|
Cash and cash equivalents
|
3
|
|
Accounts receivable
|
73
|
|
Other current assets
|
1
|
|
Derivative assets
|
11
|
|
Evaluated natural gas and oil properties
|
1,012
|
|
Unevaluated natural gas and oil properties
|
90
|
|
Other property, plant and equipment
|
28
|
|
Other long-term assets
|
26
|
|
Total assets acquired
|
1,244
|
|
Fair value of liabilities assumed:
|
|
Accounts payable
|
145
|
|
Other current liabilities
|
49
|
|
Derivative liabilities
|
70
|
|
Revolving credit facility
|
200
|
|
Senior unsecured notes
|
522
|
|
Asset retirement obligations
|
28
|
|
Other long-term liabilities
|
17
|
|
Total liabilities assumed
|
1,031
|
|
Net assets acquired and liabilities assumed
|
$
|
213
|
|
The assets acquired and liabilities assumed were recorded at their preliminary estimated fair values at the date of the Merger. The valuation of certain assets, including property, are based on preliminary appraisals. The fair value of acquired equipment is based on both available market data and a cost approach.
Unevaluated oil and gas properties were valued primarily using a market approach based on comparable transactions for similar properties while the income approach was utilized for proved oil and gas properties based on underlying reserve projections at the Merger date. Income approaches are considered Level 3 fair value estimates and include significant assumptions of future production, commodity prices, and operating and capital cost estimates, discounted using weighted average cost of capital for industry peers, and risk adjustment factors based on reserve category. Price assumptions were based on
observable market pricing adjusted for historical differentials. Cost estimates were based on current observable costs inflated based on historical and expected future inflation. Taxes were based on current statutory rates.
Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed. A full valuation was placed on all deferred tax assets assumed from Montage consistent with the Company’s treatment of its deferred tax asset balance as of December 31, 2020. The measurement of senior unsecured notes was based on unadjusted quoted prices in an active market and are primarily Level 1. The Company considered the borrowings under the revolving credit facility to approximate fair value. The value of derivative instruments was based on observable inputs, primarily forward commodity-price and interest-rate curves and is considered Level 2.
With the completion of the Merger, Southwestern acquired proved and unproved properties of approximately $1.0 billion and $90 million, respectively, primarily associated with the Appalachian Basin. The remaining $28 million in Other property, plant and equipment consists of a gathering system, buildings and various equipment.
From the date of the Merger through December 31, 2020, revenues and the net income attributable to common stockholders associated with the operations acquired through the Merger totaled $63 million and $28 million, respectively.
The following table summarizes the unaudited pro forma condensed financial information of Southwestern as if the Merger had occurred on January 1, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions, except per share amounts)
|
2020
|
|
2019
|
Revenues
|
$
|
2,701
|
|
|
$
|
3,673
|
|
Net income (loss) attributable to common stock
|
$
|
(3,177)
|
|
|
$
|
995
|
|
Net income (loss) attributable to common stock per share – basic
|
$
|
(4.71)
|
|
|
$
|
1.48
|
|
Net income (loss) attributable to common stock per share – diluted
|
$
|
(4.71)
|
|
|
$
|
1.48
|
|
The unaudited pro forma information is not necessarily indicative of the operating results that would have occurred had the Merger been completed at January 1, 2019, nor is it necessarily indicative of future operating results of the combined entity. The unaudited pro forma information gives effect to the Merger and related equity and debt issuances along with the use of proceeds therefrom as if they had occurred on January 1, 2019. The unaudited pro forma information for 2020 and 2019 is a result of combining the statements of operations of Southwestern with the pre-Merger results from January 1, 2020, and 2019 of Montage and included adjustments for revenues and direct expenses. The pro forma results exclude any cost savings anticipated as a result of the Merger and the impact of any Merger-related costs. The pro forma results include adjustments to DD&A (depreciation, depletion and amortization) based on the purchase price allocated to property, plant, and equipment and the estimated useful lives as well as adjustments to interest expense. Interest expense was adjusted to reflect the retirement of the Montage senior notes, the Montage credit facility, all related accrued interest and the associated decrease in amortization of issuance costs related to the Montage notes and revolving line of credit. This decrease was partially offset by increases in interest on debt associated with the issuance of $350 million in new 8.375% Senior Notes due 2028 related to the Southwestern debt offering and borrowings under Southwestern’s credit facility used to pay off the Montage notes, Montage credit facility and related accrued interest. Management believes the estimates and assumptions are reasonable, and the relative effects of the Merger are properly reflected.
Montage Merger-Related Expenses
The following table summarizes the Merger-related expenses incurred for the year ended December 31, 2020:
|
|
|
|
|
|
|
|
|
|
(in millions)
|
For the year ended December 31, 2020
|
|
|
Bank, legal and consulting fees
|
$
|
18
|
|
|
|
Employee severance and related costs
|
17
|
|
|
|
Contract buyouts
|
5
|
|
|
|
Other
|
1
|
|
|
|
Total Montage merger-related expenses
|
$
|
41
|
|
|
|
Employee severance and related employee cost primarily relates to one-time severance costs and the accelerated vesting of certain Montage share-based awards for former Montage employees based on the terms of the Agreement and Plan of Merger and existing change of control provisions within the former Montage employment agreements. Contract buyouts primarily consist of the costs associated with the settlement of contracts inherited from Montage that had no future value to the Company’s ongoing business.
2019 Divestitures
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.
Fayetteville Shale Sale
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.
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.
(4) LEASES
As part of the Montage Merger, the Company acquired $25 million of operating right of use assets and corresponding lease liabilities which were recognized as part of the Company’s acquisition accounting in the fourth quarter of 2020.
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 years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
Operating lease cost
|
$
|
48
|
|
|
$
|
45
|
|
Short-term lease cost
|
35
|
|
|
45
|
|
Variable lease cost
|
3
|
|
|
1
|
|
Total lease cost
|
$
|
86
|
|
|
$
|
91
|
|
As of December 31, 2020, the Company had operating leases of $6 million, related primarily to compressor leases, that have been executed but not yet commenced. These operating leases are planned to commence during 2021 with lease terms expiring through 2024. 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 years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
Cash paid for amounts included in the measurement of lease liabilities:
|
|
|
|
Operating cash flows from operating leases
|
$
|
47
|
|
|
$
|
47
|
|
|
|
|
|
Right-of-use assets obtained in exchange for operating liabilities:
|
|
|
|
Operating leases
|
$
|
48
|
|
|
$
|
95
|
|
Supplemental balance sheet information related to leases is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
December 31, 2020
|
|
December 31, 2019
|
Right-of-use asset balance:
|
|
|
|
Operating leases
|
$
|
163
|
|
|
$
|
159
|
|
Lease liability balance:
|
|
|
|
Current operating leases
|
$
|
42
|
|
|
$
|
34
|
|
Long-term operating leases
|
117
|
|
|
119
|
|
Total operating leases
|
$
|
159
|
|
|
$
|
153
|
|
|
|
|
|
Weighted average remaining lease term: (years)
|
|
|
|
Operating leases
|
5.6
|
|
6.6
|
|
|
|
|
Weighted average discount rate:
|
|
|
|
Operating leases
|
5.97
|
%
|
|
5.33
|
%
|
Maturity analysis of operating lease liabilities:
|
|
|
|
|
|
(in millions)
|
December 31, 2020
|
2021
|
$
|
50
|
|
2022
|
37
|
|
2023
|
26
|
|
2024
|
18
|
|
2025
|
14
|
|
Thereafter
|
42
|
|
Total undiscounted lease liability
|
187
|
|
Imputed interest
|
(28)
|
|
Total discounted lease liability
|
$
|
159
|
|
(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.
Marketing. The Company, through its marketing affiliate, generally markets natural gas, oil and NGLs for its affiliated E&P companies as well as other joint owners who choose to market with the Company. In addition, the Company markets some
products purchased from third parties. Marketing revenues for natural gas, oil and NGL sales are recognized when control of the product is transferred to the customer at a designated delivery point. The pricing provisions of the Company’s contracts are primarily tied to market indices with certain adjustments based on factors such as delivery, quality of the product and prevailing supply and demand conditions. Under the Company’s marketing contracts, the delivery of each unit of natural gas, oil and NGLs represents a separate performance obligation, and revenue is recognized at the point in time when the performance obligations are fulfilled. Customers are invoiced and revenues are recorded each month as natural gas, oil and NGLs are delivered, and payment terms are typically within 30 to 60 days of control transfer. Furthermore, consideration from a customer corresponds directly with the value to the customer of the Company’s performance completed to date. As a result, the Company recognizes revenue in the amount 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, 2020
|
|
|
|
|
|
|
|
Gas sales
|
$
|
928
|
|
|
$
|
—
|
|
|
$
|
39
|
|
|
$
|
967
|
|
Oil sales
|
150
|
|
|
—
|
|
|
4
|
|
|
154
|
|
NGL sales
|
265
|
|
|
—
|
|
|
—
|
|
|
265
|
|
Marketing
|
—
|
|
|
2,145
|
|
|
(1,228)
|
|
|
917
|
|
Other (1)
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
Total
|
$
|
1,348
|
|
|
$
|
2,145
|
|
|
$
|
(1,185)
|
|
|
$
|
2,308
|
|
|
|
|
|
|
|
|
|
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
|
|
(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)
|
2020
|
|
2019
|
|
2018
|
Northeast Appalachia
|
$
|
648
|
|
|
$
|
964
|
|
|
$
|
1,165
|
|
Southwest Appalachia
|
700
|
|
|
736
|
|
|
817
|
|
Fayetteville Shale
|
—
|
|
|
—
|
|
|
537
|
|
Other
|
—
|
|
|
3
|
|
|
6
|
|
Total
|
$
|
1,348
|
|
|
$
|
1,703
|
|
|
$
|
2,525
|
|
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, 2020
|
|
December 31, 2019
|
Receivables from contracts with customers
|
$
|
350
|
|
|
$
|
284
|
|
Other accounts receivable
|
18
|
|
|
61
|
|
Total accounts receivable
|
$
|
368
|
|
|
$
|
345
|
|
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, 2020 and 2019. 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, 2020, 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.
|
Swaptions
|
Instruments that refer to an option to enter into a fixed price swap. In exchange for an option premium, the purchaser gains the right but not the obligation to enter a specified swap agreement with the issuer for specified future dates. If the Company sells a swaption, the counterparty has the right to enter into a fixed price swap wherein the Company receives a fixed price for the contract and pays a floating market price to the counterparty. If the Company purchases a swaption, the Company has the right to enter into a fixed price swap wherein the Company receives a floating market price for the contract and pays a fixed price to the counterparty.
|
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.
