ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2018 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on February 28, 2020.
General
The following management’s discussion and analysis describes the principal factors affecting our results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing.
All of our filings with the SEC are available free of charge through our website (www.callon.com) as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this 2020 Annual Report on Form 10-K.
We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back over 70 years to our Company’s establishment in 1950. We are focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford, which we entered into through the Carrizo Acquisition in late 2019.
Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and the Eagle Ford. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.
Recent Developments
February Winter Storm
In February 2021, severe winter storms affected field operations in both the Permian and Eagle Ford resulting in the shut-in of nearly 100% of our operated production. Currently, we have returned nearly all of our Eagle Ford and Midland Basin wells to production and expect to have all of our Delaware well production returned by the end of February. The impact to our drilling and completion operations were not significant enough to alter our expectations for the full year development schedule.
COVID-19 Outbreak and Global Industry Downturn
The worldwide outbreak of COVID-19 in 2020, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. These dual demand and supply shocks caused oil prices to collapse at the end of the first quarter of 2020 as well as created an excess supply of oil in the United States, which could continue for a sustained period; this is in addition to recent and continued excess supply of natural gas in the United States. This excess supply, in turn, resulted in transportation and storage capacity constraints in the United States during 2020, although these constraints have recently lessened and inventories have declined from peak levels.
Our expectation is that commodity prices, which are the most significant factors impacting our profitability, will remain cyclical and volatile. While commodity prices have recently increased to pre-COVID-19 levels, there is no assurance of how long they will remain at these levels.
2020 Highlights
Operational
•Our total production in 2020 increased by 147% to 37.2 MMBoe (63% oil) as compared to 2019 primarily as a result of the Carrizo Acquisition in late 2019 and wells placed on production during 2020 as a result of our horizontal drilling program.
•Although our actual 2020 operational capital expenditures were approximately 50% or our original operational capital budget as a result of COVID-19 and the macro-economic environment, we drilled 91 gross (86.0 net) horizontal well and completed 90 gross (81.4 net) horizontal wells for the year ended December 31, 2020 and had, as of December 31, 2020, 65 gross (62.1 net) horizontal wells awaiting completion.
•Estimated proved reserves as of December 31, 2020 were 475.9 MMBoe (61% oil), with 45% classified as proved developed.
Financing
•On November 13, 2020, we exchanged $389.0 million of aggregate principal amount of our existing Senior Unsecured Notes for $216.7 million aggregate principal amount of November 2020 Second Lien Notes and 1.75 million November 2020 Warrants. This exchange resulted in the removal of approximately $172.3 million from the long-term debt balance in our consolidated balance sheets.
•On September 30, 2020, we issued $300.0 million of aggregate principal amount of September 2020 Second Lien Notes and 7.3 million September 2020 Warrants for proceeds, net of issuance costs, of approximately $288.6 million.
•As of December 31, 2020, our Credit Facility had a borrowing base and elected commitment amount of $1.6 billion and $985.0 million of borrowings outstanding as compared to borrowings outstanding as of December 31, 2019 of $1.3 billion.
Divestitures
•On September 30, 2020, we sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to our net revenue interest, in and to our operated leases, excluding certain interests (“ORRI Transaction”) for net proceeds of $135.8 million, which were used to repay borrowings outstanding under the Credit Facility.
•On November 2, 2020, we sold substantially all of our non-operated assets for net proceeds of $29.6 million, subject to post-closing adjustments, which were used to repay borrowings outstanding under the Credit Facility.
Results of Operations
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
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Years Ended December 31,
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2020
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2019 (1)
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$ Change
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% Change
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Total production (2)
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Oil (MBbls)
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Permian
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14,113
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11,365
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2,748
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24
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%
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Eagle Ford
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9,430
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300
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9,130
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3,043
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%
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Total oil (MBbls)
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23,543
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11,665
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11,878
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102
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%
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Natural gas (MMcf)
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Permian
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32,087
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19,484
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12,603
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65
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%
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Eagle Ford
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8,714
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234
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8,480
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3,624
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%
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Total natural gas (MMcf)
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40,801
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19,718
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21,083
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107
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%
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NGLs (MBbls)
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Permian
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5,390
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93
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5,297
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5,696
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%
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Eagle Ford
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1,460
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42
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1,418
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3,376
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%
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Total NGLs (MBbls)
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6,850
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135
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6,715
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4,974
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%
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Total production (MBoe)
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Permian
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24,851
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14,705
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10,146
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69
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%
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Eagle Ford
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12,342
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381
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11,961
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3,139
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%
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Total barrels of oil equivalent (MBoe)
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37,193
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15,086
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22,107
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147
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%
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Total daily production (Boe/d)
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101,620
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41,331
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60,289
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146
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%
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Oil as % of total daily production
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63
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%
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77
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%
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Benchmark prices(3)
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WTI (per Bbl)
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$39.38
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$56.98
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($17.60)
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(31
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%)
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Henry Hub (per Mcf)
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2.13
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2.56
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(0.43)
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(17
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%)
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Average realized sales price (excluding impact of settled derivatives)
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Oil (per Bbl)
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Permian
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$37.23
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$54.13
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($16.90)
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(31
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%)
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Eagle Ford
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34.49
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59.57
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(25.08)
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(42
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%)
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Total oil (per Bbl)
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36.13
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54.27
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(18.14)
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(33
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%)
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Natural gas (per Mcf)
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Permian
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1.05
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1.84
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(0.79)
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(43
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%)
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Eagle Ford
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2.07
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2.44
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(0.37)
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(15
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%)
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Total natural gas (per Mcf)
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1.27
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1.85
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(0.58)
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(31
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%)
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NGL (per Bbl)
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Permian
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11.91
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16.58
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(4.67)
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(28
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%)
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Eagle Ford
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11.71
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12.69
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(0.98)
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(8
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%)
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Total NGL (per Bbl)
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11.87
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15.37
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(3.50)
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(23
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%)
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Total average realized sales price (per Boe)
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Permian
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25.09
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44.38
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(19.29)
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(43
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%)
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Eagle Ford
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29.20
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49.81
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(20.61)
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(41
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%)
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Total average realized sales price (per Boe)
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$26.45
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$44.52
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($18.07)
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(41
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%)
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Years Ended December 31,
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2020
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2019 (1)
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$ Change
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% Change
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Average realized sales price (including impact of settled derivatives)
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Oil (per Bbl)
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$40.19
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$53.31
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($13.12)
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(25
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%)
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Natural gas (per Mcf)
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1.28
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2.22
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(0.94)
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(42
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%)
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NGLs (per Bbl)
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11.87
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15.37
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(3.50)
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(23
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%)
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Total average realized sales price (per Boe)
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$29.03
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$44.27
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($15.24)
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(34
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%)
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Revenues (in thousands)
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Oil
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Permian
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$525,412
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$615,235
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($89,823)
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(15
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%)
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Eagle Ford
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325,255
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17,872
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307,383
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1,720
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%
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Total oil
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850,667
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633,107
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217,560
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34
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%
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Natural gas
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Permian
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33,815
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35,818
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(2,003)
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(6
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%)
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Eagle Ford
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18,051
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572
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17,479
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3,056
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%
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Total natural gas
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51,866
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36,390
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15,476
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43
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%
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NGLs
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Permian
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64,201
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1,542
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62,659
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4,063
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%
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Eagle Ford
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17,094
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533
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16,561
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3,107
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%
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Total NGLs
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81,295
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2,075
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79,220
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3,818
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%
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Total revenues
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Permian
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623,428
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652,595
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(29,167)
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(4
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%)
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Eagle Ford
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360,400
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18,977
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341,423
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1,799
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%
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Total revenues
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$983,828
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$671,572
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$312,256
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46
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%
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Additional per Boe data
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Lease operating expense
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Permian
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$4.71
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$6.03
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($1.32)
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(22
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%)
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Eagle Ford
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6.25
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8.38
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(2.13)
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(25
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%)
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Total lease operating expense
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$5.22
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$6.09
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($0.87)
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(14
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%)
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Production and ad valorem taxes
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Permian
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$1.59
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$2.84
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($1.25)
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(44
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%)
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Eagle Ford
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1.87
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2.29
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(0.42)
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(18
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%)
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Total production and ad valorem taxes
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$1.68
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|
$2.83
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($1.15)
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(41
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%)
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Gathering, transportation and processing
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|
|
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Permian
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$2.29
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$—
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$2.29
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|
100
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%
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Eagle Ford
|
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1.66
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|
—
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1.66
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100
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%
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Total gathering, transportation and processing
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$2.08
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$—
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$2.08
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100
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%
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(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date.
(2) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, reserve volumes for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas.
(3) Reflects calendar average daily spot market prices.
Revenues
The following table reconciles the changes in oil, natural gas, NGLs, and total revenue for the period presented by reflecting the effect of changes in volume and in the underlying commodity prices.
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Oil
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Natural Gas
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NGLs
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Total
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(In thousands)
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Revenues for the year ended December 31, 2019 (1)(3)
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$633,107
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$36,390
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|
$2,075
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$671,572
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Volume increase (decrease)
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644,776
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38,912
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103,212
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786,900
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Price increase (decrease)
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(427,216)
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(23,436)
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(23,992)
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(474,644)
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Net increase (decrease)
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217,560
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15,476
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|
79,220
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312,256
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Revenues for the year ended December 31, 2020 (2)(3)
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$850,667
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$51,866
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$81,295
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$983,828
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Percent of total revenues
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87
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%
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5
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%
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8
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%
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(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date.
(2) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, reserve volumes for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas.
(3) Excludes sales of oil and gas purchased from third parties and sold to our customers.
Commodity Prices
The prices for oil, natural gas, and NGLs remain extremely volatile primarily due to the underlying supply and demand concerns as a result of COVID-19 as well as the actions taken by OPEC and other countries as described above. This volatility was shown in the price of oil which ranged from a low of -$36.98 per Bbl to $63.27 per Bbl. Prices of oil, natural gas, and NGLs will affect the following aspects of our business:
•our revenues, cash flows and earnings;
•the amount of oil and natural gas that we are economically able to produce;
•our ability to attract capital to finance our operations and cost of the capital;
•the amount we are allowed to borrow under the Credit Facility; and
•the value of our oil and natural gas properties.
Period over Period Variances
The change in absolute value for the year ended December 31, 2020 as compared to the year ended December 31, 2019 can be primarily attributed to the Carrizo Acquisition which closed in December 2019. The Carrizo Acquisition had a material impact to our reported results of operations. In order to provide a more meaningful basis for comparison, we focused our discussion on per unit metrics and only expanded on changes in absolute value where appropriate.
Oil revenue
For the year ended December 31, 2020, oil revenues of $850.7 million increased $217.6 million, or 34%, compared to revenues of $633.1 million for the year ended December 31, 2019. The increase in oil revenue was primarily attributable to a 102% increase in production, partially offset by a 33% decrease in the average realized sales price, which declined to $36.13 per Bbl from $54.27 per Bbl. The increase in production was comprised of 9.5 MMBbls attributable to wells that were acquired in the Carrizo Acquisition and 5.7 MMBbls attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells.
Natural gas revenue
Natural gas revenues increased $15.5 million, or 43%, during the year ended December 31, 2020 to $51.9 million as compared to $36.4 million for the year ended December 31, 2019. The increase primarily relates to an approximate 107% increase in natural gas volumes, partially offset by a 31% decrease in the average price realized, which declined to $1.27 per Mcf from $1.85 per Mcf. The increase in production was comprised of 23.8 Bcf attributable to wells that were acquired in the Carrizo Acquisition and 6.8 Bcf attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells.
NGL revenue
NGL revenues increased $79.2 million during the year ended December 31, 2020 to $81.3 million. The increase was due to certain of our natural gas processing agreements being modified effective January 1, 2020, to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
Operating Expenses
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Years Ended December 31,
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Per
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Per
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Total Change
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Boe Change
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2020
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Boe
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|
2019
|
|
Boe
|
|
$
|
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%
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|
$
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|
%
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|
(In thousands, except per Boe and % amounts)
|
Lease operating expenses
|
|
$194,101
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|
|
$5.22
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|
|
$91,827
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|
|
$6.09
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|
|
$102,274
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|
|
111
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%
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|
($0.87)
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|
|
(14
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%)
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Production and ad valorem taxes
|
|
62,638
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|
1.68
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|
42,651
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|
2.83
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|
19,987
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47
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%
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|
(1.15)
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|
(41
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%)
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Gathering, transportation and processing
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|
77,309
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|
2.08
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|
|
—
|
|
|
—
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|
|
77,309
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|
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100
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%
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|
2.08
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100
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%
|
Depreciation, depletion and amortization
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|
480,631
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|
12.92
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|
|
240,642
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|
15.95
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|
239,989
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100
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%
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|
(3.03)
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|
|
(19
|
%)
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General and administrative
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|
37,187
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|
1.00
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|
|
45,331
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|
3.00
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(8,144)
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(18
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%)
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(2.00)
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(67
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%)
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Impairment of evaluated oil and gas properties
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2,547,241
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68.48
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|
—
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—
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|
|
2,547,241
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|
100
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%
|
|
68.48
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|
100
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%
|
Merger and integration expenses
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|
28,482
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|
|
0.77
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|
|
74,363
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|
|
4.93
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|
|
(45,881)
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|
|
(62
|
%)
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|
(4.16)
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|
|
(84
|
%)
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Lease operating expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.
Lease operating expenses for the year ended December 31, 2020 increased by 111% to $194.1 million compared to $91.8 million for the same period of 2019, primarily due to production volumes increasing 147%. Lease operating expense per Boe for the year ended December 31, 2020 decreased to $5.22 compared to $6.09 for the same period of 2019 primarily due to continuing improvement of managing our field operating costs during the integration of the properties acquired from Carrizo as well as lower repairs and maintenance activities and workover expenses.
Production and valorem taxes. In general, severance taxes are based upon current year commodity prices whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. We benefit from tax credits and exemptions in our various taxing jurisdictions where available and applicable. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.
For the year ended December 31, 2020, production and ad valorem taxes increased 47% to $62.6 million compared to $42.7 million for the same period in 2019, which is primarily related to a 46% increase in total revenues which increased production taxes and the inclusion of the properties from the Carrizo Acquisition in the property valuations for ad valorem taxes. Production and ad valorem taxes as a percentage of total revenues remained consistent for the year ended December 31, 2020 as compared to the year ended December 31, 2019 at 6.4%. Although production taxes as a percentage of total revenues decreased from the year ended December 31, 2019 due to the contribution of the Carrizo Acquisition assets which carried lower effective production tax rates as a result of the impacts of natural gas and NGL marketing deductions and exemptions, this was offset by an increase in ad valorem tax as a percentage of revenue during the year ended December 31, 2020 due to the timing of the property tax valuations compared to the significant decrease in the price of crude oil affecting our revenues during 2020.
Gathering, transportation and processing expenses. Gathering, transportation and processing costs for the year ended December 31, 2020 were $77.3 million. No expense was recognized for gathering, transportation and processing costs during the same period of 2019. The change is due to the assumption of the processing agreements assumed in the Carrizo Acquisition and certain contract modifications effective January 1, 2020. As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a reduction of revenue depending on when control transferred to the purchaser.
Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved oil and gas reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from two to twenty years. The following table sets forth the components of our depreciation, depletion and amortization for the periods indicated:
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|
Years Ended December 31,
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2020
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2019
|
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|
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|
|
|
Amount
|
|
Per Boe
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|
Amount
|
|
Per Boe
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|
|
|
|
|
|
|
|
|
|
(In thousands, except per Boe)
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|
|
|
|
|
|
|
|
DD&A of evaluated oil and gas properties
|
|
$471,074
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|
|
$12.66
|
|
|
$239,679
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|
|
$15.89
|
|
|
|
|
|
|
|
|
|
Depreciation of other property and equipment
|
|
3,548
|
|
|
0.10
|
|
|
18
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Amortization of other assets
|
|
2,686
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|
|
0.07
|
|
|
—
|
|
|
—
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|
|
|
|
|
|
|
|
|
Accretion of asset retirement obligations
|
|
3,323
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|
|
0.09
|
|
|
945
|
|
|
0.06
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|
|
|
|
|
|
|
|
|
DD&A
|
|
$480,631
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|
|
$12.92
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|
|
$240,642
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|
|
$15.95
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|
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|
|
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|
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|
For the year ended December 31, 2020, DD&A increased 100% to $480.6 million from $240.6 million compared to the same period of 2019. The additional DD&A was primarily related to an increase in DD&A of evaluated oil and gas properties, which was primarily attributable to a 147% increase in production, as discussed above, partially offset by lower DD&A rates between the periods. For the year ended December 31, 2020, DD&A per Boe decreased to $12.92 compared to $15.95 for the same period of 2019 primarily as a result of the impairments of evaluated oil and gas properties that were recognized during 2020 as well as the Carrizo Acquisition which contributed to an increase in our proved reserves at a lower relative cost per Boe than our historical DD&A rate.
General and administrative, net of amounts capitalized (“G&A”). G&A for the year ended December 31, 2020 decreased to $37.2 million compared to $45.3 million for the same period of 2019, primarily due to cost saving initiatives and a decrease in the fair value of the cash-settled restricted stock units and cash-settled stock appreciation rights partially offset by increased headcount of the combined companies.
Impairment of evaluated oil and gas properties. We recognized an impairment of evaluated oil and gas properties of $2.5 billion for the year ended December 31, 2020, due primarily to declines in the 12-Month Average Realized Price of crude oil of 31%. There was no impairment of evaluated oil and gas properties for the year ended December 31, 2019. See “Note 5 - Property and Equipment, Net” of the Notes to our Consolidated Financial Statements for further discussion.
Merger and integration expense. For the year ended December 31, 2020, the Company incurred expenses associated with the Carrizo Acquisition of $28.5 million as compared to $74.4 million for the same period of 2019. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the Carrizo Acquisition.
Other Income and Expenses
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|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
$ Change
|
|
% Change
|
|
|
(In thousands, except % amounts)
|
Interest expense
|
|
$182,928
|
|
|
$81,399
|
|
|
$101,529
|
|
|
125
|
%
|
Capitalized interest
|
|
(88,599)
|
|
|
(78,492)
|
|
|
(10,107)
|
|
|
13
|
%
|
Interest expense, net of capitalized amounts
|
|
94,329
|
|
|
2,907
|
|
|
91,422
|
|
|
3,145
|
%
|
(Gain) loss on derivative contracts
|
|
27,773
|
|
|
62,109
|
|
|
(34,336)
|
|
|
(55
|
%)
|
(Gain) loss on extinguishment of debt
|
|
(170,370)
|
|
|
4,881
|
|
|
(175,251)
|
|
|
(3,590
|
%)
|
Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees),
commitment fees and annual agency fees in interest expense. The following table sets forth the components of our interest expense, net of capitalized amounts for the periods indicated:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
Change
|
|
|
(In thousands)
|
Interest expense on Credit Facility
|
|
$45,912
|
|
|
$14,422
|
|
|
$31,490
|
|
Interest expense on Second Lien Notes
|
|
9,188
|
|
|
—
|
|
|
9,188
|
|
Interest expense on Senior Notes
|
|
120,313
|
|
|
64,061
|
|
|
56,252
|
|
Amortization of debt issuance costs, premiums, and discounts
|
|
7,325
|
|
|
2,902
|
|
|
4,423
|
|
Other interest expense
|
|
190
|
|
|
14
|
|
|
176
|
|
Capitalized interest
|
|
(88,599)
|
|
|
(78,492)
|
|
|
(10,107)
|
|
Interest expense, net of capitalized amounts
|
|
$94,329
|
|
|
$2,907
|
|
|
$91,422
|
|
Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2020 increased $91.4 million to $94.3 million compared to $2.9 million for the same period of 2019. The increase is primarily due to debt that was assumed as a result of the Carrizo Acquisition and the issuance of the Second Lien Notes during 2020 partially offset by an increase in capitalized interest as a result of an increase in the balance of unevaluated properties as a result of the Carrizo Acquisition.
(Gain) loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled within the period. The net (gain) loss on derivative contracts for the periods indicated includes the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
Change
|
|
|
(In thousands)
|
(Gain) loss on oil derivatives
|
|
($48,031)
|
|
|
$73,313
|
|
|
($121,344)
|
|
(Gain) loss on natural gas derivatives
|
|
14,883
|
|
|
(8,889)
|
|
|
23,772
|
|
(Gain) loss on NGL derivatives
|
|
2,426
|
|
|
—
|
|
|
2,426
|
|
(Gain) loss on contingent consideration arrangements
|
|
2,976
|
|
|
(2,315)
|
|
|
5,291
|
|
(Gain) loss on September 2020 Warrants liability
|
|
55,519
|
|
|
—
|
|
|
55,519
|
|
(Gain) loss on derivative contracts
|
|
$27,773
|
|
|
$62,109
|
|
|
($34,336)
|
|
See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information.
(Gain) loss on extinguishment of debt. During November 2020, in connection with the exchange of $389.0 million of our Senior Unsecured Notes for the November 2020 Second Lien Notes, we recorded a gain on extinguishment of debt of $170.4 million, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. During December 2019, in connection with the Carrizo Acquisition, we entered into a new credit facility and simultaneously terminated our prior credit facility. As a result of terminating the prior credit facility, we recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the prior credit facility. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
Sales and cost of purchased oil and gas. For the year ended December 31, 2020, we recorded sales of purchased oil and gas of $49.3 million and cost of purchased oil and gas of $51.8 million related to commodities purchased from third parties and sold to our customers. No sales or cost of purchased oil and gas occurred during the same periods of 2019.
Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate, based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.
We recorded income tax expense of $122.1 million for the year ended December 31, 2020 compared to $35.3 million for the same period of 2019. The increase in income tax expense is due to the recording of a valuation allowance during the year ended
December 31, 2020. See “Note 12 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regarding the valuation allowance.
Preferred stock dividends. On July 18, 2019, we redeemed all outstanding shares of Preferred Stock, after which, the Preferred Stock was no longer deemed outstanding and dividends ceased to accrue. As such, we did not make any Preferred Stock dividend payments during the year ended December 31, 2020. Preferred Stock dividends of $4.0 million were paid during the year ended December, 31, 2019. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information.
Loss on redemption of preferred stock. As a result of the redemption of our Preferred Stock mentioned above, we recognized an $8.3 million loss due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value during 2019. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information.
Liquidity and Capital Resources
2021 Capital Budget and Funding Strategy. Our primary uses of capital are for the exploration and development of our oil and natural gas properties. Our 2021 Capital Budget has been established at up to $430.0 million, with approximately 80% directed towards drilling, completion, and equipment expenditures. Our scaled development plan for 2021 will continue to employ our life of field development philosophy and benefit from our balanced capital deployment strategy. The 2021 Capital Budget leverages the structural savings and operational efficiencies achieved during 2020 from shared best practices following the integration of Callon and Carrizo. Approximately 70% of the 2021 Capital Budget is allocated towards development in the Permian with the remaining 30% towards development in the Eagle Ford. As part of our 2021 operated horizontal drilling program, we expect to drill approximately 55 to 65 gross operated wells and complete approximately 90 to 100 gross operated wells.
Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capital expenditures depending on various factors, including, but not limited to, continued depressed commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition of leases with drilling commitments, and other factors. We plan to execute a more moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scale development program while leveraging a robust drilled, but uncompleted backlog to drive capital efficiency.
The following table is a summary of our 2020 capital expenditures (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Year Ended
|
|
March 31, 2020
|
|
June 30, 2020
|
|
September 30, 2020
|
|
December 31, 2020
|
|
December 31, 2020
|
|
(In millions)
|
Operational capital
|
$277.6
|
|
$85.1
|
|
$38.4
|
|
$87.5
|
|
$488.6
|
Capitalized interest
|
24.0
|
|
20.9
|
|
20.7
|
|
23.0
|
|
88.6
|
Capitalized G&A
|
7.4
|
|
8.9
|
|
10.2
|
|
8.9
|
|
35.4
|
Total
|
$309.0
|
|
$114.9
|
|
$69.3
|
|
$119.4
|
|
$612.6
|
(1) Capital expenditures, presented on an accrual basis, includes facilities, equipment, seismic, and land, but excludes asset retirement costs.
We continually evaluate our capital expenditure needs and compare them to our capital resources. Due to the decline in crude oil prices and ongoing uncertainty regarding the oil supply-demand macro environment, we reduced our development plan in order to preserve capital, including the temporary cessation of all drilling and completion activities for most of the second and third quarters of 2020. We reactivated two completion crews, one each in the Eagle Ford and Permian, both of which completed previously drilled multi-well projects during September. Subsequently, one of the two completion crews was released and three drilling rigs resumed operations, two restarting operations in the Permian during September and the third reactivated in the Eagle Ford during October. This reduction in activity resulted in our actual 2020 operational capital expenditures to be approximately 50% of our original operational capital budget for 2020 of $975.0 million.
Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements. In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. During 2020, to help manage our future financing cash outflows and liquidity position, we completed the exchange of $389.0 million of aggregate principal amount of our existing Senior Unsecured Notes
for $216.7 million aggregate principal amount of November 2020 Second Lien Notes and 1.75 million November 2020 Warrants. This exchange resulted in the removal of approximately $172.3 million from the long-term debt balance in our consolidated balance sheets and also reduced future interest payments.
We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us. During 2020, we entered into the ORRI Transaction and sold substantially all of our non-operated assets for combined net proceeds of $165.4 million, which were used to repay borrowings outstanding under the Credit Facility.
Overview of Cash Flow Activities. For the year ended December 31, 2020, cash and cash equivalents increased $6.9 million to $20.2 million compared to $13.3 million at December 31, 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2020
|
|
2019 (1)
|
|
(In thousands)
|
Net cash provided by operating activities
|
$559,775
|
|
|
$476,316
|
|
Net cash used in investing activities
|
(529,883)
|
|
|
(388,389)
|
|
Net cash used in financing activities
|
(22,997)
|
|
|
(90,637)
|
|
Net change in cash and cash equivalents
|
$6,895
|
|
|
($2,710)
|
|
(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date.
Operating activities. Net cash provided by operating activities was $559.8 million and $476.3 million for the years ended December 31, 2020 and 2019, respectively. The increase in operating activities was predominantly attributable to the following:
•An increase in revenue due to higher production volumes, offset by a decrease in realized pricing;
•A decrease in merger and integration expenses;
•An offsetting increase in operating expenses as a result of higher production volumes; and
•Changes related to timing of working capital payments and receipts.
Production, realized prices, and operating expenses are discussed above in Results of Operations. See “Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.
Investing activities. Net cash used in investing activities was $529.9 million and $388.4 million for the years ended December 31, 2020 and 2019, respectively. The increase in investing activities was primarily attributable to the following:
•A decrease in proceeds from sales of assets to $179.5 million during the year ended December 31, 2020, which were primarily associated with the ORRI Transaction and the sale of substantially all of our non-operated assets, compared to proceeds from sales of assets of $294.4 million for the year ended December 31, 2019;
•Partially offset by a $42.3 million decrease in acquisitions; and
•Net cash payments of $40.0 million associated with contingent considerations arrangements acquired in the Carrizo Acquisition that were paid in January 2020.
Financing activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under the Credit Facility, term debt and equity offerings. For the year ended December 31, 2020, net cash used in financing activities was $23.0 million compared to net cash used in financing activities of $90.6 million during 2019. The decrease in net cash used in financing activities was primarily attributable to the following:
•Issuance of the September 2020 Second Lien Notes and September 2020 Warrants for net proceeds of approximately $288.6 million;
•Repayment of approximately $300.0 million on the Credit Facility during 2020;
•Repayment of Carrizo’s credit facility and funding the redemption of preferred stock upon closing the Carrizo Acquisition in 2019; and
•Redemption of Preferred Stock for approximately $73.0 million in 2019.
See “Note 7 – Borrowings”, “Note 10 – Share-Based Compensation”, and “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information regarding our debt and equity transactions.
Credit Facility. On December 20, 2019, upon consummation of the Merger, we entered into the Credit Facility which provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time, and (iii) if the Second Lien
Notes are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering our major producing properties. As of December 31, 2020, the borrowing base and elected commitment amount under the revolving credit facility was $1.6 billion, with borrowings outstanding of $985.0 million at a weighted average interest rate of 2.73%, and letters of credit outstanding of $25.2 million.
Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. Under the Credit Facility, we must maintain the following financial covenants determined as of the last day of the quarter, each as described above: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. We were in compliance with these covenants at December 31, 2020.
The Credit Facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information including details of the first, second, and third amendments to the Credit Facility.
Second Lien Notes. On September 30, 2020, we issued $300.0 million in aggregate principal amount of our September 2020 Second Lien Notes and 7.3 million September 2020 Warrants for aggregate consideration of $294.0 million. The Company used the proceeds, net of issuance costs, of approximately $288.6 million to repay borrowings outstanding under the Credit Facility. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
Senior Unsecured Notes Exchange. On November 13, 2020, we closed on the exchange of $389.0 million of aggregate principal amount of the Senior Unsecured Notes for $216.7 million aggregate principal amount of November 2020 Second Lien Notes at a weighted average exchange ratio of approximately $557 per $1,000 of principal exchanged and approximately 1.75 million November 2020 Warrants. As a result of the exchange, we recognized a gain on extinguishment of debt of $170.4 million in our consolidated statement of operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date. See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for additional information about the exchange.
Even considering the downturn in commodity prices as well as a drop in demand as a result of COVID-19, we expect to have sufficient liquidity to pay interest on our Credit Facility, Second Lien Notes, and Senior Unsecured Notes as well as to fund our development program. Upon a redetermination, if any borrowings in excess of the revised borrowing base were outstanding, we could be forced to immediately repay a portion of the borrowings outstanding under the credit agreement. Additionally, if a low commodity price environment were to persist for an extended period, our ability to remain in compliance with our restrictive financial covenants in our Credit Facility and our indentures could be challenged. If we are unable to remain in compliance with our restrictive financial covenants, we could be subject to lender elections for default resolution.