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, 2020:
Financial Protection on Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per MMBtu
|
|
Fair value at December 31, 2020
($ in millions)
|
|
Volume
(Bcf)
|
|
Swaps
|
|
Sold Puts
|
|
Purchased Puts
|
|
Sold Calls
|
|
Basis Differential
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
201
|
|
|
$
|
2.80
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
29
|
|
Two-way costless collars
|
237
|
|
|
—
|
|
|
—
|
|
|
2.57
|
|
|
2.95
|
|
|
—
|
|
|
11
|
|
Three-way costless collars
|
313
|
|
|
—
|
|
|
2.16
|
|
|
2.49
|
|
|
2.85
|
|
|
—
|
|
|
(24)
|
|
Total
|
751
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
112
|
|
|
$
|
2.68
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
Two-way costless collars
|
63
|
|
|
—
|
|
|
—
|
|
|
2.52
|
|
|
3.03
|
|
|
—
|
|
|
(1)
|
|
Three-way costless collars
|
203
|
|
|
—
|
|
|
2.06
|
|
|
2.46
|
|
|
2.89
|
|
|
—
|
|
|
(15)
|
|
Total
|
378
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(12)
|
|
2023
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three-way costless collars
|
87
|
|
|
$
|
—
|
|
|
$
|
2.06
|
|
|
$
|
2.47
|
|
|
$
|
2.98
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
219
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(0.21)
|
|
|
$
|
57
|
|
2022
|
139
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.33)
|
|
|
8
|
|
2023
|
47
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.45)
|
|
|
—
|
|
2024
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.60)
|
|
|
—
|
|
2025
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.59)
|
|
|
—
|
|
Total
|
420
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price per Bbl
|
|
Fair value at December 31, 2020
($ in millions)
|
|
Volume
(MBbls)
|
|
Swaps
|
|
Sold Puts
|
|
Purchased Puts
|
|
Sold Calls
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
4,887
|
|
|
$
|
48.59
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Two-way costless collars
|
201
|
|
|
—
|
|
|
—
|
|
|
37.73
|
|
|
45.68
|
|
|
(1)
|
|
Three-way costless collars
|
1,543
|
|
|
—
|
|
|
37.42
|
|
|
47.22
|
|
|
52.86
|
|
|
—
|
|
Total
|
6,631
|
|
|
|
|
|
|
|
|
|
|
$
|
—
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
1,282
|
|
|
$
|
46.37
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Three-way costless collars
|
873
|
|
|
—
|
|
|
40.25
|
|
|
50.78
|
|
|
56.54
|
|
|
1
|
|
Total
|
2,155
|
|
|
|
|
|
|
|
|
|
|
$
|
1
|
|
2023
|
|
|
|
|
|
|
|
|
|
|
|
Three-way costless collars
|
878
|
|
|
$
|
—
|
|
|
$
|
33.52
|
|
|
$
|
43.52
|
|
|
$
|
53.41
|
|
|
$
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ethane
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
5,889
|
|
|
$
|
7.12
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(10)
|
|
Two-way costless collars
|
584
|
|
|
—
|
|
|
—
|
|
|
7.14
|
|
|
10.40
|
|
|
—
|
|
Total
|
6,473
|
|
|
|
|
|
|
|
|
|
|
$
|
(10)
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
1,575
|
|
|
$
|
8.69
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Two-way costless collars
|
135
|
|
|
—
|
|
|
—
|
|
|
7.56
|
|
|
9.66
|
|
|
—
|
|
Total
|
1,710
|
|
|
|
|
|
|
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Propane
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
6,974
|
|
|
$
|
20.43
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(36)
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
2,120
|
|
|
$
|
20.23
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Normal Butane
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
2,004
|
|
|
$
|
24.97
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(8)
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
667
|
|
|
$
|
22.77
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gasoline
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
1,936
|
|
|
$
|
37.35
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(13)
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
643
|
|
|
$
|
37.77
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Derivative Contracts
|
|
Volume
(Bcf)
|
|
Weighted Average Strike Price per MMBtu
|
|
Fair value at December 31, 2020
($ in millions)
|
Call Options – Natural Gas (Net)
|
|
|
|
|
|
2021
|
75
|
|
|
$
|
3.19
|
|
|
$
|
(8)
|
|
2022
|
77
|
|
|
3.00
|
|
|
(17)
|
|
2023
|
46
|
|
|
2.94
|
|
|
(8)
|
|
2024
|
9
|
|
|
3.00
|
|
|
(3)
|
|
Total
|
207
|
|
|
|
|
$
|
(36)
|
|
|
|
|
|
|
|
Put Options – Natural Gas
|
|
|
|
|
|
2021
|
18
|
|
|
$
|
2.00
|
|
|
$
|
(1)
|
|
2022
|
5
|
|
|
2.00
|
|
|
—
|
|
Total
|
23
|
|
|
|
|
$
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(MBbls)
|
|
Weighted Average Strike Price per Bbl
|
|
Fair value at December 31, 2020
($ in millions)
|
Sold Call Options – Oil
|
|
|
|
|
|
2021
|
226
|
|
|
$
|
60.00
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
(Bcf)
|
|
Weighted Average Strike Price per MMBtu
|
|
Fair value at December 31, 2020
($ in millions)
|
Swaptions – Natural Gas
|
|
|
|
|
|
2021
|
0.1
|
|
$
|
3.00
|
|
|
$
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Strike Price per MMBtu
|
|
Fair value at
December 31, 2020
($ in millions)
|
Storage (1)
|
Volume (Bcf)
|
|
Swaps
|
|
Basis Differential
|
|
2021
|
|
|
|
|
|
|
|
Purchased fixed price swap
|
1
|
|
|
$
|
2.04
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fixed price swaps
|
2
|
|
|
2.49
|
|
|
—
|
|
|
—
|
|
Basis swaps
|
1
|
|
|
—
|
|
|
(0.38)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Total
|
4
|
|
|
|
|
|
|
$
|
—
|
|
(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, 2020
($ in millions)
|
Purchased Fixed Price Swaps – Marketing (Natural Gas) (1)
|
|
|
|
|
|
2021
|
6
|
|
|
$
|
2.44
|
|
|
$
|
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, 2020, the net fair value of the Company’s financial instruments related to commodities was a $41 million liability and included a net reduction of the liability of $1 million due to non-performance risk. See Note 8 for additional details regarding the Company's fair value measurements of its derivative positions.
As of December 31, 2020, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or 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. Only the settled gains and losses are included in the Company’s realized commodity price calculations.
The balance sheet classification of the assets and liabilities related to derivative financial instruments are summarized below as of December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets
|
|
|
|
Balance Sheet Classification
|
|
Fair Value
|
|
(in millions)
|
|
December 31, 2020
|
|
December 31, 2019
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
Purchased fixed price swaps – natural gas
|
Derivative assets
|
|
$
|
1
|
|
|
$
|
—
|
|
|
Fixed price swaps – natural gas
|
Derivative assets
|
|
37
|
|
|
77
|
|
(1)
|
Fixed price swaps – oil
|
Derivative assets
|
|
13
|
|
|
4
|
|
|
Fixed price swaps – ethane
|
Derivative assets
|
|
—
|
|
|
11
|
|
|
Fixed price swaps – propane
|
Derivative assets
|
|
—
|
|
|
21
|
|
|
Two-way costless collars – natural gas
|
Derivative assets
|
|
54
|
|
|
10
|
|
|
Two-way costless collars – oil
|
Derivative assets
|
|
—
|
|
|
5
|
|
|
Two-way costless collars – propane
|
Derivative assets
|
|
—
|
|
|
2
|
|
|
Three-way costless collars – natural gas
|
Derivative assets
|
|
57
|
|
|
126
|
|
|
Three-way costless collars – oil
|
Derivative assets
|
|
15
|
|
|
3
|
|
|
Basis swaps – natural gas
|
Derivative assets
|
|
60
|
|
|
17
|
|
|
Call options – natural gas
|
Derivative assets
|
|
4
|
|
|
1
|
|
|
Fixed price swaps – natural gas storage
|
Derivative assets
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Fixed price swaps – natural gas
|
Other long-term assets
|
|
7
|
|
|
7
|
|
|
Fixed price swaps – oil
|
Other long-term assets
|
|
2
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Fixed price swaps – propane
|
Other long-term assets
|
|
—
|
|
|
3
|
|
|
Two-way costless collars – natural gas
|
Other long-term assets
|
|
20
|
|
|
4
|
|
|
|
|
|
|
|
|
|
Three-way costless collars – natural gas
|
Other long-term assets
|
|
87
|
|
|
74
|
|
|
Three-way costless collars – oil
|
Other long-term assets
|
|
15
|
|
|
7
|
|
|
Basis swaps – natural gas
|
Other long-term assets
|
|
15
|
|
|
15
|
|
|
Call options – natural gas
|
Other long-term assets
|
|
—
|
|
|
2
|
|
|
|
|
|
|
|
|
|
Total derivative assets
|
|
|
$
|
387
|
|
|
$
|
391
|
|
|
(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, 2020
|
|
December 31, 2019
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
Purchased fixed price swaps – natural gas
|
Derivative liabilities
|
|
$
|
—
|
|
|
$
|
1
|
|
|
|
|
|
|
|
Fixed price swaps – natural gas
|
Derivative liabilities
|
|
7
|
|
|
1
|
|
Fixed price swaps – oil
|
Derivative liabilities
|
|
12
|
|
|
6
|
|
Fixed price swaps – ethane
|
Derivative liabilities
|
|
10
|
|
|
—
|
|
Fixed price swaps – propane
|
Derivative liabilities
|
|
36
|
|
|
—
|
|
Fixed price swaps – normal butane
|
Derivative liabilities
|
|
8
|
|
|
—
|
|
Fixed price swaps – natural gasoline
|
Derivative liabilities
|
|
13
|
|
|
—
|
|
Two-way costless collars – natural gas
|
Derivative liabilities
|
|
43
|
|
|
4
|
|
Two-way costless collars – oil
|
Derivative liabilities
|
|
1
|
|
|
5
|
|
Three-way costless collars – natural gas
|
Derivative liabilities
|
|
82
|
|
|
84
|
|
Three-way costless collars – oil
|
Derivative liabilities
|
|
15
|
|
|
4
|
|
Basis swaps – natural gas
|
Derivative liabilities
|
|
3
|
|
|
17
|
|
Call options – natural gas
|
Derivative liabilities
|
|
12
|
|
|
3
|
|
Put options – natural gas
|
Derivative liabilities
|
|
1
|
|
|
—
|
|
Swaptions – natural gas
|
Derivative liabilities
|
|
2
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps – natural gas
|
Other long-term liabilities
|
|
3
|
|
|
—
|
|
Fixed price swaps – oil
|
Other long-term liabilities
|
|
2
|
|
|
2
|
|
Fixed price swaps – propane
|
Other long-term liabilities
|
|
2
|
|
|
—
|
|
Fixed price swaps – normal butane
|
Other long-term liabilities
|
|
1
|
|
|
—
|
|
Fixed price swaps – natural gasoline
|
Other long-term liabilities
|
|
2
|
|
|
—
|
|
Two-way costless collars – natural gas
|
Other long-term liabilities
|
|
21
|
|
|
4
|
|
|
|
|
|
|
|
Three-way costless collars – natural gas
|
Other long-term liabilities
|
|
102
|
|
|
72
|
|
Three-way costless collars – oil
|
Other long-term liabilities
|
|
15
|
|
|
8
|
|
Basis swaps – natural gas
|
Other long-term liabilities
|
|
7
|
|
|
9
|
|
Call options – natural gas
|
Other long-term liabilities
|
|
28
|
|
|
15
|
|
Call options – oil
|
Other long-term liabilities
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
Total derivative liabilities
|
|
|
$
|
428
|
|
|
$
|
236
|
|
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, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(in millions)
|
|
Purchased fixed price swaps – natural gas
|
|
Gain (Loss) on Derivatives
|
|
$
|
2
|
|
|
$
|
(1)
|
|
|
Purchased fixed price swaps – oil
|
|
Gain (Loss) on Derivatives
|
|
—
|
|
|
6
|
|
|
Fixed price swaps – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(25)
|
|
|
46
|
|
|
Fixed price swaps – oil
|
|
Gain (Loss) on Derivatives
|
|
—
|
|
|
(22)
|
|
|
Fixed price swaps – ethane
|
|
Gain (Loss) on Derivatives
|
|
(21)
|
|
|
6
|
|
|
Fixed price swaps – propane
|
|
Gain (Loss) on Derivatives
|
|
(60)
|
|
|
13
|
|
|
Fixed price swaps – normal butane
|
|
Gain (Loss) on Derivatives
|
|
(9)
|
|
|
—
|
|
|
Fixed price swaps – natural gasoline
|
|
Gain (Loss) on Derivatives
|
|
(15)
|
|
|
—
|
|
|
Two-way costless collars – natural gas
|
|
Gain (Loss) on Derivatives
|
|
10
|
|
|
2
|
|
|
Two-way costless collars – oil
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
(10)
|
|
|
Two-way costless collars – propane
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
2
|
|
|
Three-way costless collars – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(77)
|
|
|
37
|
|
|
Three-way costless collars – oil
|
|
Gain (Loss) on Derivatives
|
|
3
|
|
|
(2)
|
|
|
Basis swaps – natural gas
|
|
Gain (Loss) on Derivatives
|
|
59
|
|
|
17
|
|
|
Call options – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(10)
|
|
|
1
|
|
|
Call options – oil
|
|
Gain (Loss) on Derivatives
|
|
1
|
|
|
(1)
|
|
|
Swaptions – natural gas
|
|
Gain (Loss) on Derivatives
|
|
7
|
|
|
—
|
|
|
Fixed price swaps – natural gas storage
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
1
|
|
|
Interest rate swaps
|
|
Gain (Loss) on Derivatives
|
|
—
|
|
|
(1)
|
|
|
Total gain (loss) on unsettled derivatives
|
|
|
|
$
|
(138)
|
|
|
$
|
94
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(in millions)
|
|
Purchased fixed price swaps – natural gas
|
|
Gain (Loss) on Derivatives
|
|
$
|
(3)
|
|
|
$
|
—
|
|
|
Purchased fixed price swaps – oil
|
|
Gain (Loss) on Derivatives
|
|
—
|
|
|
(3)
|
|
|
Fixed price swaps – natural gas
|
|
Gain (Loss) on Derivatives
|
|
142
|
|
(2)
|
78
|
|
|
Fixed price swaps – oil
|
|
Gain (Loss) on Derivatives
|
|
65
|
|
|
10
|
|
|
Fixed price swaps – ethane
|
|
Gain (Loss) on Derivatives
|
|
6
|
|
|
17
|
|
|
Fixed price swaps – propane
|
|
Gain (Loss) on Derivatives
|
|
18
|
|
|
29
|
|
|
Fixed price swaps – normal butane
|
|
Gain (Loss) on Derivatives
|
|
(2)
|
|
|
—
|
|
|
Fixed price swaps – natural gasoline
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
—
|
|
|
Two-way costless collars – natural gas
|
|
Gain (Loss) on Derivatives
|
|
(5)
|
|
|
16
|
|
|
Two-way costless collars – oil
|
|
Gain (Loss) on Derivatives
|
|
17
|
|
|
6
|
|
|
Two-way costless collars – propane
|
|
Gain (Loss) on Derivatives
|
|
2
|
|
|
2
|
|
|
Three-way costless collars – natural gas
|
|
Gain (Loss) on Derivatives
|
|
38
|
|
(3)
|
31
|
|
|
Three-way costless collars – oil
|
|
Gain (Loss) on Derivatives
|
|
9
|
|
|
—
|
|
|
Basis swaps – natural gas
|
|
Gain (Loss) on Derivatives
|
|
76
|
|
|
(3)
|
|
|
Call options – natural gas
|
|
Gain (Loss) on Derivatives
|
|
—
|
|
|
(2)
|
|
(4)
|
|
|
|
|
|
|
|
|
Purchased fixed price swaps – natural gas storage
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
—
|
|
|
Fixed price swaps – natural gas storage
|
|
Gain (Loss) on Derivatives
|
|
2
|
|
|
(1)
|
|
|
Interest rate swaps
|
|
Gain (Loss) on Derivatives
|
|
(1)
|
|
|
—
|
|
|
Total gain on settled derivatives
|
|
|
|
$
|
362
|
|
|
$
|
180
|
|
|
|
|
|
|
|
|
|
|
Total gain on derivatives
|
|
|
|
$
|
224
|
|
|
$
|
274
|
|
|
(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 $9 million amortization of premiums paid related to certain natural gas fixed price options for the year ended December 31, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations.
(3)Includes $2 million amortization of premiums paid related to certain natural gas three-way costless collars for the year ended December 31, 2020, which is included in gain (loss) on derivatives on the consolidated statements of operations.
(4)Includes $1 million amortization of premiums paid related to certain natural gas call options for the year ended December 31, 2019, which is included in gain (loss) on derivatives on the consolidated statement of operations.
(7) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
In 2020, 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, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2020
|
(in millions)
|
Pension and Other Postretirement
|
|
Foreign Currency
|
|
Total
|
Beginning balance, December 31, 2019
|
$
|
(19)
|
|
|
$
|
(14)
|
|
|
$
|
(33)
|
|
Other comprehensive loss before reclassifications
|
—
|
|
|
—
|
|
|
—
|
|
Amounts reclassified from other comprehensive income (1)
|
(5)
|
|
|
—
|
|
|
(5)
|
|
Net current-period other comprehensive loss
|
(5)
|
|
|
—
|
|
|
(5)
|
|
Ending balance, December 31, 2020
|
$
|
(24)
|
|
|
$
|
(14)
|
|
|
$
|
(38)
|
|
(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, 2020
|
Pension and other postretirement:
|
|
|
|
(in millions)
|
Amortization of prior service cost and net loss (1)
|
|
Other Loss, Net
|
|
$
|
(6)
|
|
|
|
Provision for income taxes
|
|
(1)
|
|
|
|
Net loss
|
|
$
|
(5)
|
|
|
|
|
|
|
Total reclassifications for the period
|
|
Net loss
|
|
$
|
(5)
|
|
(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, 2020 and 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
(in millions)
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
|
Cash and cash equivalents
|
$
|
13
|
|
|
$
|
13
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
2018 revolving credit facility due April 2024 (1)
|
700
|
|
|
700
|
|
|
34
|
|
|
34
|
|
|
Senior notes (2)
|
2,471
|
|
|
2,609
|
|
|
2,228
|
|
|
2,085
|
|
|
Derivative instruments, net
|
(41)
|
|
|
(41)
|
|
|
155
|
|
(3)
|
155
|
|
(3)
|
(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 as of December 31, 2019 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. The fair value of the Company's 4.10% Senior Notes due March 2022 is considered to be a Level 2 measurement on the fair value hierarchy. The fair values of the Company's remaining senior notes are considered to be a Level 1 measurement. The carrying values 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 Company measures the fair value of its derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, natural gas and liquids forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and non-performance risk. Non-performance risk considers the effect of the Company’s credit standing on the fair value of derivative liabilities and the effect of counterparty credit standing on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. As of December 31, 2020, the impact of non-performance risk on the fair value of the Company’s net derivative liability position was a reduction of the liability of $1 million.
The Company has classified its derivative instruments into 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, 2020 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 call options, two-way costless collars, three-way costless collars and swaptions (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. 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.
The Company’s basis swaps (Level 2) are estimated using third-party calculations based upon forward commodity price curves.