Hedging. As of February 19, 2021, we had the following outstanding oil, natural gas and NGL derivative contracts:
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For the Full Year of
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For the Full Year of
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Oil contracts (WTI)
|
2021
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|
2022
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Swap contracts
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|
Total volume (Bbls)
|
1,827,000
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|
—
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|
Weighted average price per Bbl
|
$43.54
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|
|
$—
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|
|
Collar contracts
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|
|
|
|
Total volume (Bbls)
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11,202,775
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|
1,355,000
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Weighted average price per Bbl
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|
|
Ceiling (short call)
|
$47.80
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|
|
$60.00
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|
|
Floor (long put)
|
$39.95
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|
|
$45.00
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|
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Short call contracts
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|
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|
|
Total volume (Bbls)
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4,825,300
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(1)
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—
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Weighted average price per Bbl
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$63.62
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|
$—
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Short call swaption contracts
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Total volume (Bbls)
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455,000
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(2)
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1,825,000
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(2)
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Weighted average price per Bbl
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$47.00
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|
|
$52.18
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|
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Oil contracts (ICE Brent)
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Swap contracts
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Total volume (Bbls)
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505,000
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(3)
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—
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Weighted average price per Bbl
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$37.34
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|
$—
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|
|
Collar contracts
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Total volume (Bbls)
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730,000
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|
|
—
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|
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Weighted average price per Bbl
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|
|
Ceiling (short call)
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$50.00
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|
|
$—
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Floor (long put)
|
$45.00
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|
|
$—
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|
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Oil contracts (Midland basis differential)
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|
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Swap contracts
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|
|
Total volume (Bbls)
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3,022,900
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|
|
—
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|
|
Weighted average price per Bbl
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$0.26
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|
|
$—
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Oil contracts (Argus Houston MEH)
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Swap contracts
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Total volume (Bbls)
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450,000
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|
|
—
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|
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Weighted average price per Bbl
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$46.50
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|
|
$—
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|
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Collar contracts
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Total volume (Bbls)
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409,500
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|
|
—
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|
|
Weighted average price per Bbl
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|
|
|
|
Ceiling (short call)
|
$47.00
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|
|
$—
|
|
|
Floor (long put)
|
$41.00
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|
|
$—
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|
|
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
(2) The short call swaption contracts have exercise expiration dates as follows: 455,000 Bbls expire on March 31, 2021 and 1,825,000 Bbls expire on December 31, 2021.
(3) In January 2021, we paid approximately $3.1 million to terminate 184,000 Bbls of ICE Brent swaps. Additionally, in February 2021, we executed offsetting ICE Brent swaps on 159,300 Bbls, resulting in a locked-in loss of approximately $2.9 million which we will pay as the applicable contracts settle.
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For the Full Year of
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For the Full Year of
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Natural gas contracts (Henry Hub)
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2021
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|
2022
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Swap contracts
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|
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Total volume (MMBtu)
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11,123,000
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|
|
—
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Weighted average price per MMBtu
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$2.60
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|
$—
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|
Collar contracts (three-way collars)
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Total volume (MMBtu)
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1,350,000
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|
|
—
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|
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Weighted average price per MMBtu
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|
|
|
|
Ceiling (short call)
|
$2.70
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|
|
$—
|
|
|
Floor (long put)
|
$2.42
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|
|
$—
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|
|
Floor (short put)
|
$2.00
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|
|
$—
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|
|
Collar contracts (two-way collars)
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|
|
|
|
Total volume (MMBtu)
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9,550,000
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|
|
1,800,000
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|
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Weighted average price per MMBtu
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|
|
|
|
Ceiling (short call)
|
$3.04
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|
|
$3.88
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|
|
Floor (long put)
|
$2.59
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|
|
$2.78
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|
|
Short call contracts
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|
|
|
|
Total volume (MMBtu)
|
7,300,000
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|
(1)
|
—
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|
|
Weighted average price per MMBtu
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$3.09
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|
|
$—
|
|
|
|
|
|
|
|
Natural gas contracts (Waha basis differential)
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|
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Swap contracts
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|
|
|
|
Total volume (MMBtu)
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16,425,000
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|
|
—
|
|
|
Weighted average price per MMBtu
|
($0.42)
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|
|
$—
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|
|
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
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|
|
|
|
|
|
|
|
|
|
|
For the Full Year of
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|
|
|
NGL contracts (OPIS Mont Belvieu Purity Ethane)
|
2021
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|
|
|
Swap contracts
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|
|
|
|
Total volume (Bbls)
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1,825,000
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|
|
|
|
Weighted average price per Bbl
|
$7.62
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|
|
|
|
Preferred Stock. On June 18, 2019, we announced we had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). We recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. We paid $4.0 million for Preferred Stock dividends for the year ended December 31, 2019. See “Note 11 - Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional discussion.
Contractual Obligations
The following table includes our current contractual obligations and purchase commitments as of December 31, 2020:
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|
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Payments due by Period
|
|
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< 1 Year
|
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Years 2 - 3
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Years 4 - 5
|
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> 5 Years
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Total
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|
|
(In thousands)
|
Credit Facility (1)
|
|
$—
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|
|
$—
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|
|
$985,000
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|
|
$—
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|
|
$985,000
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|
9.00% Second Lien Senior Secured Notes (2)
|
|
—
|
|
|
—
|
|
|
516,659
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|
|
—
|
|
|
516,659
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|
6.25% Senior Notes (2)
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|
—
|
|
|
542,720
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|
|
—
|
|
|
—
|
|
|
542,720
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|
6.125% Senior Notes (2)
|
|
—
|
|
|
—
|
|
|
460,241
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|
|
—
|
|
|
460,241
|
|
8.25% Senior Notes (2)
|
|
—
|
|
|
—
|
|
|
187,238
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|
|
—
|
|
|
187,238
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|
6.375% Senior Notes (2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
320,783
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|
|
320,783
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|
Interest expense and other fees related to debt commitments (3)
|
|
174,387
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|
|
331,815
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|
|
198,714
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|
|
20,450
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|
|
725,366
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|
Drilling rig leases (4)
|
|
4,317
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|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,317
|
|
Operating leases (5)
|
|
10,601
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|
|
10,454
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|
|
8,894
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|
|
14,139
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|
|
44,088
|
|
Delivery commitments (6)
|
|
12,401
|
|
|
22,533
|
|
|
24,868
|
|
|
39,291
|
|
|
99,093
|
|
Produced water disposal commitments (7)
|
|
21,355
|
|
|
29,095
|
|
|
12,242
|
|
|
741
|
|
|
63,433
|
|
Asset retirement obligations (8)
|
|
1,881
|
|
|
587
|
|
|
6,827
|
|
|
49,795
|
|
|
59,090
|
|
Total contractual obligations
|
|
$224,942
|
|
|
$937,204
|
|
|
$2,400,683
|
|
|
$445,199
|
|
|
$4,008,028
|
|
(1)The Credit Facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
(2)Includes the outstanding principal amount only.
(3)Includes estimated cash payments on the 9.00% Second Lien Senior Secured Notes, 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as of December 31, 2020, at the applicable commitment fee rate.
(4)Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2020. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. In January 2021, we extended one of our drilling rig contracts for a term of one year. The gross contractual obligation for this extended drilling rig contract is approximately $5.5 million and is not included in the table above as it was entered into subsequent to December 31, 2020. See “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information related to our drilling rig leases.
(5)Operating leases primarily consist of contracts for office space. See “Note 13 – Leases” of the Notes to our Consolidated Financial Statements for additional information.
(6)Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas.
(7)Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.
(8)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See “Note 14 – Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information.
Other commitments
The following table includes our current oil sales contracts and firm transportation agreements as of December 31, 2020:
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|
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|
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|
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Type of Commitment (1)
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Region
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Execution Date
|
|
Start Date
|
|
End Date
|
|
Committed
Volumes (Bbls/d)
|
Oil sales contract
|
|
Eagle Ford
|
|
November 2020
|
|
January 2021
|
|
December 2021
|
|
10,000
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Oil sales contract
|
|
Permian
|
|
August 2020
|
|
August 2020
|
|
December 2021
|
|
7,500
|
Oil sales contract
|
|
Permian
|
|
July 2019
|
|
August 2021
|
|
July 2026
|
|
5,000
|
Oil sales contract
|
|
Permian
|
|
June 2019
|
|
January 2020
|
|
December 2024
|
|
10,000
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Oil sales contract
|
|
Permian
|
|
August 2018
|
|
April 2020
|
|
March 2022
|
|
15,000
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Firm transportation agreement (2)(3)
|
|
Permian
|
|
June 2019
|
|
August 2020
|
|
July 2030
|
|
10,000
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Firm transportation agreement (2)
|
|
Permian
|
|
August 2018
|
|
April 2020
|
|
March 2027
|
|
15,000
|
(1)For each of the commitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities.
(2)Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast.
(3)The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively.
Summary of Critical Accounting Policies
The following summarizes our critical accounting policies. See a complete list of significant accounting policies in “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements.
Use of estimates
The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of evaluated oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.
Oil and natural gas properties
Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred.
Proceeds from the sale or disposition of evaluated and unevaluated oil and gas properties are accounted for as a reduction of evaluated oil and gas property costs, unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves in which case a gain or loss is recognized. For the years ended December 31, 2020, 2019, and 2018, we did not have any sales of oil and gas properties that significantly altered such relationship.
Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or we determine that these costs have been impaired. We assess properties on an individual basis or as a group and consider the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, we analyzed our unevaluated leasehold giving consideration to our updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result, we impaired $229.6 million unevaluated leasehold costs and transferred these costs to evaluated properties during the year ended December 31, 2020.
Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.
At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.
The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the quarter (the “12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as we elected not to meet the criteria to qualify for hedge accounting treatment.
Primarily as a result of the significant reduction in the 12-Month Average Realized Price of oil, we recognized impairments of evaluated oil and gas properties of $2.5 billion for the year December 31, 2020. We did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018. Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2020, 2019, and 2018 are summarized in the table below:
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Years Ended December 31,
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2020
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2019
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2018
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Impairment of evaluated oil and natural gas properties (In thousands)
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$2,547,241
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$—
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$—
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Beginning of period 12-Month Average Realized Price ($/Bbl)
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$53.90
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$58.40
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$49.48
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End of period 12-Month Average Realized Price ($/Bbl)
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$37.44
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$53.90
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$58.40
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Percent increase (decrease) in 12-Month Average Realized Price
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(31
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%)
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(8
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%)
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18
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%
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The decrease in the 12-Month Average Realized Price as of December 31, 2020 reduced our proved oil and gas reserve volumes by approximately 26.2 MMBoe. This reduction was primarily attributable to proved developed reserves of producing wells and proved undeveloped reserves with shorter economic lives. Volumes associated with locations of proved undeveloped reserves that were no longer economic and removed from proved reserves as a result of the decrease in the 12-Month Average Realized Price as of December 31, 2020 were less than 1.0 MMBoe.
Our current forecast for the first quarter of 2021 includes the following:
•Estimated 12-Month Average Realized Price based on the first calendar day of each month oil and gas prices available for the 11 months ended February 1, 2021 and an estimate for the twelfth month based on a quoted forward price;
•Estimated range of the first quarter of 2021 cost center ceiling, at the high end, that would exceed the net book value of oil and gas properties, resulting in no impairment in the carrying value of evaluated oil and gas properties, and at the low end, would result in an impairment in the carrying value of evaluated oil and gas properties of $100.0 million;
•No proved undeveloped reserves that would no longer be economic and would be removed from proved reserves as of March 31, 2021; and
•Assumes that all other inputs and assumptions are as of December 31, 2020, other than the price of crude oil, natural gas, and NGLs, and remain unchanged.
Drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to December 31, 2020 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling described above. Further impairments in subsequent quarters may occur if the trailing
12-month commodity prices continue to be lower than the comparable trailing 12-month commodity prices applicable to 2020. Based on the current outlook for future commodity prices, we do not believe that those prices, if realized, would have a significant adverse impact on our proved oil and gas reserves volumes.
In addition, the process of estimating proved oil and gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.”
The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2020 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of December 31, 2020 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2020 that may require revisions to estimates of proved reserves. See also Part I, “Item 1A. Risk Factors—If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.”
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12-Month Average
Realized Prices
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Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes
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Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
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Full Cost Pool Scenarios
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Crude Oil
($/Bbl)
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Natural Gas
($/Mcf)
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(In millions)
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(In millions)
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December 31, 2020 Actual
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$37.44
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$1.02
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$—
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Crude Oil and Natural Gas Price Sensitivity
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Crude Oil and Natural Gas +10%
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$41.40
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$1.21
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$640
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$640
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Crude Oil and Natural Gas -10%
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$33.49
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$0.81
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($632)
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($632)
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Crude Oil Price Sensitivity
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Crude Oil +10%
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$41.40
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$1.02
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$602
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$602
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Crude Oil -10%
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$33.49
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$1.02
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($588)
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($588)
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Natural Gas Price Sensitivity
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Natural Gas +10%
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$37.44
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$1.21
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$48
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$48
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Natural Gas -10%
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$37.44
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$0.81
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($50)
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($50)
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Asset retirement obligations
We record an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligations is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information.
Estimating the future plugging and abandonment costs of wells and related facilities requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Derivative instruments
We use commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of our forecasted sales of production and achieve a more predictable level of cash flow. We do not use these instruments for speculative or trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price.
Our commodity derivative instruments, as well as our contingent consideration arrangements, are carried at their fair value in the consolidated balance sheets with all gains and losses as a result of changes in the fair value recognized in the consolidated statements of operations in the period in which the changes occur. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding our derivatives instruments and their fair values, see “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk”.
Income taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards.
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2020, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the end of the year, which limits the ability to consider other subjective evidence such as our potential for future growth. Beginning in the second quarter of 2020 and continuing through the end of 2020, based on the evaluation of the evidence available, we concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, we recorded a valuation allowance of $639.2 million, reducing the net deferred tax assets as of December 31, 2020 to zero.
We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. See “Note 12 - Income Taxes” of the Notes to our Consolidated Financial Statements for additional discussion.
Our ability to utilize our federal net operating losses (“NOLs”) to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Callon. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of Callon multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. Due to the issuance of common stock associated with the Carrizo Acquisition, we incurred a cumulative ownership change and as such, our NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382.
Recently Adopted and Recently Issued Accounting Pronouncements
See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2020.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments.
Commodity price risk
Our revenues are derived from the sale of our oil, natural gas, and NGL production. The prices for oil, natural gas, and NGLs remain extremely volatile primarily due to the underlying supply and demand concerns as a result of COVID-19 as well as the actions taken
by OPEC and other countries as described above. This volatility was shown in the price of oil which ranged from a low of -$36.98 per Bbl to $63.27 per Bbl.