Assets and liabilities measured at fair value on a recurring basis are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
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:
|
|
|
|
|
|
|
|
Purchased fixed price swaps
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Fixed price swaps
|
—
|
|
|
59
|
|
|
—
|
|
|
59
|
|
Two-way costless collars
|
—
|
|
|
74
|
|
|
—
|
|
|
74
|
|
Three-way costless collars
|
—
|
|
|
174
|
|
|
—
|
|
|
174
|
|
Basis swaps
|
—
|
|
|
75
|
|
|
—
|
|
|
75
|
|
Call options
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps
|
—
|
|
|
(96)
|
|
|
—
|
|
|
(96)
|
|
Two-way costless collars
|
—
|
|
|
(65)
|
|
|
—
|
|
|
(65)
|
|
Three-way costless collars
|
—
|
|
|
(214)
|
|
|
—
|
|
|
(214)
|
|
Basis swaps
|
—
|
|
|
(10)
|
|
|
—
|
|
|
(10)
|
|
Call options
|
—
|
|
|
(40)
|
|
|
—
|
|
|
(40)
|
|
Put options
|
—
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Swaptions
|
—
|
|
|
(2)
|
|
|
—
|
|
|
(2)
|
|
|
|
|
|
|
|
|
|
Total
|
$
|
—
|
|
|
$
|
(41)
|
|
|
$
|
—
|
|
|
$
|
(41)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 swaps (1)
|
$
|
—
|
|
|
$
|
125
|
|
|
$
|
—
|
|
|
$
|
125
|
|
Two-way costless collars
|
—
|
|
|
21
|
|
|
—
|
|
|
21
|
|
Three-way costless collars
|
—
|
|
|
210
|
|
|
—
|
|
|
210
|
|
Basis swaps – natural gas
|
—
|
|
|
32
|
|
|
—
|
|
|
32
|
|
Call options
|
—
|
|
|
3
|
|
|
—
|
|
|
3
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
Purchased fixed price swaps
|
—
|
|
|
(1)
|
|
|
—
|
|
|
(1)
|
|
Fixed price swaps
|
—
|
|
|
(9)
|
|
|
—
|
|
|
(9)
|
|
Two-way costless collars
|
—
|
|
|
(13)
|
|
|
—
|
|
|
(13)
|
|
Three-way costless collars
|
—
|
|
|
(168)
|
|
|
—
|
|
|
(168)
|
|
Basis swaps
|
—
|
|
|
(26)
|
|
|
—
|
|
|
(26)
|
|
Call options
|
—
|
|
|
(19)
|
|
|
—
|
|
|
(19)
|
|
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.
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
On November 13, 2020, the Company completed the Merger with Montage. See Note 3 for a discussion of the fair value measurement of assets acquired and liabilities assumed.
In 2020, the Company determined that the $6 million carrying value of certain non-core assets exceeded their respective fair value less costs to sell and recognized a $5 million non-cash impairment. The Company used Level 2 measurements to determine the fair value of these assets.
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.
In the third quarter of 2018, the Company determined the carrying value of certain non-full cost pool assets associated with the Fayetteville Shale sale exceeded the fair value less costs to sell. 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, 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.
(9) DEBT
The components of debt as of December 31, 2020 and 2019 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
(in millions)
|
Debt Instrument
|
|
Unamortized Issuance Expense
|
|
Unamortized
Debt Discount
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt:
|
|
|
|
|
|
|
|
Variable rate (2.110% at December 31, 2020) 2018 revolving credit facility, due April 2024
|
$
|
700
|
|
|
$
|
—
|
|
(1)
|
$
|
—
|
|
|
$
|
700
|
|
4.10% Senior Notes due March 2022
|
207
|
|
|
—
|
|
|
—
|
|
|
207
|
|
4.95% Senior Notes due January 2025 (2)
|
856
|
|
|
(4)
|
|
|
(1)
|
|
|
851
|
|
7.50% Senior Notes due April 2026
|
618
|
|
|
(6)
|
|
|
—
|
|
|
612
|
|
7.75% Senior Notes due October 2027
|
440
|
|
|
(5)
|
|
|
—
|
|
|
435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.375% Senior Notes due September 2028
|
350
|
|
|
(5)
|
|
|
—
|
|
|
345
|
|
Total long-term debt
|
$
|
3,171
|
|
|
$
|
(20)
|
|
|
$
|
(1)
|
|
|
$
|
3,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
(1)At December 31, 2020 and 2019, unamortized issuance expense of $12 million and $11 million, respectively, associated with the 2018 revolving credit facility (as defined below) was classified as other long-term assets on the consolidated balance sheet.
(2)Effective in July 2018, the interest rate was 6.20% for the 2025 Notes, reflecting a net downgrade in the Company's bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company's bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021.
The following is a summary of scheduled debt maturities by year as of December 31, 2020:
|
|
|
|
|
|
(in millions)
|
|
2021
|
$
|
—
|
|
2022
|
207
|
|
2023
|
—
|
|
2024 (1)
|
700
|
|
2025
|
856
|
|
Thereafter
|
1,408
|
|
|
$
|
3,171
|
|
(1)The Company’s current revolving credit facility matures in 2024.
Credit Facilities
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”) with a group of banks that, as amended, has a maturity date of April 2024. 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.
The Company may utilize the 2018 credit facility in the form of loans and letters of credit. 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, as amended, ranges from 1.75% to 2.75% based on the Company’s utilization of 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, as amended, ranges from 0.75% to 1.75% based on the Company’s utilization of the 2018 credit facility.
In conjunction with the October 2020 redetermination process, the Company entered into an amendment to the credit agreement governing the 2018 credit facility to, among other matters:
•limit the Company's unrestricted cash and cash equivalents to $200 million when loans under the 2018 credit facility are outstanding, subject to certain exceptions; and
•increase the applicable rate by 25 basis points on loans outstanding under the 2018 credit facility.
In addition, the following amendments and redeterminations were made upon the closing of the Merger:
•increase the elected borrowing base and total aggregate commitments to $2.0 billion, the maximum permitted lien amount based on provisions in certain of the Company's senior note indentures;
•include certain Montage entities owning gas and oil properties as guarantors to the 2018 credit facility; and
•deem any Montage letters of credit issued prior to the Merger close to have been issued 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, 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. For purposes of calculating consolidated EBITDAX, the Company can include the Montage consolidated EBITDAX prior to the merger for the same twelve-month rolling period. 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, 2020, 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.
As of December 31, 2020, the Company had $233 million in letters of credit and $700 million in borrowings outstanding under the 2018 credit facility.
The Company's exposure to the anticipated transition from LIBOR in late 2021 is limited to the 2018 credit facility. Upon announcement by the administrator of LIBOR identifying a specific date for LIBOR cessation, the credit agreement governing the 2018 credit facility will be amended to reference an alternative rate as established by JP Morgan, as Administrative Agent, and the Company. The alternative rate will be based on the prevailing market convention and is expected to be the Secured Overnight Financing Rate (“SOFR”).
Senior Notes
In January 2015, the Company completed a public offering of $1.0 billion aggregate principal amount of its 4.95% Senior Notes due 2025 (the “2025 Notes”). The interest rate on the 2025 Notes is determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the 2025 Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. Effective in July 2018, the interest rate for the 2015 Notes was 6.20%, reflecting a net downgrade in the Company's bond ratings since the initial offering. On April 7, 2020, S&P downgraded the Company's bond rating to BB-, which had the effect of increasing the interest rate on the 2025 Notes to 6.45% following the July 23, 2020 interest payment due date. The first coupon payment to the bondholders at the higher interest rate will be paid in January 2021. In the event of future downgrades, the coupons for this series of notes have been capped at 6.95%.
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.
In the first half of 2020, the Company repurchased $6 million of its 4.10% senior notes due 2022, $36 million of its 4.95% senior notes due 2025, $21 million of its 7.50% senior notes due 2026 and $44 million of its 7.75% senior notes due 2027 for $72 million, and recognized a $35 million gain on the extinguishment of debt.
In August 2020, the Company completed a public offering of $350 million aggregate principal amount of its 2028 Notes, with net proceeds from the offering totaling approximately $345 million after underwriting discounts and offering expenses. The 2028 Notes were sold to the public at 100% of their face value. The net proceeds from the notes, in conjunction with the net proceeds from the August 2020 common stock offering and borrowings under the revolving credit facility, were utilized to fund a redemption of $510 million of Montage's Notes in connection with the closing of the Merger.
(10) COMMITMENTS AND CONTINGENCIES
Operating Commitments and Contingencies
As of December 31, 2020, 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, $531 million 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 $923 million of that amount. As of December 31, 2020, 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 (1)
|
$
|
8,013
|
|
|
$
|
860
|
|
|
$
|
1,532
|
|
|
$
|
1,286
|
|
|
$
|
1,813
|
|
|
$
|
2,522
|
|
Pending regulatory approval and/or construction (2)
|
531
|
|
|
2
|
|
|
30
|
|
|
37
|
|
|
88
|
|
|
374
|
|
Total transportation charges
|
$
|
8,544
|
|
|
$
|
862
|
|
|
$
|
1,562
|
|
|
$
|
1,323
|
|
|
$
|
1,901
|
|
|
$
|
2,896
|
|
(1)With the close of the Montage Merger the Company acquired firm transportation commitments of approximately $1,100 million. These commitments approximate $99 million within the next year, $197 million from 1 to 3 years, $196 million from 3 to 5 years, $284 million from 5 to 8 years and $324 million beyond 8 years.
(2)Based on the estimated in-service dates as of December 31, 2020.
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 2025 with a current aggregate annual payment of approximately $11 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 2036. As of December 31, 2020, future minimum payments under these non-cancelable leases accounted for as operating leases (including short-term) are approximately $30 million in 2021, $21 million in 2022, $18 million in 2023, $14 million in 2024, $12 million in 2025 and $36 million thereafter.
The Company also has commitments for compression services and compression rentals related to its E&P segment. As of December 31, 2020, future minimum payments under these non-cancelable agreements (including short-term obligations) are approximately $20 million in 2021, $14 million in 2022, $3 million in 2022 and less than $1 million in 2024.
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.
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, 2020, 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.