The following table sets forth oil, natural gas and NGL revenues for the year ended December 31, 2020 as well as the impact on the oil, natural gas and NGL revenues assuming a 10% increase or decrease in our average realized sales prices for oil, natural gas and NGLs, excluding the impact of commodity derivative settlements:
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Year Ended December 31, 2020
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Oil
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Natural Gas
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NGLs
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Total
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(In thousands)
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Revenues
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$850,667
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$51,866
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$81,295
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$983,828
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Impact of a 10% fluctuation in average realized prices
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$85,067
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$5,187
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$8,129
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$98,383
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From time to time, we enter into derivative financial instruments to manage oil, natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes we hedge through use of our derivative instruments varies from period to period. Generally, our objective is to hedge approximately 60% of our anticipated internally forecasted production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.
As of December 31, 2020, for the full year of 2021, we had 14,547,575 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. We also had 3,022,900 Bbls of WTI Midland-Cushing oil basis hedges. Additionally, for the full year of 2021, we had 22,023,000 MMBtus of fixed price NYMEX natural gas hedges and 16,425,000 MMBtus of Waha natural gas basis hedges. See “Note 8 - Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for a description of our outstanding derivative contracts as of December 31, 2020.
We may utilize fixed price swaps, which reduce our exposure to decreases in commodity prices, but limits the benefit we might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.
We also may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to us, and if the price rises above the ceiling, the counterparty receives the difference from us. Additionally, we may sell put options at a price lower than the floor price in conjunction with a collar (three-way collar) and use the proceeds to increase either/both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), our net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.
We may purchase put options, which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to us.
We enter into these various agreements from time to time to reduce the effects of volatile oil, natural gas and NGL prices and do not enter into derivative transactions for speculative or trading purposes. Presently, none of our derivative positions are designated as hedges for accounting purposes.
Interest rate risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2020, we had $985.0 million outstanding under the Credit Facility with a weighted average interest rate of 2.73%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $9.9 million based on the balance outstanding at December 31, 2020. See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for more information on our Credit Facility.
Counterparty and customer credit risk
Our principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.
We market our oil, natural gas and NGL production to energy marketing companies and are subject to credit risk due to the concentration of our oil, natural gas and NGL receivables with several significant customers. For the year ended December 31, 2020, two purchasers accounted for more than 10% of our revenue: Shell Trading Company (31%) and Valero Energy (23%). The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. We are generally paid by our purchasers within 30 to 90 days after the month of production and currently do not believe that we have
a risk of not collecting. At December 31, 2020, our total receivables from the sale of our oil, natural gas and NGL production were approximately $100.3 million.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. The allowance for credit losses related to our joint interest receivables is immaterial. At December 31, 2020, our joint interest receivables were approximately $11.5 million.
Our oil, natural gas and NGL commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. All of the counterparties of our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At December 31, 2020, we had a net commodity derivative liability position of $96.1 million.
ITEM 8. Financial Statements and Supplementary Data
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Page
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Reports of Independent Registered Public Accounting Firm
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|
Consolidated Balance Sheets as of December 31, 2020 and 2019
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Consolidated Statements of Operations for the Years Ended December 31, 2020, 2019 and 2018
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Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2020, 2019 and 2018
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Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018
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|
Notes to Consolidated Financial Statements
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|
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Callon Petroleum Company
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements 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.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 25, 2021 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves
As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion expense and assess its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment assessment. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future net revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense and potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
•We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment.
•We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:
◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;
◦Tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs;
◦Evaluated the method used to determine the future capital costs and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells;
◦Tested the working and net revenue interests used in the reserve report by inspecting land and division order records;
◦Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and
◦Applied analytical procedures to the reserve report forecasted production by comparing to historical actual results, and to the prior year reserve report.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2016.
Houston, Texas
February 25, 2021
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Callon Petroleum Company
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 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 the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2020, and our report dated February 25, 2021 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible 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 (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
/s/ GRANT THORNTON LLP
Houston, Texas
February 25, 2021
Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except par and share data)
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December 31,
|
|
2020
|
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2019
|
ASSETS
|
|
|
|
Current assets:
|
|
|
|
Cash and cash equivalents
|
$20,236
|
|
$13,341
|
Accounts receivable, net
|
133,109
|
|
|
209,463
|
|
Fair value of derivatives
|
921
|
|
|
26,056
|
|
Other current assets
|
24,103
|
|
|
19,814
|
|
Total current assets
|
178,369
|
|
|
268,674
|
|
Oil and natural gas properties, full cost accounting method:
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|
|
|
Evaluated properties, net
|
2,355,710
|
|
|
4,682,994
|
|
Unevaluated properties
|
1,733,250
|
|
|
1,986,124
|
|
Total oil and natural gas properties, net
|
4,088,960
|
|
|
6,669,118
|
|
Operating lease right-of-use assets
|
22,526
|
|
|
63,908
|
|
Other property and equipment, net
|
31,640
|
|
|
35,253
|
|
Deferred tax asset
|
—
|
|
|
115,720
|
|
Deferred financing costs
|
23,643
|
|
|
22,233
|
|
|
|
|
|
Other assets, net
|
17,730
|
|
|
19,932
|
|
Total assets
|
$4,362,868
|
|
$7,194,838
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
Current liabilities:
|
|
|
|
Accounts payable and accrued liabilities
|
$345,365
|
|
$490,442
|
Operating lease liabilities
|
13,175
|
|
|
42,858
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of derivatives
|
97,060
|
|
|
71,197
|
|
Other current liabilities
|
41,508
|
|
|
47,750
|
|
Total current liabilities
|
497,108
|
|
|
652,247
|
|
Long-term debt
|
2,969,264
|
|
|
3,186,109
|
|
Operating lease liabilities
|
27,576
|
|
|
37,088
|
|
Asset retirement obligations
|
57,209
|
|
|
48,860
|
|
|
|
|
|
|
|
|
|
Fair value of derivatives
|
88,046
|
|
|
32,695
|
|
Other long-term liabilities
|
12,663
|
|
|
14,531
|
|
Total liabilities
|
3,651,866
|
|
|
3,971,530
|
|
Commitments and contingencies
|
|
|
|
Stockholders’ equity:
|
|
|
|
Common stock, $0.01 par value, 52,500,000 shares authorized; 39,758,817 and
39,659,001 shares outstanding, respectively (1)
|
398
|
|
|
3,966
|
|
Capital in excess of par
|
3,222,959
|
|
|
3,198,076
|
|
Retained earnings (Accumulated deficit)
|
(2,512,355)
|
|
|
21,266
|
|
Total stockholders’ equity
|
711,002
|
|
|
3,223,308
|
|
Total liabilities and stockholders’ equity
|
$4,362,868
|
|
$7,194,838
|
(1) All share amounts (except par value) have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Operating Revenues:
|
|
|
|
|
|
Oil
|
$850,667
|
|
|
$633,107
|
|
|
$530,898
|
|
Natural gas
|
51,866
|
|
|
36,390
|
|
|
56,726
|
|
Natural gas liquids
|
81,295
|
|
|
2,075
|
|
|
—
|
|
Sales of purchased oil and gas
|
49,319
|
|
|
—
|
|
|
—
|
|
Total operating revenues
|
1,033,147
|
|
|
671,572
|
|
|
587,624
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
Lease operating
|
194,101
|
|
|
91,827
|
|
|
69,180
|
|
Production and ad valorem taxes
|
62,638
|
|
|
42,651
|
|
|
35,755
|
|
Gathering, transportation and processing
|
77,309
|
|
|
—
|
|
|
—
|
|
Cost of purchased oil and gas
|
51,766
|
|
|
—
|
|
|
—
|
|
Depreciation, depletion and amortization
|
480,631
|
|
|
240,642
|
|
|
182,783
|
|
General and administrative
|
37,187
|
|
|
45,331
|
|
|
35,293
|
|
Impairment of evaluated oil and gas properties
|
2,547,241
|
|
|
—
|
|
|
—
|
|
Merger and integration expenses
|
28,482
|
|
|
74,363
|
|
|
—
|
|
Other operating
|
10,644
|
|
|
4,100
|
|
|
5,083
|
|
Total operating expenses
|
3,489,999
|
|
|
498,914
|
|
|
328,094
|
|
Income (Loss) From Operations
|
(2,456,852)
|
|
|
172,658
|
|
|
259,530
|
|
|
|
|
|
|
|
Other (Income) Expenses:
|
|
|
|
|
|
Interest expense, net of capitalized amounts
|
94,329
|
|
|
2,907
|
|
|
2,500
|
|
(Gain) loss on derivative contracts
|
27,773
|
|
|
62,109
|
|
|
(48,544)
|
|
(Gain) loss on extinguishment of debt
|
(170,370)
|
|
|
4,881
|
|
|
—
|
|
Other (income) expense
|
2,983
|
|
|
(468)
|
|
|
(2,896)
|
|
Total other (income) expense
|
(45,285)
|
|
|
69,429
|
|
|
(48,940)
|
|
|
|
|
|
|
|
Income (Loss) Before Income Taxes
|
(2,411,567)
|
|
|
103,229
|
|
|
308,470
|
|
Income tax expense
|
(122,054)
|
|
|
(35,301)
|
|
|
(8,110)
|
|
Net Income (Loss)
|
($2,533,621)
|
|
|
$67,928
|
|
|
$300,360
|
|
Preferred stock dividends
|
—
|
|
|
(3,997)
|
|
|
(7,295)
|
|
Loss on redemption of preferred stock
|
—
|
|
|
(8,304)
|
|
|
—
|
|
Income (Loss) Available to Common Stockholders
|
($2,533,621)
|
|
|
$55,627
|
|
|
$293,065
|
|
|
|
|
|
|
|
Income (Loss) Available to Common Stockholders
Per Common Share (1):
|
|
|
|
|
|
Basic
|
($63.79)
|
|
|
$2.39
|
|
|
$13.50
|
|
Diluted
|
($63.79)
|
|
|
$2.38
|
|
|
$13.46
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding (1):
|
|
|
|
|
|
Basic
|
39,718
|
|
|
23,313
|
|
|
21,703
|
|
Diluted
|
39,718
|
|
|
23,340
|
|
|
21,773
|
|
(1) All share and per share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(In thousands, except share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
|
|
|
|
Preferred
|
|
Common
|
|
Capital in
|
|
Earnings
|
|
Total
|
|
Stock
|
|
Stock
|
|
Excess
|
|
(Accumulated
|
|
Stockholders'
|
|
Shares
|
|
$
|
|
Shares (1)
|
|
$
|
|
of Par
|
|
Deficit)
|
|
Equity
|
Balance at 12/31/2017
|
1,459
|
|
|
$15
|
|
20,183
|
|
|
$2,018
|
|
$2,181,359
|
|
($327,426)
|
|
|
$1,855,966
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
300,360
|
|
|
300,360
|
|
Shares issued pursuant to employee benefit plans
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
533
|
|
|
—
|
|
|
533
|
|
Restricted stock
|
—
|
|
|
—
|
|
|
40
|
|
|
5
|
|
|
7,651
|
|
|
—
|
|
|
7,656
|
|
Common stock issued
|
—
|
|
|
—
|
|
|
2,530
|
|
|
253
|
|
|
287,735
|
|
|
—
|
|
|
287,988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock dividend
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,295)
|
|
|
(7,295)
|
|
Balance at 12/31/2018
|
1,459
|
|
|
$15
|
|
22,757
|
|
|
$2,276
|
|
$2,477,278
|
|
($34,361)
|
|
|
$2,445,208
|
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
67,928
|
|
|
67,928
|
|
Shares issued pursuant to employee benefit plans
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
154
|
|
|
—
|
|
|
154
|
|
Restricted stock
|
—
|
|
|
—
|
|
|
79
|
|
|
8
|
|
|
11,622
|
|
|
—
|
|
|
11,630
|
|
Common stock issued for Carrizo Acquisition
|
—
|
|
|
—
|
|
|
16,821
|
|
|
1,682
|
|
|
763,691
|
|
|
—
|
|
|
765,373
|
|
Common stock warrants reissued in conjunction with Carrizo Acquisition
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,029
|
|
|
—
|
|
|
10,029
|
|
Preferred stock dividend
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,997)
|
|
|
(3,997)
|
|
Preferred stock redemption
|
(1,459)
|
|
|
(15)
|
|
|
—
|
|
|
—
|
|
|
(64,698)
|
|
|
—
|
|
|
(64,713)
|
|
Loss on redemption of preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,304)
|
|
|
(8,304)
|
|
Balance at 12/31/2019
|
—
|
|
|
$—
|
|
39,659
|
|
|
$3,966
|
|
$3,198,076
|
|
$21,266
|
|
|
$3,223,308
|
Net loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,533,621)
|
|
|
(2,533,621)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock
|
—
|
|
|
—
|
|
|
100
|
|
|
10
|
|
|
12,213
|
|
|
—
|
|
|
12,223
|
|
Reverse stock split
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,578)
|
|
|
3,578
|
|
|
—
|
|
|
—
|
|
Issuance of common stock warrants
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,109
|
|
|
—
|
|
|
9,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17)
|
|
|
—
|
|
|
(17)
|
|
Balance at 12/31/2020
|
—
|
|
|
$—
|
|
|
39,759
|
|
|
$398
|
|
$3,222,959
|
|
($2,512,355)
|
|
|
$711,002
|
(1) All share amounts have been retroactively adjusted for the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Cash flows from operating activities:
|
|
|
|
|
|
Net income (loss)
|
($2,533,621)
|
|
|
$67,928
|
|
$300,360
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
480,631
|
|
|
245,936
|
|
|
185,605
|
|
Impairment of evaluated oil and gas properties
|
2,547,241
|
|
|
—
|
|
|
—
|
|
Amortization of non-cash debt related items
|
3,901
|
|
|
2,907
|
|
|
2,483
|
|
Deferred income tax expense
|
118,607
|
|
|
35,301
|
|
|
8,110
|
|
(Gain) loss on derivative contracts
|
27,773
|
|
|
62,109
|
|
|
(48,544)
|
|
Cash received (paid) for commodity derivative settlements, net
|
98,870
|
|
|
(3,789)
|
|
|
(27,272)
|
|
|
|
|
|
|
|
(Gain) loss on early extinguishment of debt
|
(170,370)
|
|
|
4,881
|
|
|
—
|
|
Non-cash expense related to equity share-based awards
|
6,773
|
|
|
9,767
|
|
|
6,289
|
|
Change in the fair value of liability share-based awards
|
(4,110)
|
|
|
1,624
|
|
|
375
|
|
|
|
|
|
|
|
Payments for cash-settled restricted stock unit awards
|
(770)
|
|
|
(1,425)
|
|
|
(4,990)
|
|
Other, net
|
7,857
|
|
|
(90)
|
|
|
(144)
|
|
Changes in current assets and liabilities:
|
|
|
|
|
|
Accounts receivable
|
75,770
|
|
|
(35,071)
|
|
|
(17,351)
|
|
Other current assets
|
(6,550)
|
|
|
(4,166)
|
|
|
(7,601)
|
|
Accounts payable and accrued liabilities
|
(92,227)
|
|
|
82,290
|
|
|
72,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
—
|
|
|
8,114
|
|
|
(2,508)
|
|
Net cash provided by operating activities
|
559,775
|
|
|
476,316
|
|
|
467,654
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Capital expenditures
|
(677,154)
|
|
|
(640,540)
|
|
|
(611,173)
|
|
Acquisitions
|
—
|
|
|
(42,266)
|
|
|
(718,793)
|
|
|
|
|
|
|
|
Proceeds from sales of assets
|
178,970
|
|
|
294,417
|
|
|
9,009
|
|
Cash paid for settlements of contingent consideration arrangements, net
|
(40,000)
|
|
|
—
|
|
|
—
|
|
Other, net
|
8,301
|
|
|
—
|
|
|
(3,100)
|
|
Net cash used in investing activities
|
(529,883)
|
|
|
(388,389)
|
|
|
(1,324,057)
|
|
Cash flows from financing activities:
|
|
|
|
|
|
Borrowings on Credit Facility
|
5,353,000
|
|
|
2,455,900
|
|
|
500,000
|
|
Payments on Credit Facility
|
(5,653,000)
|
|
|
(895,500)
|
|
|
(325,000)
|
|
Payment to terminate Prior Credit Facility
|
—
|
|
|
(475,400)
|
|
|
—
|
|
Repayment of Carrizo’s senior secured revolving credit facility
|
—
|
|
|
(853,549)
|
|
|
—
|
|
Repayment of Carrizo’s preferred stock
|
—
|
|
|
(220,399)
|
|
|
—
|
|
Issuance of 9.00% Second Lien Senior Secured Notes due 2025
|
300,000
|
|
|
—
|
|
|
—
|
|
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025
|
(35,270)
|
|
|
—
|
|
|
—
|
|
Issuance of September 2020 Warrants
|
23,909
|
|
|
—
|
|
|
—
|
|
Issuance of 6.375% Senior Notes due 2026
|
—
|
|
|
—
|
|
|
400,000
|
|
Issuance of common stock
|
—
|
|
|
—
|
|
|
287,988
|
|
Payment of preferred stock dividends
|
—
|
|
|
(3,997)
|
|
|
(7,295)
|
|
Payment of deferred financing and debt exchange costs
|
(10,811)
|
|
|
(22,480)
|
|
|
(9,430)
|
|
Tax withholdings related to restricted stock units
|
(509)
|
|
|
(2,195)
|
|
|
(1,804)
|
|
Redemption of preferred stock
|
—
|
|
|
(73,017)
|
|
|
—
|
|
Other, net
|
(316)
|
|
|
—
|
|
|
—
|
|
Net cash provided by (used in) financing activities
|
(22,997)
|
|
|
(90,637)
|
|
|
844,459
|
|
Net change in cash and cash equivalents
|
6,895
|
|
|
(2,710)
|
|
|
(11,944)
|
|
Balance, beginning of period
|
13,341
|
|
|
16,051
|
|
|
27,995
|
|
Balance, end of period
|
$20,236
|
|
$13,341
|
|
$16,051
|
The accompanying notes are an integral part of these consolidated financial statements.