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 filed a petition to review the trial court’s decision with the Texas Supreme Court, and the Court requested a response from the plaintiff. The Court subsequently ordered full briefing on the merits of the case. 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 intends 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)
|
2020
|
|
2019
|
|
2018
|
Current:
|
|
|
|
|
|
Federal
|
$
|
(2)
|
|
|
$
|
(1)
|
|
|
$
|
(5)
|
|
State
|
—
|
|
|
(1)
|
|
|
6
|
|
|
(2)
|
|
|
(2)
|
|
|
1
|
|
Deferred:
|
|
|
|
|
|
Federal
|
371
|
|
|
(431)
|
|
|
—
|
|
State
|
38
|
|
|
22
|
|
|
—
|
|
|
409
|
|
|
(409)
|
|
|
—
|
|
Provision (benefit) for income taxes
|
$
|
407
|
|
|
$
|
(411)
|
|
|
$
|
1
|
|
The provision for income taxes was an effective rate of (15)% in 2020, (86)% in 2019 and 0% in 2018. The Company’s effective tax rate increased in 2020, as compared with 2019, primarily due to the increase in the valuation allowance in 2020. 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)
|
2020
|
|
2019
|
|
2018
|
Expected provision (benefit) at federal statutory rate
|
$
|
(568)
|
|
|
$
|
101
|
|
|
$
|
113
|
|
Increase (decrease) resulting from:
|
|
|
|
|
|
State income taxes, net of federal income tax effect
|
(55)
|
|
|
11
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in valuation allowance
|
1,034
|
|
|
(522)
|
|
|
(121)
|
|
Removal of sequestration fee on AMT receivables
|
—
|
|
|
—
|
|
|
(5)
|
|
Other
|
(4)
|
|
|
(1)
|
|
|
1
|
|
Provision (benefit) for income taxes
|
$
|
407
|
|
|
$
|
(411)
|
|
|
$
|
1
|
|
The 2020 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, 2020 and 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
Deferred tax liabilities:
|
|
|
|
Differences between book and tax basis of property
|
$
|
—
|
|
|
$
|
312
|
|
Derivative activity
|
—
|
|
|
34
|
|
Right of use lease asset
|
38
|
|
|
37
|
|
Other
|
2
|
|
|
2
|
|
|
40
|
|
|
385
|
|
Deferred tax assets:
|
|
|
|
Differences between book and tax basis of property
|
295
|
|
|
—
|
|
Accrued compensation
|
38
|
|
|
33
|
|
Accrued pension costs
|
11
|
|
|
9
|
|
Asset retirement obligations
|
20
|
|
|
13
|
|
Net operating loss carryforward
|
1,117
|
|
|
769
|
|
Future lease payments
|
38
|
|
|
37
|
|
Derivative activity
|
9
|
|
|
—
|
|
Capital loss carryover
|
27
|
|
|
—
|
|
Other
|
24
|
|
|
18
|
|
|
1,579
|
|
|
879
|
|
Valuation allowance
|
(1,539)
|
|
|
(87)
|
|
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. 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. Additionally, in January 2020 the IRS announced that any previously sequestered amounts relating to these alternative minimum tax refunds would also be refunded. The Company had approximately $2 million in sequestered amounts relating to alternative minimum tax refunds. All of those refunds have been received as of December 2020 after the CARES Act (enacted in March 2020) accelerated alternative minimum tax refunds.
In 2020, the Company received refunds related to federal income tax of $32 million. The Company received a refund of $1 million in state income tax in 2019 and paid $6.3 million in state income tax in 2018. The Company’s net operating loss carryforward as of December 31, 2020 was $4.5 billion and $2 billion for federal and state reporting purposes, respectively, the majority of which will expire between 2035 and 2039. Included in the Company's net operating loss carryforward are the net operating loss carryforwards acquired in the Montage acquisition of $1 billion. A portion of the Montage-related net operating loss carryovers are subject to an annual section 382 limitation of $1.7 million, and the Company has appropriately accounted for this limitation in purchase accounting. In addition, certain net operating loss carryovers are subject to a section 382 limitation of $90 million, but the Company does not expect this limit to have a material impact on its net operating loss carryforward balance. 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 2039. The Company also had a statutory depletion carryforward of $13 million and $55 million related to interest deduction carryforward as of December 31, 2020.
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.
Due to unexpected significant pricing declines resulting from the effects of COVID-19 and developments related to Russia/OPEC, as well as the general oversupply of the market along with the material write-down of the carrying value of the Company’s natural gas and oil properties, in addition to other negative evidence, the Company concluded that it was more likely than not that these deferred tax assets will not be realized and recorded a discrete tax expense of $408 million for the increase in its valuation allowance in the first quarter of 2020. The net change in valuation allowance is reflected as a component of income tax expense. The Company also has retained a valuation allowance of $87 million related to net operating losses in jurisdictions in which it no longer operates. Management will continue to assess available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted based on changes in subjective estimates of future taxable income or if objective negative evidence is no longer present.
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.
A reconciliation of the changes to the valuation allowance is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
Valuation allowance at beginning of year
|
$
|
87
|
|
|
$
|
609
|
|
Release of valuation allowance
|
—
|
|
|
(522)
|
|
Establishment of valuation allowance on opening deferred balance
|
408
|
|
|
—
|
|
Opening balance adjustments
|
6
|
|
|
—
|
|
Changes based on 2020 activity
|
626
|
|
|
—
|
|
|
|
|
|
Purchase accounting
|
412
|
|
|
—
|
|
|
|
|
|
Valuation allowance at end of year
|
$
|
1,539
|
|
|
$
|
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, 2020, 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)
|
2020
|
|
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 2018 to 2020 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 2020 and 2019 activity related to asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
Asset retirement obligation at January 1
|
$
|
57
|
|
|
$
|
61
|
|
Accretion of discount
|
4
|
|
|
3
|
|
Obligations incurred
|
1
|
|
|
2
|
|
Obligations assumed from Montage
|
28
|
|
|
—
|
|
Obligations settled/removed
|
(6)
|
|
|
(9)
|
|
Revisions of estimates
|
1
|
|
|
—
|
|
Asset retirement obligation at December 31
|
$
|
85
|
|
|
$
|
57
|
|
|
|
|
|
Current liability
|
$
|
4
|
|
|
$
|
6
|
|
Long-term liability
|
81
|
|
|
51
|
|
Asset retirement obligation at December 31
|
$
|
85
|
|
|
$
|
57
|
|
(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, $2 million and $3 million of contribution expense in 2020, 2019 and 2018, respectively. Additionally, the Company capitalized $1 million of contributions in 2020 and $1 million and $2 million in 2019 and 2018, respectively, 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. As part of ongoing effort to reduce costs, the Company has elected to freeze its pension plan effective January 1, 2021. Employees that were participants in the pension plan prior to January 1, 2021 will continue to receive the interest component of the plan but will no longer receive the service component. 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.
Prior to January 1, 2021, substantially all of the Company’s employees were covered by the defined benefit pension. Substantially all of the Company’s employees continue to be covered by the postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
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. In 2020, the settlement loss was immaterial.
The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
(in millions)
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Change in benefit obligations:
|
|
|
|
|
|
|
|
Benefit obligation at January 1
|
$
|
126
|
|
|
$
|
125
|
|
|
$
|
13
|
|
|
$
|
13
|
|
Service cost
|
7
|
|
|
7
|
|
|
2
|
|
|
1
|
|
Interest cost
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
Participant contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Actuarial loss
|
16
|
|
|
15
|
|
|
1
|
|
|
1
|
|
Benefits paid
|
(13)
|
|
|
(2)
|
|
|
(1)
|
|
|
(2)
|
|
Plan amendments
|
—
|
|
|
—
|
|
|
(2)
|
|
|
—
|
|
Curtailments
|
(2)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Settlements
|
—
|
|
|
(24)
|
|
|
—
|
|
|
—
|
|
Benefit obligation at December 31
|
$
|
139
|
|
|
$
|
126
|
|
|
$
|
13
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
(in millions)
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Change in plan assets:
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
$
|
96
|
|
|
$
|
91
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
11
|
|
|
16
|
|
|
—
|
|
|
—
|
|
Employer contributions
|
12
|
|
|
12
|
|
|
1
|
|
|
2
|
|
Participant contributions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefits paid
|
(13)
|
|
|
(2)
|
|
|
(1)
|
|
|
(2)
|
|
Settlements
|
—
|
|
|
(21)
|
|
|
—
|
|
|
—
|
|
Fair value of plan assets at December 31
|
$
|
106
|
|
|
$
|
96
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Funded status of plans at December 31
|
$
|
(33)
|
|
|
$
|
(30)
|
|
|
$
|
(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, 2020 and 2019 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
Projected benefit obligation
|
$
|
139
|
|
|
$
|
126
|
|
Accumulated benefit obligation
|
139
|
|
|
124
|
|
Fair value of plan assets
|
106
|
|
|
96
|
|
Pension and other postretirement benefit costs include the following components for 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Service cost
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
10
|
|
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
2
|
|
Interest cost
|
5
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Expected return on plan assets
|
(6)
|
|
|
(6)
|
|
|
(7)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of transition obligation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
1
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net periodic benefit cost
|
7
|
|
|
8
|
|
|
10
|
|
|
2
|
|
|
1
|
|
|
3
|
|
Curtailment gain
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
Settlement loss
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total benefit cost (benefit)
|
$
|
7
|
|
|
$
|
14
|
|
|
$
|
10
|
|
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
(1)
|
|
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, 2020 and 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
(in millions)
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Net actuarial (loss) gain arising during the year
|
$
|
(12)
|
|
|
$
|
(5)
|
|
|
$
|
2
|
|
|
$
|
(1)
|
|
Amortization of prior service cost
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
1
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Settlements
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
Curtailments
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Tax effect
|
3
|
|
|
(1)
|
|
|
(1)
|
|
|
—
|
|
|
$
|
(5)
|
|
|
$
|
4
|
|
|
$
|
1
|
|
|
$
|
(1)
|
|
Included in accumulated other comprehensive income as of December 31, 2020 and 2019 was a $36 million loss ($28 million net of tax) and a $30 million loss ($22 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2020, $5 million was classified from accumulated other comprehensive income, primarily driven by actuarial 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 2021 is a $1 million expense.
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2020 and 2019 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Discount rate
|
3.10
|
%
|
|
3.70
|
%
|
|
2.80
|
%
|
|
3.50
|
%
|
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 2020, 2019 and 2018 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Discount rate
|
3.70
|
%
|
|
3.70
|
%
|
|
4.35
|
%
|
|
3.50
|
%
|
|
4.35
|
%
|
|
4.35
|
%
|
Expected return on plan assets
|
6.50
|
%
|
|
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 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
Health care cost trend assumed for next year
|
6.5
|
%
|
|
7.0
|
%
|
Rate to which the cost trend is assumed to decline
|
5.0
|
%
|
|
5.0
|
%
|
Year that the rate reaches the ultimate trend rate
|
2037
|
|
2037
|
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
|
|
|
$
|
(2)
|
|
Effect on postretirement benefit obligations
|
$
|
2
|
|
|
$
|
(2)
|
|
Pension Payments and Asset Management
In 2020, the Company contributed $12 million to its pension plans and $1 million to its other postretirement benefit plan. The Company expects to contribute $13 million to its pension and other postretirement benefit plans in 2021.
The following benefit payments, which reflect projected future interest costs, are expected to be paid:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
(in millions)
|
2021
|
$
|
5
|
|
|
2021
|
|
$
|
1
|
|
2022
|
5
|
|
|
2022
|
|
1
|
|
2023
|
5
|
|
|
2023
|
|
1
|
|
2024
|
6
|
|
|
2024
|
|
1
|
|
2025
|
5
|
|
|
2025
|
|
1
|
|
Years 2026-2030
|
26
|
|
|
Years 2026-2030
|
|
4
|
|
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, 2020, 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)
|
30
|
%
|
|
49
|
%
|
Non-U.S. equity (2)
|
30
|
%
|
|
17
|
%
|
|
|
|
|
Total equity securities
|
60
|
%
|
|
66
|
%
|
Fixed income (3)
|
35
|
%
|
|
32
|
%
|
Cash (4)
|
5
|
%
|
|
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, 2020 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 value equity (1)
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
U.S. large cap core equity (2)
|
24
|
|
|
24
|
|
|
—
|
|
|
—
|
|
U.S. small cap equity (3)
|
13
|
|
|
13
|
|
|
—
|
|
|
—
|
|
Non-U.S. equity (4)
|
18
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Fixed income (5)
|
34
|
|
|
34
|
|
|
—
|
|
|
—
|
|
Cash and cash equivalents
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Total measured within fair value hierarchy
|
$
|
101
|
|
|
$
|
101
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Measured at net asset value (6)
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
U.S. large cap growth equity (7)
|
3
|
|
|
|
|
|
|
|
U.S. small cap equity (3)
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total measured at net asset value
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total plan assets at fair value
|
$
|
106
|
|
|
|
|
|
|
|
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, 2019 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 (8)
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
U.S. large cap value equity (1)
|
6
|
|
|
6
|
|
|
—
|
|
|
—
|
|
U.S. small cap equity (3)
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Non-U.S. equity (4)
|
32
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Fixed income (5)
|
22
|
|
|
22
|
|
|
—
|
|
|
—
|
|
Cash and cash equivalents
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Total measured within fair value hierarchy
|
$
|
67
|
|
|
$
|
67
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Measured at net asset value (6)
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
U.S. large cap growth equity (7)
|
3
|
|
|
|
|
|
|
|
U.S. large cap core equity (2)
|
18
|
|
|
|
|
|
|
|
Fixed income (5)
|
8
|
|
|
|
|
|
|
|
Total measured at net asset value
|
$
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total plan assets at fair value
|
$
|
96
|
|
|
|
|
|
|
|
(1)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.
(2)An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
(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)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.
(6)Plan assets for which fair value was measured using net asset value as a practical expedient.
(7)An institutional fund that seeks to invest in companies with sustainable competitive advantages, as identified through proprietary research.
(8)Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
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) LONG-TERM INCENTIVE 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, 2019 and 2020 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.
In February 2020, the Company announced a strategic realignment of the Company’s organizational structure. Affected employees were offered a severance package, which included a one-time payment depending on length of service and, if applicable, the current value of unvested long-term incentive awards that were forfeited. The Company also recognized additional severance costs in the fourth quarter of 2020 related to continued organizational restructuring. 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, 2020 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, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Stock options – general and administrative expense
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
2
|
|
Stock options – general and administrative expense capitalized
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
The Company recorded no deferred tax assets related to stock options for the year ended December 31, 2020, compared to deferred tax assets of less than $1 million for the years ended December 31, 2019 and 2018. Additionally, the Company had no unrecognized compensation cost related to unvested stock options at December 31, 2020.
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 2020, 2019 or 2018.
The following tables summarize stock option activity for the years 2020, 2019 and 2018, and provide information for options outstanding at December 31 of each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
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
|
4,635
|
|
|
$
|
15.26
|
|
|
5,178
|
|
|
$
|
17.06
|
|
|
6,020
|
|
|
$
|
19.43
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Exercised
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Forfeited or expired
|
(785)
|
|
|
$
|
24.46
|
|
|
(543)
|
|
|
$
|
32.38
|
|
|
(842)
|
|
|
$
|
33.99
|
|
Options outstanding at December 31
|
3,850
|
|
|
$
|
13.39
|
|
|
4,635
|
|
|
$
|
15.26
|
|
|
5,178
|
|
|
$
|
17.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
Options Exercisable
|
Range of
Exercise Prices
|
Options Outstanding at December 31, 2020
|
|
Weighted Average Exercise Price
|
|
Weighted Average Remaining Contractual Life
|
|
Options Exercisable at December 31, 2020
|
|
Weighted Average Exercise Price
|
|
Weighted Average Remaining Contractual Life
|
|
(in thousands)
|
|
|
|
(years)
|
|
(in thousands)
|
|
|
|
(years)
|
$7.74-$29.42
|
3,126
|
|
|
$
|
8.95
|
|
|
2.3
|
|
3,126
|
|
|
$
|
8.95
|
|
|
2.3
|
$30.59-$35.64
|
634
|
|
|
$
|
30.59
|
|
|
0.9
|
|
634
|
|
|
$
|
30.59
|
|
|
0.9
|
|
|
|
|
|
|
|
|
|
|
|
|
$46.55-$46.55
|
90
|
|
|
$
|
46.55
|
|
|
0.3
|
|
90
|
|
|
$
|
46.55
|
|
|
0.3
|
|
3,850
|
|
|
$
|
13.39
|
|
|
2.0
|
|
3,850
|
|
|
$
|
13.39
|
|
|
2.0
|
No options were granted or exercised in 2020, 2019 or 2018.
Equity-Classified Restricted Stock
The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Restricted stock grants – general and administrative expense
|
$
|
3
|
|
|
$
|
6
|
|
|
$
|
9
|
|
Restricted stock grants – general and administrative expense capitalized
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
5
|
|
The Company also recorded deferred tax asset of $2 million related to restricted stock for the year ended December 31, 2020, compared to a reduction in the deferred tax assets of less than $1 million and deferred tax asset of $2 million for the years end
2019 and 2018, respectively. As of December 31, 2020, there was $1 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 less than one year.
The following table summarizes the restricted stock activity for the years 2020, 2019 and 2018, and provides information for restricted stock outstanding at December 31 of each year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
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
|
1,480
|
|
|
$
|
7.00
|
|
|
2,717
|
|
|
$
|
7.91
|
|
|
6,254
|
|
|
$
|
8.85
|
|
|
Granted
|
584
|
|
|
$
|
2.86
|
|
|
493
|
|
|
$
|
3.06
|
|
|
350
|
|
|
$
|
4.72
|
|
|
Vested
|
(1,098)
|
|
|
$
|
5.26
|
|
|
(1,516)
|
|
|
$
|
7.16
|
|
|
(2,058)
|
|
|
$
|
9.24
|
|
|
Forfeited
|
(269)
|
|
(1)
|
$
|
7.79
|
|
|
(214)
|
|
(2)
|
$
|
8.38
|
|
|
(1,829)
|
|
(3)
|
$
|
9.01
|
|
|
Unvested shares at December 31
|
697
|
|
|
$
|
5.97
|
|
|
1,480
|
|
|
$
|
7.00
|
|
|
2,717
|
|
|
$
|
7.91
|
|
|
(1)Includes 171,813 shares forfeited as a result of the reduction in workforce for the year end December 31, 2020.
(2)Includes 65,196 shares forfeited as a result of the reduction in workforce for the year ended December 31, 2019.
(3)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 2020, $2 million for 2019 and $2 million for 2018. The total fair value of shares vested were $6 million for 2020, $11 million for 2019 and $19 million for 2018.
Equity-Classified Restricted Stock Units
As a result of the Merger with Montage, certain Montage employees became employees of Southwestern and retained their original equity awards. The amount of compensation costs related these equity-classified restricted stock units recorded by the Company was immaterial for the year ended December 31, 2020. As of December 31, 2020, there was less than $1 million of total unrecognized compensation cost related to unvested equity-classified restricted stock units that is expected to be recognized over a weighted-average period of approximately one year.
The following table summarizes equity-classified restricted stock unit activity to be paid out in Company stock for the year ended December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of Units
|
|
Weighted Average
Fair Value
|
|
(in thousands)
|
|
|
Unvested Units at January 1, 2020
|
—
|
|
|
$
|
—
|
|
Granted
|
186
|
|
|
$
|
3.05
|
|
Vested
|
(42)
|
|
|
$
|
3.05
|
|
Forfeited
|
(10)
|
|
|
$
|
3.05
|
|
Unvested Units at December 31, 2020
|
134
|
|
|
$
|
3.05
|
|
Equity-Classified Performance Units
The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2020, 2019 and 2018. 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 2020, 2019 or 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Performance units – general and administrative expense
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
3
|
|
Performance units – general and administrative expense capitalized
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
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, 2020, compared to deferred tax assets of less than $1 million and $1 million in 2019 and 2018, respectively. As of December 31, 2020, there are no more equity-classified performance units outstanding.