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
|
|
1.
|
|
11.
|
Stockholders’ Equity
|
2.
|
|
12.
|
|
3.
|
Revenue Recognition
|
13.
|
|
4.
|
|
14.
|
|
5.
|
Property and Equipment, Net
|
15.
|
|
6.
|
|
16.
|
Accounts Payable and Accrued Liabilities
|
7.
|
|
17.
|
Commitments and Contingencies
|
8.
|
|
18.
|
Subsequent Events (Unaudited)
|
9.
|
|
19.
|
|
10.
|
|
20.
|
|
Note 1 – Description of Business
Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
Callon’s focus is on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas, as well as the Eagle Ford, which the Company entered into through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”) in late 2019. The Company’s primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow generating business in the Eagle Ford.
Note 2 – Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of evaluated oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, fair value of second lien notes upon issuance, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
Accounts Receivable, Net
Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for credit losses and bad debt expense was immaterial for all periods presented.
Concentration of Credit Risk and Major Customers
The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
Shell Trading Company
|
|
31%
|
|
10%
|
|
*
|
Valero Energy
|
|
23%
|
|
*
|
|
*
|
Rio Energy International, Inc.
|
|
*
|
|
26%
|
|
28%
|
Enterprise Crude Oil, LLC
|
|
*
|
|
19%
|
|
14%
|
Plains Marketing, L.P.
|
|
*
|
|
15%
|
|
21%
|
* - Less than 10% for the applicable year.
The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company, which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty.
Oil and Natural Gas Properties
The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred.
Proceeds from the sale or disposition of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2020, 2019 and 2018, the Company did not have any sales of oil and gas properties that significantly altered such relationship.
From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.
Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or the Company determines that these costs have been impaired. The Company assesses
properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result, the Company impaired $229.6 million unevaluated leasehold costs and transferred these costs to evaluated properties during the year ended December 31, 2020.
Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unevaluated properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.
Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.
The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. Primarily as a result of the 31% decrease in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $2.5 billion for the year December 31, 2020. The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018.
Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years.
Deferred Financing Costs
Deferred financing costs associated with the Company’s senior notes and second lien notes are classified as a reduction of the related senior notes or second lien notes carrying value on the consolidated balance sheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility.
Asset Retirement Obligations
The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” for additional information.
Derivative Instruments
The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative or trading purposes.
The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets.
The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion.
Revenue Recognition
The Company recognizes revenues from the sales of oil, natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. See “Note 3 - Revenue Recognition” for further discussion.
Income Taxes
Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. See “Note 12 - Income Taxes” for further discussion of the deferred tax asset valuation allowance.
Share-Based Compensation
The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 - Share-Based Compensation” for further details of the awards discussed below.
RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years).
Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value, which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs will expire between one and six years, depending on the date of grant.
Supplemental Cash Flow Information
The following table sets forth supplemental cash flow information for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
Interest paid, net of capitalized amounts
|
|
$91,269
|
|
|
$—
|
|
|
$—
|
|
Income taxes paid (1)
|
|
—
|
|
|
—
|
|
|
—
|
|
Cash paid for amounts included in the measurement of lease liabilities:
|
|
|
|
|
|
|
Operating cash flows from operating leases
|
|
$44,314
|
|
|
$3,414
|
|
|
$—
|
|
Investing cash flows from operating leases
|
|
24,234
|
|
|
32,529
|
|
|
—
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
Change in accrued capital expenditures
|
|
($64,465)
|
|
|
($31,475)
|
|
|
($52,757)
|
|
Change in asset retirement costs
|
|
8,605
|
|
|
13,559
|
|
|
8,730
|
|
Contingent consideration arrangement
|
|
—
|
|
|
8,512
|
|
|
—
|
|
ROU assets obtained in exchange for lease liabilities:
|
|
|
|
|
|
|
Operating leases
|
|
$8,070
|
|
|
$66,914
|
|
|
$—
|
|
Financing leases
|
|
—
|
|
|
2,197
|
|
|
—
|
|
(1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2020.
Earnings per Share
The Company’s basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a loss attributable to common shareholders per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 6 - Earnings Per Share” for further discussion.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, development, and production of crude oil, natural gas, and NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States.
Recently Adopted Accounting Standards
Credit Losses. In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 did not have a material impact to the Company’s consolidated financial statements or disclosures.
Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”).
Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related
disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.
Upon adoption, the Company implemented policy elections and practical expedients which include the following:
•package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance
•excluding ROU assets and lease liabilities for leases with terms that are less than one year;
•combining lease and non-lease components and accounting for them as a single lease (elected by asset class);
•excluding land easements that existed or expired prior to adoption; and
•policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance.
Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion.
Recently Issued Accounting Standards
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of December 31, 2020, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 7 – Borrowings” for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Credit Facility.
Note 3 – Revenue Recognition
Revenue from contracts with customers
Oil sales
Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.
Natural gas and NGL sales
Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas processing agreements and have concluded that we maintain control through processing or we have the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. We recognize revenue when control transfers to the purchaser at the delivery point based on the contractual index price received.
Contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to deliver the product to the purchaser, for the majority of the Company’s natural gas processing agreements were previously recorded as a reduction of revenue. As a result of the modifications to certain of the Company’s natural gas processing agreements, as well as the natural gas processing agreements assumed in the Carrizo Acquisition, the Company now recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and
processing” in its consolidated statements of operations as the Company maintains control throughout processing. These changes impact the comparability of 2020 with prior periods. For the years ended December 31, 2019 and 2018, $10.5 million and $7.6 million of gathering, transportation, and processing fees were recognized as a reduction to natural gas revenues in the consolidated statement of operations.
Oil and gas purchase and sale arrangements
Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.
Accounts receivable from revenues from contracts with customers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2020 and 2019 of $100.3 million and $165.3 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The decrease from December 31, 2019 is primarily due to the lower realized price of oil.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Note 4 – Acquisitions and Divestitures
2020 Acquisitions and Divestitures
ORRI Transaction. On September 30, 2020, the Company sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests to Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, for an aggregate purchase price of $140.0 million (“ORRI Transaction”), with an effective date of October 1, 2020. After adjusting for costs associated with the sale, the net proceeds of $135.8 million were used to repay borrowings outstanding under the Credit Facility.
Non-Operated Working Interest Transaction. On November 2, 2020, the Company sold substantially all of its non-operated assets for net proceeds of approximately $29.6 million, which were used to repay borrowings outstanding under the Credit Facility. The transaction had an effective date of September 1, 2020 and is subject to post-closing adjustments.
The aggregate net proceeds for each of the 2020 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves.
The Company did not have any material acquisitions for the year ended December 31, 2020.
2019 Acquisitions and Divestitures
Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “Note 7 - Borrowings” for further details.
The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate.
The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
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Final Purchase
Price Allocation
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(In thousands)
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Consideration:
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Fair value of the Company’s common stock issued
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$765,373
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Total consideration
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$765,373
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Liabilities:
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Accounts payable
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$37,657
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Revenues and royalties payable
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52,449
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Operating lease liabilities - current
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29,924
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Fair value of derivatives - current
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61,015
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Other current liabilities
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88,346
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Long-term debt
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1,984,135
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Operating lease liabilities - non-current
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30,070
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Asset retirement obligation
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26,151
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Fair value of derivatives - non-current
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26,960
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Other long-term liabilities
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17,887
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Common stock warrants
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10,029
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Total liabilities assumed
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$2,364,623
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Assets:
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Accounts receivable, net
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$48,479
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Fair value of derivatives - current
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17,451
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Other current assets
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11,640
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Evaluated oil and natural gas properties
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2,133,280
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Unevaluated properties
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679,900
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Other property and equipment
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9,614
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Fair value of derivatives - non-current
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4,518
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Deferred tax asset
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162,629
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Operating lease right-of-use-assets
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59,907
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Other long term assets
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2,578
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Total assets acquired
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$3,129,996
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During the measurement period, the Company made adjustments to certain of the assets acquired and liabilities assumed, primarily due to the final tax returns of Carrizo which provided the underlying tax basis of Carrizo’s assets and liabilities. Approximately $556.2 million of revenues and $200.9 million of direct operating expenses attributed to the Carrizo Acquisition were included in the Company’s consolidated statements of operations for the year ended December 31, 2020. For the period from the closing date of the Carrizo Acquisition on December 20, 2019 through December 31, 2019, approximately $28.6 million of revenues and $7.0 million of
direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2019.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2019 and 2018 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.
Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.
The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.
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Years Ended December 31,
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2019
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2018
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(In thousands)
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Revenues
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$1,620,357
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$1,661,171
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Income from operations
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614,668
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767,628
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Net income
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369,777
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734,527
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Basic earnings per common share
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$0.89
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$1.87
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Diluted earnings per common share
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$0.89
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$1.87
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In conjunction with the Carrizo Acquisition, the Company incurred costs totaling $28.5 million and $74.4 million for the years ended December 31, 2020 and 2019, respectively, comprised of severance costs of $6.2 million and $28.8 million for the years ended December 31, 2020 and 2019, respectively, and other merger and integration expenses of $22.3 million and $45.6 million for the years ended December 31, 2020 and 2019, respectively. Through December 31, 2020, the Company has incurred cumulative costs associated with the Carrizo Acquisition of $102.9 million comprised of severance costs of $35.8 million and other merger and integration expenses of $67.1 million. As of December 31, 2020 and 2019, $5.7 million and $52.4 million, respectively, remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets.
Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”) for net cash proceeds of $244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which included approximately 9,850 net Wolfcamp acres with an average 66% working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves.
2018 Acquisitions and Divestitures
On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for a net cash consideration of approximately $539.5 million (the “Delaware Asset Acquisition”). The Company funded the Delaware Asset Acquisition with net proceeds from both the common stock
offering completed on May 30, 2018 and the issuance of the 6.375% Senior Notes. See “Note 7 - Borrowings” and “Note 11 - Stockholders’ Equity” for further details of these offerings.
The Delaware Asset Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
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Purchase Price Allocation
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(In thousands)
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Assets
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Oil and natural gas properties
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Evaluated properties
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$253,089
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Unevaluated properties
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287,000
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Total oil and natural gas properties
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$540,089
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Total assets acquired
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$540,089
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Liabilities
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Asset retirement obligations
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($570)
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Total liabilities assumed
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($570)
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Net Assets Acquired
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$539,519
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Approximately $27.3 million of revenues and $9.9 million of direct operating expenses attributed to the Delaware Asset Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on August 31, 2018 through December 31, 2018.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2018, assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition.
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Year Ended December 31, 2018
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(In thousands)
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Revenues
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$669,236
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Income from operations
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299,090
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Net income
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324,318
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Basic earnings per common share
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$1.49
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Diluted earnings per common share
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$1.49
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Other. In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for aggregate net cash consideration of approximately $37.8 million. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for net cash consideration of approximately $87.9 million.
The Company did not have any material divestitures for the year ended December 31, 2018.
Note 5 – Property and Equipment, Net
As of December 31, 2020 and 2019, total property and equipment, net consisted of the following:
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As of December 31,
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2020
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2019
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Oil and natural gas properties, full cost accounting method
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(In thousands)
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Evaluated properties
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$7,894,513
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$7,203,482
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Accumulated depreciation, depletion, amortization and impairments
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(5,538,803)
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(2,520,488)
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Evaluated properties, net
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2,355,710
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4,682,994
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Unevaluated properties
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Unevaluated leasehold and seismic costs
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1,532,304
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1,843,725
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Capitalized interest
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200,946
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142,399
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Total unevaluated properties
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1,733,250
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1,986,124
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Total oil and natural gas properties, net
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$4,088,960
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$6,669,118
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Other property and equipment
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$60,287
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$67,202
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Accumulated depreciation
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(28,647)
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(31,949)
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Other property and equipment, net
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$31,640
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$35,253
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The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $36.2 million for the years ended December 31, 2020, 2019, and $28.0 million for the year ended December 31, 2018, respectively. The Company capitalized interest costs to unproved properties totaling $88.6 million, $78.5 million and $56.2 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Impairment of Evaluated Oil and Gas Properties
Primarily as a result of the significant reduction in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of evaluated oil and gas properties of $2.5 billion for the year December 31, 2020. The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2019 and 2018.
Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2020, 2019, and 2018 are summarized in the table below:
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Years Ended December 31,
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2020
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2019
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2018
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Impairment of evaluated oil and natural gas properties (In thousands)
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$2,547,241
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$—
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$—
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Beginning of period 12-Month Average Realized Price ($/Bbl)
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$53.90
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$58.40
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$49.48
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End of period 12-Month Average Realized Price ($/Bbl)
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$37.44
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$53.90
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$58.40
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Percent increase (decrease) in 12-Month Average Realized Price
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(31
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%)
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(8
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%)
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18
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%
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The Company currently estimates the range of the first quarter of 2021 cost center ceiling, at the high end, would exceed the net book value of oil and gas properties, resulting in no impairment in the carrying value of evaluated oil and gas properties, and at the low end, would result in an impairment in the carrying value of evaluated oil and gas properties of $100.0 million. This is based on an estimated 12-Month Average Realized price of crude oil of approximately $40.23 per Bbl as of March 31, 2021, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Declines in the 12-Month Average Realized Price of crude oil in subsequent quarters could result in a lower present value of the estimated future net revenues from proved oil and gas reserves and may result in additional impairments of evaluated oil and gas properties.
As a result of the downturn in the oil and gas industry as well as in the broader macroeconomic environment in 2020, the Company analyzed its unevaluated leasehold giving consideration to its updated exploration program as well as to the remaining lease term of certain unevaluated leaseholds. As a result of this analysis, the Company impaired $229.6 million unevaluated leasehold costs and transferred to evaluated properties during the year ended December 31, 2020.
Unevaluated property costs not subject to amortization as of December 31, 2020 were incurred in the following periods:
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2020
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2019
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2018
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2017 and Prior
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Total
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(In thousands)
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Unevaluated property costs
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$113,078
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$680,456
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$439,478
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$500,238
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$1,733,250
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Note 6 – Earnings Per Share
Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the year ended December 31, 2020, the Company reported a loss available to common stockholders. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding.
The following table sets forth the computation of basic and diluted earnings per share:
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Years Ended December 31,
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2020
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2019
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2018
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(In thousands, except per share amounts)
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Net income (loss)
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($2,533,621)
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$67,928
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$300,360
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Preferred stock dividends (1)
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—
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(3,997)
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(7,295)
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Loss on redemption of preferred stock
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—
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(8,304)
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—
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Income (loss) available to common stockholders
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($2,533,621)
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$55,627
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$293,065
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Basic weighted average common shares outstanding (2)
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39,718
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23,313
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21,703
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Dilutive impact of restricted stock (2)
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—
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27
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70
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Diluted weighted average common shares outstanding (2)
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39,718
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23,340
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21,773
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Income (Loss) Available to Common Stockholders Per Common Share (2)
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Basic
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($63.79)
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$2.39
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$13.50
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Diluted
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($63.79)
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$2.38
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$13.46
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Restricted stock (2)(3)
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581
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90
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16
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Warrants (2)(3)
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2,564
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9
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0
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(1) The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption.
(2) Shares and per share data have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 – Stockholders’ Equity” for additional information.
(3) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
Note 7 – Borrowings
The Company’s borrowings consisted of the following:
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As of December 31,
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2020
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2019
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(In thousands)
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Senior Secured Revolving Credit Facility due 2024
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$985,000
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$1,285,000
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9.00% Second Lien Senior Secured Notes due 2025
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516,659
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—
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6.25% Senior Notes due 2023
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542,720
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650,000
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6.125% Senior Notes due 2024
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460,241
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600,000
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8.25% Senior Notes due 2025
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187,238
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250,000
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6.375% Senior Notes due 2026
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320,783
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400,000
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Total principal outstanding
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3,012,641
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3,185,000
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Unamortized discount on Second Lien Notes
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(41,820)
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—
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Unamortized premium for 6.25% Senior Notes
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2,917
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4,838
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Unamortized premium for 6.125% Senior Notes
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3,236
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5,344
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Unamortized premium for 8.25% Senior Notes
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3,240
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5,286
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Unamortized deferred financing costs for Second Lien Notes
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(3,931)
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—
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Unamortized deferred financing costs for Senior Notes
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(7,019)
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(14,359)
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Total carrying value of borrowings (1)
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$2,969,264
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$3,186,109
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(1) Excludes unamortized deferred financing costs related to the Company’s Credit Facility of $23.6 million and $22.2 million as of December 31, 2020 and 2019, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
Senior Secured Revolving Credit Facility
On December 20, 2019, upon consummation of the Merger, the Company entered into the senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”). The credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) are outstanding at such time, (ii) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”) are outstanding at such time, and (iii) if the Second Lien Notes, defined below, are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion.
On December 31, 2020, the borrowing base and the elected commitment amount under the revolving credit facility was $1.6 billion, with borrowings outstanding of $985.0 million at a weighted average interest rate of 2.73%, and letters of credit outstanding of $25.2 million. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the Credit Facility shall have the meaning given to such terms in the credit agreement.
On May 7, 2020, the Company entered into the first amendment to its credit agreement governing the Credit Facility. The amendment included, but was not limited to the following:
•Established a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduced the elected commitments to $1.7 billion, which were subsequently revised as described below;
•Permits the incurrence of, among other things, new second lien notes in 2020 exchanged for unsecured notes in an aggregate principal amount of up to $400.0 million without triggering a reduction in the borrowing base so long as any such second lien notes are subject to an intercreditor agreement providing that the liens securing the second lien notes rank junior to the liens securing the credit agreement;
•Provides that testing of the Leverage Ratio is suspended until March 31, 2022, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not exceed 4.00 to 1.00;
•Provides for testing of the Secured Leverage Ratio that may not exceed 3.00 to 1.00 on a quarterly basis beginning with the quarter ended March 31, 2020 through the quarter ending December 31, 2021; and
•Provided that the testing of the Current Ratio was suspended until September 30, 2020, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not be less than 1.00 to 1.00
On September 30, 2020, the Company entered into the second amendment to its credit agreement governing the Credit Facility. The amendment, among other things, reaffirmed the $1.7 billion borrowing base as a result of the fall 2020 scheduled redetermination.
Also on September 30, 2020, the Company entered into the third amendment to its credit agreement governing the Credit Facility. The amendment included, but was not limited to the following:
•Established a new borrowing base of $1.6 billion and reduced the elected commitments to $1.6 billion in connection with the issuance of the September 2020 Second Lien Notes and September 2020 Warrants, described below, and the ORRI Transaction;
•Permitted the issuance of the $300.0 million of September 2020 Second Lien Notes as contemplated by the Purchase Agreement, described below, without triggering a reduction in the borrowing base;
•Extends through the end of 2021 the time period during which second lien notes issued in exchange for unsecured notes may be issued without triggering a reduction in the borrowing base; and
•If the Second Lien Notes are outstanding at such time, caused the maturity of the Credit Facility to spring forward to a date which is 182 days prior to the maturity of any of the 6.25% Senior Notes or the 6.125% Senior Notes, in each case, to the extent a principal amount of more than $100.0 million with respect to each such issuance is outstanding as of such date.
Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.00% to 2.00%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a Eurodollar loan plus a margin between 2.00% to 3.00%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations.
The Company terminated the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”), which was entered into on May 25, 2017, upon entering into the Credit Facility described above. As a result of terminating the Prior Credit Facility, the Company recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the Prior Credit Facility.
Second Lien Notes
On September 30, 2020, the Company entered into a Purchase Agreement (the “Purchase Agreement”) where it issued (i) $300.0 million in aggregate principal amount of its 9.00% Second Lien Senior Secured Notes due 2025 (the “September 2020 Second Lien Notes”) and (ii) warrants for 7.3 million shares of the Company’s common stock, with a term of five years and an exercise price of $5.60 per share, exercisable only on a net share settlement basis (the “September 2020 Warrants”), for aggregate consideration of $294.0 million. The Company used the proceeds, net of issuance costs, of approximately $288.6 million to repay borrowings outstanding under the Credit Facility. The Company also entered into a registration rights agreement with the purchaser of the September 2020 Second Lien Notes.
Net proceeds were allocated to the September 2020 Warrants based on their fair value on the date of issuance with the remaining net proceeds allocated to the September 2020 Second Lien Notes. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:
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|
|
Issuance Date Fair Value Assumptions
|
Exercise price
|
|
$5.60
|
Expected term (in years)
|
|
5.0
|
Expected volatility
|
|
116.3
|
%
|
Risk-free interest rate
|
|
0.3
|
%
|
Dividend yield
|
|
—
|
%
|
See “Note 9 - Fair Value Measurements” for further discussion.
The September 2020 Second Lien Notes will mature on the earlier of (i) April 1, 2025 and (ii) 91 days prior to the maturity date of any outstanding unsecured notes in a principal amount at or greater than $100.0 million and have interest payable semi-annually each April 1 and October 1, commencing on April 1, 2021.
The Company may redeem the September 2020 Second Lien Notes in accordance with the following terms: (1) prior to October 1, 2022, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 109.00% of principal, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2022, a redemption of all or part of the principal at a price of 100% of the principal amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the date of redemption; and (3) subsequent to October 1, 2022, a redemption, in whole or in part, at redemption prices decreasing annually from 105.00% to 100% of the principal amount redeemed plus accrued and unpaid interest.
Upon the occurrence of certain change of control events, each holder of the September 2020 Second Lien Notes may require the Company to repurchase all or a portion of the September 2020 Second Lien Notes at a price of 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase.
Senior Unsecured Notes Exchange
On November 2, 2020, the Company entered into an Exchange Agreement (the “Exchange Agreement”) by and among the Company and certain holders (the “Holders”) of the Company’s 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, and 6.375% Senior Notes (each as defined in this footnote and together the “Senior Unsecured Notes”). Upon closing on November 13, 2020, pursuant to the Exchange Agreement, the Company agreed to exchange $389.0 million of aggregate principal amount of the Senior Unsecured Notes held by the Holders for $216.7 million aggregate principal amount of newly issued 9.00% Second Lien Senior Secured Notes due 2025 (the “November 2020 Second Lien Notes” and together with the September 2020 Second Lien Notes the “Second Lien Notes”) at a weighted average exchange ratio of approximately $557 per $1,000 of principal exchanged. The November 2020 Second Lien Notes were issued under the Company’s indenture dated as of September 30, 2020. Pursuant to the Exchange Agreement, the Company also agreed to issue to the Holders warrants for approximately 1.75 million shares of the Company’s common stock, with a term of five years and an exercise price of $5.60 per share, exercisable only on a net share settlement basis (the “November 2020 Warrants”).
The Company assessed the debt exchange to determine whether it should be accounted for pursuant to Financial Accounting Standards Board’s Accounting Standard Codification (“ASC”) Topic 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC Topic 470-50, Modifications and Extinguishments (“ASC 470-50”). This assessment requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty. It was determined that the Company was not experiencing financial difficulty and could obtain funds at market rates similar to other non-troubled debtors, therefore the Company accounted for the exchange as an extinguishment of debt in accordance with ASC 470-50. As the November 2020 Second Lien Notes were issued with the November 2020 Warrants, the $216.7 million aggregate principal amount was allocated between the November 2020 Second Lien Notes and the November 2020 Warrants based on their relative fair values at the exchange date. This resulted in $207.6 million allocated to the November 2020 Second Lien Notes and $9.1 million allocated to the November 2020 Warrants. The Company recognized a gain on the extinguishment of debt of $170.4 million in its consolidated statement of operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date.
The fair value of the November 2020 Second Lien Notes was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation included the redemption premiums, described below, as well as redemption assumptions provided by the Company. The fair value of the November 2020 Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:
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|
|
Issuance Date Fair Value Assumptions
|
Exercise price
|
|
$5.60
|
Expected term (in years)
|
|
4.9
|
Expected volatility
|
|
98.4
|
%
|
Risk-free interest rate
|
|
0.4
|
%
|
Dividend yield
|
|
—
|
%
|
Senior Unsecured Notes
6.25% Senior Notes. The Company’s 6.25% Senior Notes, which were assumed upon consummation of the Merger, mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. The Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest. Following a change of control, each holder of the 6.25% Senior Notes may require the Company to repurchase the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest.
6.125% Senior Notes. The Company’s 6.125% Senior Notes mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. The Company may redeem all or a portion of the 6.125% Senior Notes at redemption prices decreasing from 104.594% to 100% of the principal amount on October 1, 2022, plus accrued and unpaid interest. Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest.
8.25% Senior Notes. The Company’s 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”), which were assumed upon consummation of the Merger, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Since July 15, 2020, the Company may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of
the 8.25% Senior Notes may require the Company to repurchase the 8.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest.
6.375% Senior Notes. On June 7, 2018, the Company issued $400.0 million aggregate principal amount of 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. The Company used the net proceeds from the offering of approximately $394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund a portion of the Delaware Asset Acquisition described above.
The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) subsequent to July 1, 2021, a redemption, in whole or in part, at redemption prices decreasing annually from 103.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
Each of the Senior Unsecured Notes described above are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
Restrictive covenants
The Company’s credit agreement contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios.
Under the credit agreement, the Company must maintain the following financial covenants determined as of the last day of the quarter, each as described above: (1) a Secured Leverage Ratio of no more than 3.00 to 1.00 and (2) a Current Ratio of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2020.
The credit agreement and the indentures governing our Senior Unsecured Notes also place restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The credit agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
Note 8 – Derivative Instruments and Hedging Activities
Objectives and strategies for using derivative instruments
The Company is exposed to fluctuations in oil, natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty risk and offsetting
The Company typically has numerous commodity derivative instruments outstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
As of December 31, 2020, the Company has outstanding commodity derivative instruments with sixteen counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any
need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting.
Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk and accordingly does not currently require its counterparties to post collateral to support the net asset positions of its commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty.
While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. See “Note 9 - Fair Value Measurements” for further discussion.
Financial statement presentation and settlements
Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 9 - Fair Value Measurements” for additional information regarding fair value.
Contingent consideration arrangements
Ranger Divestiture. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds for the next year. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):
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Year
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|
Threshold (1)
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|
Contingent
Receipt -
Annual
|
|
Threshold (1)
|
|
Contingent
Receipt -
Annual
|
|
Period
Cash Flow
Occurs
|
|
Statement of
Cash Flows Presentation
|
|
Remaining Contingent
Receipt -
Aggregate Limit (3)
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Remaining Potential Settlement
|
|
2021
|
|
Greater than $60/Bbl, less than $65/Bbl
|
|
$9,000
|
|
|
Equal to or greater than $65/Bbl
|
|
$20,833
|
|
|
(2)
|
|
(2)
|
|
$20,833
|
|
|
|
(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.
(2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder presented in cash flows from operating activities.
(3) The specified pricing threshold for both 2019 and 2020 was not met. As such, approximately $20.8 million remains for potential settlements in future years.
As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below:
Contingent ExL Consideration
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Year
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|
Threshold (1)
|
|
Period
Cash Flow
Occurs
|
|
Statement of
Cash Flows Presentation
|
|
Contingent
Payment -
Annual
|
|
Remaining Contingent
Payments -
Aggregate Limit
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(In thousands)
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Remaining Potential Settlement
|
|
2021
|
|
$50.00
|
|
|
(2)
|
|
(2)
|
|
($25,000)
|
|
|
($25,000)
|
|
(3)
|
|
(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).
(2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from investing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. In January 2020, the Company paid $50.0 million as the specified pricing threshold for 2019 was met. Therefore, if the commodity price threshold is reached in 2021, $19.2 million of the next contingent payment will be presented in cash flows from investing activities with the remainder presented in cash flows from operating activities.
(3) The specified pricing threshold for 2020 was not met. Only $25.0 million remains for potential settlements in future years.
Additionally, as part of the Carrizo Acquisition, the Company acquired other contingent consideration arrangements where the Company could receive payments if certain pricing thresholds were met in 2019 and 2020, which ranged between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. The specified pricing thresholds for each of these other contingent consideration arrangements for 2020 were not met, therefore there were no payments from the contingent consideration arrangements acquired in the Carrizo Acquisition in January 2021. In January 2020, the Company received $10.0 million as the specified pricing thresholds for 2019 were met for certain of the contingent consideration arrangements. These cash receipts are classified as cash flows from investing activities in the consolidated statements of cash flows. Each of these other contingent consideration arrangements acquired in the Carrizo Acquisition expired at the end of the 2020.
Warrants
The Company determined that the September 2020 Warrants issued with the September 2020 Second Lien Notes are required to be accounted for as a derivative instrument. The September 2020 Warrants are exercisable only on a net share settlement basis. The Company records the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a result of changes in the fair value of the September 2020 Warrants recorded as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which the changes occur. Upon issuance, the Company recorded a liability for the September 2020 Warrants of $23.9 million and as of December 31, 2020, the liability for the September 2020 Warrants was $79.4 million. See “Note 18 - Subsequent Events” for further discussion.
Derivatives not designated as hedging instruments
The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations. As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2020
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
|
(In thousands)
|
Assets
|
|
|
|
|
|
Commodity derivative instruments
|
$21,156
|
|
|
($20,235)
|
|
|
$921
|
|
Contingent consideration arrangements
|
—
|
|
|
—
|
|
|
—
|
|
Fair value of derivatives - current
|
$21,156
|
|
|
($20,235)
|
|
|
$921
|
|
Commodity derivative instruments
|
$—
|
|
|
$—
|
|
|
$—
|
|
Contingent consideration arrangements
|
1,816
|
|
|
—
|
|
|
1,816
|
|
Other assets, net
|
$1,816
|
|
|
$—
|
|
|
$1,816
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
Commodity derivative instruments
|
($117,295)
|
|
|
$20,235
|
|
|
($97,060)
|
|
Contingent consideration arrangements
|
—
|
|
|
—
|
|
|
—
|
|
Fair value of derivatives - current
|
($117,295)
|
|
|
$20,235
|
|
|
($97,060)
|
|
Commodity derivative instruments
|
$—
|
|
|
$—
|
|
|
$—
|
|
Contingent consideration arrangements
|
(8,618)
|
|
|
—
|
|
|
(8,618)
|
|
September 2020 Warrants liability
|
(79,428)
|
|
|
—
|
|
|
(79,428)
|
|
Fair value of derivatives - non current
|
($88,046)
|
|
|
$—
|
|
|
($88,046)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2019
|
|
Presented without
|
|
|
|
As Presented with
|
|
Effects of Netting
|
|
Effects of Netting
|
|
Effects of Netting
|
|
(In thousands)
|
Assets
|
|
|
|
|
|
Commodity derivative instruments
|
$26,849
|
|
|
($17,511)
|
|
|
$9,338
|
|
Contingent consideration arrangements
|
16,718
|
|
|
—
|
|
|
16,718
|
|
Fair value of derivatives - current
|
$43,567
|
|
|
($17,511)
|
|
|
$26,056
|
|
Commodity derivative instruments
|
$—
|
|
|
$—
|
|
|
$—
|
|
Contingent consideration arrangements
|
9,216
|
|
|
—
|
|
|
9,216
|
|
Other assets, net
|
$9,216
|
|
|
$—
|
|
|
$9,216
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
Commodity derivative instruments
|
($38,708)
|
|
|
$17,511
|
|
|
($21,197)
|
|
Contingent consideration arrangements
|
(50,000)
|
|
|
—
|
|
|
(50,000)
|
|
Fair value of derivatives - current
|
($88,708)
|
|
|
$17,511
|
|
|
($71,197)
|
|
Commodity derivative instruments
|
($12,935)
|
|
|
—
|
|
|
($12,935)
|
|
Contingent consideration arrangements
|
(19,760)
|
|
|
—
|
|
|
(19,760)
|
|
Fair value of derivatives - non current
|
($32,695)
|
|
|
$—
|
|
|
($32,695)
|
|
The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:
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|
|
|
|
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|
|
|
|
|
|
|
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|
|
Years Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
(In thousands)
|
(Gain) loss on oil derivatives
|
($48,031)
|
|
|
$73,313
|
|
|
($45,463)
|
|
(Gain) loss on natural gas derivatives
|
14,883
|
|
|
(8,889)
|
|
|
(3,081)
|
|
(Gain) loss on NGL derivatives
|
2,426
|
|
|
—
|
|
|
—
|
|
(Gain) loss on contingent consideration arrangements
|
2,976
|
|
|
(2,315)
|
|
|
—
|
|
(Gain) loss on September 2020 Warrants liability
|
55,519
|
|
|
—
|
|
|
—
|
|
(Gain) loss on derivative contracts
|
$27,773
|
|
|
$62,109
|
|
|
($48,544)
|
|
The components of “Cash (paid) received for commodity derivative settlements” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
(In thousands)
|
Cash flows from operating activities
|
|
|
|
|
|
Cash (paid) received on oil derivatives
|
$98,723
|
|
|
($11,188)
|
|
|
($27,510)
|
|
Cash (paid) received on natural gas derivatives
|
147
|
|
|
7,399
|
|
|
238
|
|
Cash (paid) received for commodity derivative settlements
|
$98,870
|
|
|
($3,789)
|
|
|
($27,272)
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
Cash paid for settlements of contingent consideration arrangements, net
|
($40,000)
|
|
|
$—
|
|
|
$—
|
|
Derivative positions
Listed in the tables below are the outstanding oil, natural gas and NGL derivative contracts as of December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
|
|
Oil contracts (WTI)
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (Bbls)
|
1,827,000
|
|
|
|
|
Weighted average price per Bbl
|
$43.54
|
|
|
|
|
Collar contracts
|
|
|
|
|
Total volume (Bbls)
|
10,282,775
|
|
|
|
|
Weighted average price per Bbl
|
|
|
|
|
Ceiling (short call)
|
$46.69
|
|
|
|
|
Floor (long put)
|
$39.28
|
|
|
|
|
Short call contracts
|
|
|
|
|
Total volume (Bbls)
|
4,825,300
|
|
(1)
|
|
|
Weighted average price per Bbl
|
$63.62
|
|
|
|
|
Short call swaption contracts
|
|
|
|
|
Total volume (Bbls)
|
1,375,000
|
|
(2)
|
|
|
Weighted average price per Bbl
|
$49.01
|
|
|
|
|
|
|
|
|
|
Oil contracts (ICE Brent)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (Bbls)
|
848,300
|
|
|
|
|
Weighted average price per Bbl
|
$37.36
|
|
|
|
|
Collar contracts
|
|
|
|
|
Total volume (Bbls)
|
730,000
|
|
|
|
|
Weighted average price per Bbl
|
|
|
|
|
Ceiling (short call)
|
$50.00
|
|
|
|
|
Floor (long put)
|
$45.00
|
|
|
|
|
|
|
|
|
|
Oil contracts (Midland basis differential)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (Bbls)
|
3,022,900
|
|
|
|
|
Weighted average price per Bbl
|
$0.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil contracts (Argus Houston MEH)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (Bbls)
|
450,000
|
|
|
|
|
Weighted average price per Bbl
|
$46.50
|
|
|
|
|
Collar contracts
|
|
|
|
|
Total volume (Bbls)
|
409,500
|
|
|
|
|
Weighted average price per Bbl
|
|
|
|
|
Ceiling (short call)
|
$47.00
|
|
|
|
|
Floor (long put)
|
$41.00
|
|
|
|
|
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
(2) The short call swaption contracts have exercise expiration dates as follows: 455,000 Bbls expire on March 31, 2021, 460,000 Bbls expire on June 30, 2021 and 460,000 Bbls expire on September 30, 2021.
|
|
|
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
|
|
Natural gas contracts (Henry Hub)
|
2021
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (MMBtu)
|
11,123,000
|
|
|
|
|
Weighted average price per MMBtu
|
$2.60
|
|
|
|
|
Collar contracts (three-way collars)
|
|
|
|
|
Total volume (MMBtu)
|
1,350,000
|
|
|
|
|
Weighted average price per MMBtu
|
|
|
|
|
Ceiling (short call)
|
$2.70
|
|
|
|
|
Floor (long put)
|
$2.42
|
|
|
|
|
Floor (short put)
|
$2.00
|
|
|
|
|
Collar contracts (two-way collars)
|
|
|
|
|
Total volume (MMBtu)
|
9,550,000
|
|
|
|
|
Weighted average price per MMBtu
|
|
|
|
|
Ceiling (short call)
|
$3.04
|
|
|
|
|
Floor (long put)
|
$2.59
|
|
|
|
|
Short call contracts
|
|
|
|
|
Total volume (MMBtu)
|
7,300,000
|
|
(1)
|
|
|
Weighted average price per MMBtu
|
$3.09
|
|
|
|
|
|
|
|
|
|
Natural gas contracts (Waha basis differential)
|
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (MMBtu)
|
16,425,000
|
|
|
|
|
Weighted average price per MMBtu
|
($0.42)
|
|
|
|
|
(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.
|
|
|
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
|
|
NGL contracts (OPIS Mont Belvieu Purity Ethane)
|
2021
|
|
|
|
Swap contracts
|
|
|
|
|
Total volume (Bbls)
|
1,825,000
|
|
|
|
|
Weighted average price per Bbl
|
$7.62
|
|
|
|
|
Note 9 – Fair Value Measurements
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair value of financial instruments
Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt. The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the borrowings bear interest at variable rates and are reflective of market rates. As of December 31, 2020, the Company determined that its Second Lien Notes met the requirements to be designated as Level 2 in the valuation hierarchy due to the availability of quoted secondary market trading prices resulting in the transfer out of Level 3. The following table presents the principal amounts of the Company’s Second Lien Notes
and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 7 - Borrowings” for further discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
|
Principal Amount
|
|
Fair Value
|
|
Principal Amount
|
|
Fair Value
|
|
|
(In thousands)
|
9.00% Second Lien Senior Secured Notes
|
|
$516,659
|
|
|
$470,160
|
|
|
$—
|
|
|
$—
|
|
6.25% Senior Notes
|
|
542,720
|
|
|
344,627
|
|
|
650,000
|
|
|
658,125
|
|
6.125% Senior Notes
|
|
460,241
|
|
|
260,036
|
|
|
600,000
|
|
|
611,130
|
|
8.25% Senior Notes
|
|
187,238
|
|
|
100,172
|
|
|
250,000
|
|
|
256,250
|
|
6.375% Senior Notes
|
|
320,783
|
|
|
161,995
|
|
|
400,000
|
|
|
405,424
|
|
Total
|
|
$2,027,641
|
|
|
$1,336,990
|
|
|
$1,900,000
|
|
|
$1,930,929
|
|
Assets and liabilities measured at fair value on a recurring basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:
Commodity derivative instruments. The fair value of commodity derivative instruments is derived using a third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion.
Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
Assets
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$—
|
|
|
$921
|
|
|
$—
|
|
Contingent consideration arrangements
|
|
—
|
|
|
1,816
|
|
|
—
|
|
Liabilities
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
—
|
|
|
(97,060)
|
|
|
—
|
|
Contingent consideration arrangements
|
|
—
|
|
|
(8,618)
|
|
|
—
|
|
September 2020 Warrants
|
|
—
|
|
|
—
|
|
|
(79,428)
|
|
Total net assets (liabilities)
|
|
$—
|
|
|
($102,941)
|
|
|
($79,428)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
(In thousands)
|
Assets
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
$—
|
|
|
$9,338
|
|
|
$—
|
|
Contingent consideration arrangements
|
|
—
|
|
|
25,934
|
|
|
—
|
|
Liabilities
|
|
|
|
|
|
|
Commodity derivative instruments
|
|
—
|
|
|
(34,132)
|
|
|
—
|
|
Contingent consideration arrangements
|
|
—
|
|
|
(69,760)
|
|
|
—
|
|
Total net liabilities (liabilities)
|
|
$—
|
|
|
($68,620)
|
|
|
$—
|
|
September 2020 Warrants. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants are designated as Level 3 within the valuation hierarchy. See “Note 7 - Borrowings” and “Note 8 - Derivative Instruments and Hedging Activities” for additional details regarding the September 2020 Warrants.
The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants for the year ended December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2020
|
|
|
(In thousands)
|
Beginning of period
|
|
$—
|
|
Recognition of issuance date fair value
|
|
23,909
|
|
(Gain) loss on changes in fair value
|
|
55,519
|
|
Transfers into (out of) Level 3
|
|
—
|
|
End of period
|
|
$79,428
|
|
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisitions. The fair value of assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the market and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 - Acquisitions and Divestitures” for additional discussion.
Asset retirement obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 14 - Asset Retirement Obligations” for additional discussion.
Note 10 – Share-Based Compensation
All share and per share numbers included in this footnote, except for those disclosed in “— 2018 Omnibus Incentive Plan” below, have been adjusted for the reverse stock split. See “Note 11 - Stockholders’ Equity” for discussion of the reverse stock split and reduction in authorized shares.
2020 Omnibus Incentive Plan
At the Company’s annual meeting of shareholders on June 8, 2020, shareholders approved the 2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the 2020 Plan, no further awards may be granted under the 2018 Plan, however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. Effective August 7, 2020, in connection with the reverse stock split and reduction in authorized shares, the Board of Directors approved and adopted an amendment to the 2020 Plan to proportionately adjust the limitations on awards that may be granted. At December 31, 2020, there were 2,002,463 shares available for future share-based awards under the 2020 Plan.
2018 Omnibus Incentive Plan
The 2018 Plan, which became effective May 10, 2018 following shareholder approval, authorized and reserved for issuance 9,400,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2018 Plan replaced the 2011 Omnibus Incentive Plan (the “Prior Plan”), and included a provision at inception whereby all remaining, un-issued and authorized shares from the Prior Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional 1,322,742 shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to 10,722,742 at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the Prior Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan. As a result of the Merger, the 2018 Plan was amended and restated to incorporate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “Carrizo Plan”), including outstanding awards under the Carrizo Plan and shares available to grant to the former employees of Carrizo which were converted to shares of the Company by applying the conversion ratio of 1.75 shares of the Company per one share of Carrizo (the “Amended and Restated 2018 Plan”).