The following table summarizes equity-classified performance unit activity to be paid out in Company stock for the years ended December 31, 2020, 2019 and 2018, and provides information for unvested units as of December 31, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
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 units at January 1
|
178
|
|
|
$
|
10.47
|
|
|
598
|
|
|
$
|
10.01
|
|
|
1,084
|
|
|
$
|
10.12
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Vested
|
(178)
|
|
|
$
|
10.47
|
|
|
(378)
|
|
|
$
|
9.59
|
|
|
(290)
|
|
|
$
|
10.47
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
(42)
|
|
(2)
|
$
|
10.47
|
|
|
(196)
|
|
(3)
|
$
|
9.94
|
|
Unvested shares at December 31
|
—
|
|
|
$
|
—
|
|
|
178
|
|
|
$
|
10.47
|
|
|
598
|
|
|
$
|
10.01
|
|
(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)
|
2020
|
|
2019
|
|
2018
|
Restricted stock units – general and administrative expense
|
$
|
5
|
|
|
$
|
7
|
|
|
$
|
4
|
|
Restricted stock units – general and administrative expense capitalized
|
$
|
2
|
|
|
$
|
5
|
|
|
$
|
3
|
|
The Company also recorded deferred tax assets of $1 million for the year ended December 31, 2020, compared to less than $1 million and $2 million related to liability-classified restricted stock units for the years ended 2019 and 2018, respectively. As of December 31, 2020, there was $22 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 two 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, 2020 and 2019 and provides information for unvested units as of December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
Number
of Units
|
|
Weighted Average Fair Value
|
|
Number
of Units
|
|
Weighted Average Fair Value
|
|
Number
of Units
|
|
Weighted Average Fair Value
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
Unvested units at January 1
|
12,992
|
|
|
$
|
2.42
|
|
|
8,202
|
|
|
$
|
3.41
|
|
|
—
|
|
|
$
|
—
|
|
Granted
|
6,172
|
|
|
$
|
1.41
|
|
|
8,659
|
|
|
$
|
4.34
|
|
|
12,216
|
|
|
$
|
3.69
|
|
Vested
|
(3,960)
|
|
|
$
|
1.43
|
|
|
(2,624)
|
|
|
$
|
4.09
|
|
|
(232)
|
|
|
$
|
5.14
|
|
Forfeited
|
(3,591)
|
|
(1)
|
$
|
2.67
|
|
|
(1,245)
|
|
(2)
|
$
|
3.48
|
|
|
(3,782)
|
|
(3)
|
$
|
4.86
|
|
Unvested units at December 31
|
11,613
|
|
|
$
|
2.67
|
|
|
12,992
|
|
|
$
|
2.42
|
|
|
8,202
|
|
|
$
|
3.41
|
|
(1)Includes 2,010,196 units related to the reduction in workforce for the year ended December 31, 2020.
(2)Includes 400,056 units related to the reduction in workforce for the year ended December 31, 2019.
(3)Includes 2,766,610 units related to the reduction in workforce for the year ended December 31, 2018.
Liability-Classified Performance Units
In 2020, 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 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 performance unit awards granted in 2020 include a performance condition based on return on average capital employed and a market condition based on relative TSR. The fair values of all market conditions discussed above are calculated by Monte Carlo models on a quarterly basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Liability-classified performance units – general and administrative expense
|
$
|
7
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Liability-classified performance units – general and administrative expense capitalized
|
$
|
2
|
|
|
$
|
1
|
|
|
$
|
—
|
|
The Company also recorded deferred tax assets of $2 million related to liability-classified performance units for the year ended December 31, 2020, compared to a reduction of deferred tax asset of less than $1 million and a deferred tax asset of $1 million for the years ended 2019 and 2018, respectively. As of December 31, 2020, there was $14 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 or stock for the years ended December 31, 2020, 2019 and 2018 and provides information for unvested units as of December 31, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
Number
of Units
|
|
Weighted Average
Fair Value
|
|
Number
of Units
|
|
Weighted Average
Fair Value
|
|
Number
of Units
|
|
Weighted Average
Fair Value
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
|
(in thousands)
|
|
|
Unvested units at January 1
|
5,142
|
|
|
$
|
2.42
|
|
|
2,803
|
|
|
$
|
3.41
|
|
|
—
|
|
|
$
|
—
|
|
Granted
|
6,172
|
|
|
$
|
1.41
|
|
|
2,757
|
|
|
$
|
4.34
|
|
|
3,200
|
|
|
$
|
3.70
|
|
Vested
|
—
|
|
|
$
|
—
|
|
|
(43)
|
|
|
$
|
2.42
|
|
|
—
|
|
|
$
|
—
|
|
Forfeited
|
(2,615)
|
|
(1)
|
$
|
3.05
|
|
|
(375)
|
|
(2)
|
$
|
3.12
|
|
|
(397)
|
|
(3)
|
$
|
4.55
|
|
Unvested units at December 31
|
8,699
|
|
|
$
|
2.57
|
|
|
5,142
|
|
|
$
|
2.42
|
|
|
2,803
|
|
|
$
|
3.41
|
|
(1)Includes 518,450 units related to the reduction in workforce for the year ended December 31, 2020.
(2)Includes 375,086 units related to the reduction in workforce for the year ended December 31, 2019.
(3)Includes 295,160 units related to the reduction in workforce for the year ended December 31, 2018.
Cash-Based Compensation
Performance Cash Awards
In 2020, the Company granted performance cash awards that vest over a four-year period and are payable in cash on an annual basis. The value of each unit of the award equal one dollar. The Company recognizes the cost of these awards as general and administrative expense, operating expense and capitalized expense over the vesting period of the awards. The performance cash awards granted in 2020 include a performance condition determined annually by the Company. In 2020, the performance measure is a targeted discretionary cash flow amount. If the Company, in its sole discretion, determines that the threshold was not met, the amount for that vesting period will not vest and will be cancelled.
|
|
|
|
|
|
|
|
|
|
|
|
|
Number
of Units
|
|
Weighted Average
Fair Value
|
|
(in thousands)
|
|
|
Unvested units at January 1, 2020
|
—
|
|
|
$
|
—
|
|
Granted
|
20,044
|
|
|
$
|
1.00
|
|
Vested
|
(100)
|
|
|
$
|
1.00
|
|
Forfeited
|
(1,591)
|
|
(1)
|
$
|
1.00
|
|
Unvested Units at December 31, 2020
|
18,353
|
|
|
$
|
1.00
|
|
(1) Includes 945,500 units related to the reduction in workforce for the year ended December 31, 2020.
The Company also recorded a deferred tax asset of $1 million related to performance cash awards for the year ended December 31, 2020. As of December 31, 2020 there was $14 million of total unrecognized compensation cost related to performance cash awards. This cost is expected to be recognized over a weighted average 3.2 years. The final value of the performance cash awards is contingent upon the Company's actual performance against these performance measures.
(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.
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
|
2020
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
1,391
|
|
|
$
|
917
|
|
|
$
|
—
|
|
|
$
|
2,308
|
|
Intersegment revenues
|
(43)
|
|
|
1,228
|
|
|
—
|
|
|
1,185
|
|
Depreciation, depletion and amortization expense
|
348
|
|
|
9
|
|
|
—
|
|
|
357
|
|
Impairments
|
2,830
|
|
|
—
|
|
|
—
|
|
|
2,830
|
|
Operating loss
|
(2,864)
|
|
(1)
|
(7)
|
|
|
—
|
|
|
(2,871)
|
|
Interest expense (2)
|
94
|
|
|
—
|
|
|
—
|
|
|
94
|
|
Gain on derivatives
|
224
|
|
|
—
|
|
|
—
|
|
224
|
|
Gain on early extinguishment of debt
|
—
|
|
|
—
|
|
|
35
|
|
|
35
|
|
Other income, net
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
Provision for income taxes (2)
|
407
|
|
|
—
|
|
|
—
|
|
|
407
|
|
Assets
|
4,654
|
|
(3)
|
381
|
|
|
125
|
|
|
5,160
|
|
Capital investments (4)
|
899
|
|
|
—
|
|
|
—
|
|
|
899
|
|
|
|
|
|
|
|
|
|
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
|
|
(5)
|
(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
|
|
|
6,717
|
|
Capital investments (4)
|
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)
|
2
|
|
|
(2)
|
|
|
—
|
|
|
—
|
|
Provision for income taxes (2)
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Assets
|
4,872
|
|
(3)
|
539
|
|
|
386
|
|
|
5,797
|
|
Capital investments (4)
|
1,231
|
|
|
9
|
|
|
8
|
|
|
1,248
|
|
(1)Operating income for the E&P segment includes $16 million of restructuring charges and $41 million of acquisition-related charges for the year ended December 31, 2020.
(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)Capital investments include a decrease of $3 million for 2020, an increase of $34 million for 2019 and a decrease of $53 million for 2018 related to the change in accrued expenditures between years.
(5)Operating income for the E&P segment includes $11 million of restructuring charges for the year ended December 31, 2019.
(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.
The following table presents the breakout of other assets, which represent corporate assets not allocated to segments and assets for non-reportable segments for the years ended December 31, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the years ended December 31,
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Cash and cash equivalents
|
$
|
13
|
|
|
$
|
5
|
|
|
$
|
205
|
|
Accounts receivable
|
1
|
|
|
—
|
|
|
4
|
|
Income taxes receivable
|
—
|
|
|
30
|
|
|
89
|
|
Current hedging asset
|
—
|
|
|
—
|
|
|
1
|
|
Prepayments
|
6
|
|
|
8
|
|
|
8
|
|
Property, plant and equipment
|
16
|
|
|
27
|
|
|
60
|
|
Unamortized debt expense
|
11
|
|
|
11
|
|
|
11
|
|
Right-of-use lease assets
|
72
|
|
|
80
|
|
|
—
|
|
Non-qualified retirement plan
|
6
|
|
|
7
|
|
|
8
|
|
|
$
|
125
|
|
|
$
|
168
|
|
|
$
|
386
|
|
Included in intersegment revenues of the Marketing segment are $1.2 billion, $1.6 billion and $2.3 billion for 2020, 2019 and 2018, 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.
SUPPLEMENTAL QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the years ended December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions, except share amounts)
|
1st Quarter
|
|
2nd Quarter
|
|
3rd Quarter
|
|
4th Quarter
|
|
2020
|
Operating revenues
|
$
|
592
|
|
|
$
|
410
|
|
|
$
|
527
|
|
|
$
|
779
|
|
Operating loss
|
(1,490)
|
|
|
(756)
|
|
|
(381)
|
|
|
(244)
|
|
Net loss
|
(1,547)
|
|
|
(880)
|
|
|
(593)
|
|
|
(92)
|
|
Loss per share – Basic
|
(2.86)
|
|
|
(1.63)
|
|
|
(1.04)
|
|
|
(0.14)
|
|
Loss per share – Diluted
|
(2.86)
|
|
|
(1.63)
|
|
|
(1.04)
|
|
|
(0.14)
|
|
|
|
|
|
|
|
|
|
|
2019
|
Operating revenues
|
$
|
990
|
|
|
$
|
667
|
|
|
$
|
636
|
|
|
$
|
745
|
|
Operating income (loss)
|
213
|
|
|
22
|
|
|
(29)
|
|
|
64
|
|
Net income
|
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
|
|
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, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
Proved properties
|
$
|
25,789
|
|
|
$
|
23,744
|
|
Unproved properties
|
1,472
|
|
|
1,506
|
|
Total capitalized costs
|
27,261
|
|
|
25,250
|
|
Less: Accumulated depreciation, depletion and amortization
|
(23,362)
|
|
|
(20,203)
|
|
Net capitalized costs
|
$
|
3,899
|
|
|
$
|
5,047
|
|
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, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
|
Prior
|
|
Total
|
Property acquisition costs
|
$
|
116
|
|
|
$
|
44
|
|
|
$
|
34
|
|
|
$
|
1,022
|
|
|
$
|
1,216
|
|
Exploration and development costs
|
17
|
|
|
17
|
|
|
14
|
|
|
20
|
|
|
68
|
|
Capitalized interest
|
62
|
|
|
47
|
|
|
33
|
|
|
46
|
|
|
188
|
|
|
$
|
195
|
|
|
$
|
108
|
|
|
$
|
81
|
|
|
$
|
1,088
|
|
|
$
|
1,472
|
|
Of the total net unevaluated costs excluded from amortization as of December 31, 2020, approximately $1.1 billion is related to undeveloped properties in Southwest Appalachia (acquired in 2014 and 2015), $88 million is related to the recently acquired Montage properties and approximately $6 million is related to the acquisition of undeveloped properties in Northeast Appalachia. Additionally, the Company has approximately $188 million of unevaluated capitalized interest and $61 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)
|
2020
|
|
2019
|
|
2018
|
Unproved property acquisition costs
|
$
|
124
|
|
(1)
|
$
|
162
|
|
|
$
|
164
|
|
Exploration costs
|
—
|
|
|
2
|
|
|
5
|
|
Development costs
|
784
|
|
|
936
|
|
|
1,014
|
|
Capitalized costs incurred
|
$
|
908
|
|
|
$
|
1,100
|
|
|
$
|
1,183
|
|
Full cost pool amortization per Mcfe
|
$
|
0.38
|
|
|
$
|
0.56
|
|
|
$
|
0.51
|
|
(1)Excludes $90 million of unevaluated property acquisition costs associated with the non-cash Montage Merger.
Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $88 million, $109 million and $115 million during 2020, 2019 and 2018, 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 $56 million, $77 million and $90 million during 2020, 2019 and 2018, 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)
|
2020
|
|
2019
|
|
2018
|
Sales
|
$
|
1,348
|
|
|
$
|
1,703
|
|
|
$
|
2,525
|
|
Production (lifting) costs
|
(866)
|
|
|
(781)
|
|
|
(974)
|
|
Depreciation, depletion and amortization
|
(348)
|
|
|
(462)
|
|
|
(514)
|
|
Impairment of natural gas and oil properties
|
(2,825)
|
|
|
—
|
|
|
—
|
|
|
(2,691)
|
|
|
460
|
|
|
1,037
|
|
Provision for income taxes (1)
|
—
|
|
|
110
|
|
|
—
|
|
Results of operations (2)
|
$
|
(2,691)
|
|
|
$
|
350
|
|
|
$
|
1,037
|
|
(1)Prior to the recognition of a valuation allowance, in 2020 and 2018 the Company recognized an income tax provision (benefit) of ($624) million and $254 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 97% of the present worth of the Company’s total proved reserves as of December 31 of 2020. For 2019 and 2018, NSAI’s audit accounted for 99% of the present worth of the Company’s total proved properties. 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.
The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2020, 2019 and 2018, all of which were located in the United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(Bcf)
|
|
Oil
(MBbls)
|
|
NGL
(MBbls)
|
|
Total
(Bcfe)
|
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 (1)
|
(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 (2)
|
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
|
|
Revisions of previous estimates due to price
|
(2,143)
|
|
|
(32,507)
|
|
|
(338,639)
|
|
|
(4,370)
|
|
Revisions of previous estimates other than price
|
763
|
|
|
3,816
|
|
|
106,444
|
|
|
1,424
|
|
Extensions, discoveries and other additions
|
714
|
|
|
135
|
|
|
4,371
|
|
|
741
|
|
Production
|
(694)
|
|
|
(5,141)
|
|
|
(25,927)
|
|
|
(880)
|
|
Acquisition of reserves in place (3)
|
1,911
|
|
|
18,796
|
|
|
55,141
|
|
|
2,354
|
|
Disposition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2020
|
9,181
|
|
|
58,024
|
|
|
410,151
|
|
|
11,990
|
|
(1)The 2018 disposition is primarily associated with the Fayetteville Shale sale.
(2)For the year ended December 31, 2019, 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.
(3)The 2020 acquisition is primarily associated with the Montage Merger.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
(Bcf)
|
|
Oil
(MBbls)
|
|
NGL
(MBbls)
|
|
Total
(Bcfe)
|
Proved developed reserves as of:
|
|
|
|
|
|
|
|
December 31, 2018
|
4,395
|
|
|
18,037
|
|
|
175,480
|
|
|
5,557
|
|
December 31, 2019
|
4,906
|
|
|
26,124
|
|
|
226,271
|
|
|
6,421
|
|
December 31, 2020
|
6,342
|
|
|
33,563
|
|
|
276,548
|
|
|
8,203
|
|
Proved undeveloped reserves as of:
|
|
|
|
|
|
|
|
December 31, 2018
|
3,649
|
|
|
50,970
|
|
|
401,583
|
|
|
6,364
|
|
December 31, 2019
|
3,724
|
|
|
46,801
|
|
|
382,490
|
|
|
6,300
|
|
December 31, 2020
|
2,839
|
|
|
24,461
|
|
|
133,603
|
|
|
3,787
|
|
The Company’s estimated proved natural gas, oil and NGL reserves were 11,990 Bcfe at December 31, 2020, compared to 12,721 Bcfe at December 31, 2019. The Company’s reserves decreased in 2020, compared to 2019, as acquisitions, non-price revisions, positive extensions, discoveries and other additions in Appalachia were more than offset by negative price revisions and production. The increase in non-price revisions at December 31, 2020 resulted primarily from increased well performance and lower operating costs.
The increase in the Company’s reserves in 2019 primarily resulted from the positive extensions, discoveries, other additions and 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 following table summarizes the changes in reserves for 2018, 2019 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachia
|
|
Fayetteville
|
|
|
|
|
(in Bcfe)
|
Northeast
|
|
Southwest
|
|
Shale (1)
|
|
Other (2)
|
|
Total
|
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
|
|
Net revisions
|
|
|
|
|
|
|
|
|
|
Price revisions
|
(389)
|
|
|
(3,981)
|
|
|
—
|
|
|
—
|
|
|
(4,370)
|
|
Performance and production revisions
|
46
|
|
|
1,378
|
|
|
—
|
|
|
—
|
|
|
1,424
|
|
Total net revisions
|
(343)
|
|
|
(2,603)
|
|
|
—
|
|
|
—
|
|
|
(2,946)
|
|
Extensions, discoveries and other additions
|
|
|
|
|
|
|
|
|
|
Proved developed
|
198
|
|
|
69
|
|
|
—
|
|
|
—
|
|
|
267
|
|
Proved undeveloped
|
474
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
474
|
|
Total reserve additions
|
672
|
|
|
69
|
|
|
—
|
|
|
—
|
|
|
741
|
|
Production
|
(473)
|
|
|
(407)
|
|
|
—
|
|
|
—
|
|
|
(880)
|
|
Acquisition of reserves in place
|
223
|
|
|
2,131
|
|
|
—
|
|
|
—
|
|
|
2,354
|
|
Disposition of reserves in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2020
|
4,916
|
|
|
7,073
|
|
|
—
|
|
|
1
|
|
|
11,990
|
|
(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 for the year ended December 31, 2019 include 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, 2020 proved reserves included 2,437 Bcfe of proved undeveloped reserves from 138 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 $207 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, 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 that have a negative $50 million present value when discounted at 10%. 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 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, 2020, 2019 and 2018 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)
|
2020
|
|
2019
|
|
2018
|
Future cash inflows
|
$
|
17,997
|
|
|
$
|
27,003
|
|
|
$
|
34,523
|
|
Future production costs
|
(11,969)
|
|
|
(14,981)
|
|
|
(15,347)
|
|
Future development costs (1)
|
(1,924)
|
|
|
(3,246)
|
|
|
(4,095)
|
|
Future income tax expense
|
—
|
|
|
(476)
|
|
|
(2,079)
|
|
Future net cash flows
|
4,104
|
|
|
8,300
|
|
|
13,002
|
|
10% annual discount for estimated timing of cash flows
|
(2,257)
|
|
|
(4,600)
|
|
|
(7,003)
|
|
Standardized measure of discounted future net cash flows
|
$
|
1,847
|
|
|
$
|
3,700
|
|
|
$
|
5,999
|
|
(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)
|
2020
|
|
2019
|
|
2018
|
Natural gas (per MMBtu)
|
$
|
1.98
|
|
|
$
|
2.58
|
|
|
$
|
3.10
|
|
Oil (per Bbl)
|
39.57
|
|
|
55.69
|
|
|
65.56
|
|
NGLs (per Bbl)
|
10.27
|
|
|
11.58
|
|
|
17.64
|
|
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 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2020
|
|
2019
|
|
2018
|
Standardized measure, beginning of year
|
$
|
3,700
|
|
|
$
|
5,999
|
|
|
$
|
5,562
|
|
Sales and transfers of natural gas and oil produced, net of production costs
|
(478)
|
|
|
(923)
|
|
|
(1,564)
|
|
Net changes in prices and production costs
|
(2,720)
|
|
|
(3,510)
|
|
|
2,162
|
|
Extensions, discoveries, and other additions, net of future production and development costs
|
81
|
|
|
234
|
|
|
335
|
|
Acquisition of reserves in place
|
443
|
|
|
—
|
|
|
—
|
|
Sales of reserves in place
|
—
|
|
|
(2)
|
|
|
(2,022)
|
|
Revisions of previous quantity estimates
|
(987)
|
|
|
152
|
|
|
361
|
|
Net change in income taxes
|
35
|
|
|
491
|
|
|
(304)
|
|
Changes in estimated future development costs
|
1,241
|
|
|
621
|
|
|
(166)
|
|
Previously estimated development costs incurred during the year
|
624
|
|
|
704
|
|
|
536
|
|
Changes in production rates (timing) and other
|
(466)
|
|
|
(718)
|
|
|
521
|
|
Accretion of discount
|
374
|
|
|
652
|
|
|
578
|
|
Standardized measure, end of year
|
$
|
1,847
|
|
|
$
|
3,700
|
|
|
$
|
5,999
|
|