RSU Equity Awards
The following table summarizes RSU Equity Award activity for the years ended December 31, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RSU Equity Awards (in thousands)
|
|
Weighted Average Grant-Date Fair Value per Share
|
For the Year Ended December 31, 2018
|
|
|
|
|
Unvested at the beginning of the period
|
|
179
|
|
|
$115.36
|
|
Granted (1)
|
|
87
|
|
|
$144.86
|
|
Vested (2)
|
|
(51)
|
|
|
$103.83
|
|
Forfeited
|
|
(5)
|
|
|
$114.32
|
|
Unvested at the end of the period
|
|
210
|
|
|
$130.39
|
|
For the Year Ended December 31, 2019
|
|
|
|
|
Unvested at the beginning of the period
|
|
210
|
|
|
$130.39
|
|
Granted (1)
|
|
188
|
|
|
$85.96
|
|
Vested (2)
|
|
(106)
|
|
|
$126.75
|
|
Forfeited
|
|
(23)
|
|
|
$110.55
|
|
Unvested at the end of the period
|
|
269
|
|
|
$102.48
|
|
For the Year Ended December 31, 2020
|
|
|
|
|
Unvested at the beginning of the period
|
|
269
|
|
|
$102.48
|
|
Granted (1)
|
|
562
|
|
|
$21.07
|
|
Vested (2)
|
|
(132)
|
|
|
$105.14
|
|
Forfeited
|
|
(22)
|
|
|
$96.84
|
|
Unvested at the end of the period
|
|
677
|
|
|
$34.57
|
|
(1)Includes 111.2 thousand, 39.9 thousand and 20.8 thousand target performance-based RSU Equity Awards for the years ended December 31, 2020, 2019 and 2018, respectively.
(2)The fair value of shares vested was $1.6 million, $7.3 million and $6.3 million during the years ended December 31, 2020, 2019 and 2018, respectively.
Grant activity for the years ended December 31, 2020, 2019 and 2018 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards.
The number of outstanding performance-based RSU Equity Awards that can vest is based on a calculation that compares the Company’s total shareholder return (“TSR”) to the same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% of the target units for the awards granted in 2020 and between 0% and 200% of the target units for the awards granted in 2018 and 2019. The increase in the maximum amount of performance-based RSU Equity Awards that can vest for the awards granted in 2020 is due to an absolute TSR modifier, which was added as a second factor in the calculation, in addition to the relative TSR multiplier. While the absolute TSR modifier could increase the number of awards that vest, the number of awards that vest could also be reduced if the absolute TSR is less than 5% over the performance period.
The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
Performance-based Equity Awards
|
|
2020
|
|
2019
|
|
2018
|
Vesting Multiplier
|
|
50% - 100%
|
|
100
|
%
|
|
142
|
%
|
Target
|
|
21,920
|
|
8,878
|
|
8,300
|
Vested at end of performance period
|
|
11,372
|
|
8,878
|
|
11,786
|
Did not vest at end of performance period
|
|
10,548
|
|
—
|
|
—
|
The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest. For the years ended December 31, 2020, 2019 and 2018, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $3.4 million, $4.3 million, and $3.5 million, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the years ended December 31, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance-based Awards
|
|
June 29, 2020
|
|
January 31, 2020
|
|
January 31, 2019
|
|
May 10, 2018
|
Expected term (in years)
|
|
2.5
|
|
2.9
|
|
2.9
|
|
2.6
|
Expected volatility
|
|
113.2
|
%
|
|
54.8
|
%
|
|
47.9
|
%
|
|
51.6
|
%
|
Risk-free interest rate
|
|
0.2
|
%
|
|
1.3
|
%
|
|
2.4
|
%
|
|
2.6
|
%
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
As of December 31, 2020, unrecognized compensation costs related to unvested RSU Equity Awards were $13.5 million and will be recognized over a weighted average period of 1.7 years.
Cash-Settled RSU Awards
The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash-Settled RSU Awards
(in thousands)
|
|
Weighted Average Grant-Date Fair Value per Share
|
For the Year Ended December 31, 2018
|
|
|
|
|
Unvested at the beginning of the period
|
|
61
|
|
|
$123.82
|
|
Granted
|
|
35
|
|
|
$164.77
|
|
Vested
|
|
(28)
|
|
|
$116.67
|
|
Forfeited
|
|
(2)
|
|
|
$161.50
|
|
Unvested at the end of the period
|
|
66
|
|
|
$147.59
|
|
For the Year Ended December 31, 2019
|
|
|
|
|
Unvested at the beginning of the period
|
|
66
|
|
|
$147.59
|
|
Granted
|
|
44
|
|
|
$105.08
|
|
Vested
|
|
(16)
|
|
|
$155.29
|
|
Forfeited
|
|
(8)
|
|
|
$145.71
|
|
Unvested at the end of the period
|
|
86
|
|
|
$124.22
|
|
For the Year Ended December 31, 2020
|
|
|
|
|
Unvested at the beginning of the period
|
|
86
|
|
|
$124.22
|
|
Granted
|
|
142
|
|
|
$26.84
|
|
Vested
|
|
(16)
|
|
|
$160.39
|
|
Did not vest at end of performance period
|
|
(16)
|
|
|
$163.55
|
|
Forfeited
|
|
—
|
|
|
$—
|
|
Unvested at the end of the period
|
|
196
|
|
|
$47.56
|
|
Grant activity primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards that occurred in the first half of each of the years presented in the table above. These awards cliff vest after an approximate three-year performance period.
The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted for each of the respective periods presented are the same as the performance-based RSU Equity Awards presented above.
For the years ended December 31, 2020, 2019 and 2018, Cash-Settled RSU Awards vested resulting in cash payments of $0.2 million, $0.8 million and $3.2 million, respectively.
The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2020
|
|
2019
|
|
|
(In thousands)
|
Other current liabilities
|
|
$182
|
|
|
$966
|
|
Other long-term liabilities
|
|
1,336
|
|
|
2,089
|
|
Total Cash-Settled RSU Awards
|
|
$1,518
|
|
|
$3,055
|
|
As of December 31, 2020, the Company had the following performance-based Cash-Settled RSU Awards outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target Awards Outstanding
|
|
Potential Minimum Units Vesting
|
|
Potential Maximum Units Vesting
|
|
|
(In thousands)
|
Vesting in 2021
|
|
35
|
|
|
—
|
|
|
70
|
|
Vesting in 2022
|
|
111
|
|
|
—
|
|
|
334
|
|
Other
|
|
50
|
|
|
50
|
|
|
50
|
|
Total Cash-Settled RSU Awards
|
|
196
|
|
|
50
|
|
|
454
|
|
As of December 31, 2020, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $1.5 million and will be recognized over a weighted average period of 1.9 years.
Cash-Settled SARs
As a result of the Merger, Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The table below summarizes the Cash SAR activity for the year ended December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Appreciation Rights
(in thousands)
|
|
Weighted
Average
Exercise
Prices
|
|
Weighted Average Remaining Life
(In years)
|
|
Aggregate Intrinsic Value
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2019
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period
|
|
—
|
|
|
$—
|
|
|
|
|
|
Granted
|
|
—
|
|
|
$—
|
|
|
|
|
|
Reissued
|
|
368
|
|
|
$100.34
|
|
|
|
|
|
Exercised
|
|
—
|
|
|
$—
|
|
|
|
|
|
Forfeited
|
|
—
|
|
|
$—
|
|
|
|
|
|
Expired
|
|
—
|
|
|
$—
|
|
|
|
|
|
Outstanding, end of period
|
|
368
|
|
|
$100.34
|
|
|
4.4
|
|
$—
|
|
Vested, end of period
|
|
368
|
|
|
$100.34
|
|
|
—
|
|
|
$—
|
|
Vested and exercisable, end of period
|
|
—
|
|
|
$—
|
|
|
—
|
|
|
$—
|
|
For the Year Ended December 31, 2020
|
|
|
|
|
|
|
|
|
Outstanding, beginning of period
|
|
368
|
|
|
$100.34
|
|
|
|
|
|
Granted
|
|
—
|
|
|
$—
|
|
|
|
|
|
Exercised
|
|
—
|
|
|
$—
|
|
|
|
|
|
Forfeited
|
|
—
|
|
|
$—
|
|
|
|
|
|
Expired
|
|
—
|
|
|
$—
|
|
|
|
|
|
Outstanding, end of period
|
|
368
|
|
|
$100.34
|
|
|
3.4
|
|
$—
|
|
Vested, end of period
|
|
368
|
|
|
$100.34
|
|
|
—
|
|
|
$—
|
|
Vested and exercisable, end of period
|
|
—
|
|
|
$—
|
|
|
—
|
|
|
$—
|
|
The acquisition date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model was $4.6 million. The following table summarizes the assumptions used, the resulting acquisition date fair value per Cash SAR, and the expiration dates for the grants that occurred during periods presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
|
2016
|
Expected term (in years)
|
|
5.4
|
|
4.5
|
|
1.9
|
|
1.1
|
Expected volatility
|
|
60.7
|
%
|
|
56.9
|
%
|
|
58.6
|
%
|
|
68.1
|
%
|
Risk-free interest rate
|
|
1.7
|
%
|
|
1.7
|
%
|
|
1.6
|
%
|
|
1.5
|
%
|
Dividend yield
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
Expiration date
|
|
March 17, 2026
|
|
March 17, 2025
|
|
March 23, 2022
|
|
March 17, 2021
|
The liabilities for Cash SARs as of December 31, 2020 and 2019 were $1.7 million and $5.0 million, respectively, all of which were classified as “Other current liabilities” in the consolidated balance sheets in the respective periods. Changes to the fair value of the Cash SARs are included in “General and administrative” in the consolidated statements of operations. As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2020.
Share-Based Compensation Expense, Net
Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
RSU Equity Awards
|
|
$13,030
|
|
|
$14,322
|
|
|
$9,460
|
|
Cash-Settled RSU Awards
|
|
(771)
|
|
|
1,021
|
|
|
336
|
|
Cash SARs
|
|
(3,344)
|
|
|
443
|
|
|
—
|
|
|
|
8,915
|
|
|
15,786
|
|
|
9,796
|
|
Less: amounts capitalized to oil and gas properties
|
|
(6,252)
|
|
|
(4,704)
|
|
|
(3,434)
|
|
Total share-based compensation expense, net
|
|
$2,663
|
|
|
$11,082
|
|
|
$6,362
|
|
Note 11 – Stockholders’ Equity
November 2020 Warrants
The Company issued approximately 1.75 million November 2020 Warrants in conjunction with the November 2020 Second Lien Notes that were issued in the senior unsecured note exchange described above. The Company determined that the November 2020 Warrants qualify as freestanding financial instruments, but meet the scope exception in ASC 815 - Derivatives and Hedging as they are indexed to the Company’s common stock. As such, the November 2020 Warrants meet the applicable criteria for equity classification and are reflected in additional paid in capital in the consolidated balance sheets. See “Note 7 - Borrowings” and “Note 18 - Subsequent Events” for additional information.
Reverse Stock Split
On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and reduced the total number of authorized shares of the Company’s common stock pursuant to an amendment to the Company’s Certificate of Incorporation, which was approved by the Company’s shareholders at the Company’s annual meeting of shareholders on June 8, 2020. The reverse stock split became effective as of the close of business on August 7, 2020. The Company’s common stock began trading on a split-adjusted basis on the NYSE at the market open on August 10, 2020. The par value of the common stock was not adjusted as a result of the reverse stock split.
The reverse stock split was intended to, among other things, increase the per share trading price of the Company’s common shares to satisfy the $1.00 minimum closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, each 10 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled by paying cash in lieu of the fair value. The number of outstanding shares of common stock were reduced from 397,479,684 as of August 7, 2020 to 39,746,967 shares. The total number of shares of common stock that the Company is authorized to issue was reduced from 525,000,000 to 52,500,000 shares. All share and per share amounts, except par value per share, in the accompanying consolidated financial statements and notes thereto were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of common stock to additional paid-in capital in the current period.
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). The Company recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest. As such, no Preferred Stock dividends were paid during 2020. The Company paid Preferred Stock dividends of $4.0 million and $7.3 million for years ended December 31, 2019 and 2018, respectively.
Common Stock Offerings
On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately $288.0 million. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018. See “Note 4 - Acquisitions and Divestitures” for further discussion of the Delaware Asset Acquisition.
Note 12 – Income Taxes
The components of the Company’s income tax expense are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
Current
|
|
|
|
|
|
|
Federal
|
|
$—
|
|
|
$—
|
|
|
$—
|
|
State
|
|
3,447
|
|
|
220
|
|
|
—
|
|
Total current income tax expense
|
|
3,447
|
|
|
220
|
|
|
—
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
Federal
|
|
126,903
|
|
|
33,584
|
|
|
3,594
|
|
State
|
|
(8,296)
|
|
|
1,497
|
|
|
4,516
|
|
Total deferred income tax expense
|
|
118,607
|
|
|
35,081
|
|
|
8,110
|
|
Total income tax expense
|
|
$122,054
|
|
|
$35,301
|
|
|
$8,110
|
|
A reconciliation of the income tax expense calculated at the federal statutory rate of 21% to income tax expense is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
Income (loss) before income taxes
|
|
($2,411,567)
|
|
|
$103,229
|
|
|
$308,470
|
|
Income tax expense (benefit) computed at the statutory federal income tax rate
|
|
(506,429)
|
|
|
21,678
|
|
|
64,779
|
|
State income tax expense (benefit), net of federal benefit
|
|
(11,827)
|
|
|
1,253
|
|
|
3,568
|
|
Equity based compensation
|
|
2,746
|
|
|
1,222
|
|
|
(494)
|
|
Non-deductible compensation
|
|
—
|
|
|
90
|
|
|
1,209
|
|
Non-deductible merger expenses
|
|
—
|
|
|
5,537
|
|
|
—
|
|
Statutory depletion carryforward
|
|
—
|
|
|
5,381
|
|
|
—
|
|
Other
|
|
(1,621)
|
|
|
140
|
|
|
168
|
|
Change in valuation allowance
|
|
639,185
|
|
|
—
|
|
|
(61,120)
|
|
Income tax expense
|
|
$122,054
|
|
|
$35,301
|
|
|
$8,110
|
|
The income tax expense of $122.1 million for the year ended December 31, 2020 is primarily due to the valuation allowance recorded against the Company’s net deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for additional details.
At December 31, 2019, the Company recorded a tax expense of $5.5 million associated with non-deductible merger expenses from the Carrizo Acquisition which primarily relate to non-deductible executive compensation expenses and transaction costs that are inherently facilitative in nature and permanently capitalized for tax purposes.
As of December 31, 2020 and 2019, the net deferred income tax assets and liabilities are comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2020
|
|
2019
|
|
|
(In thousands)
|
Deferred tax assets
|
|
|
|
|
Oil and natural gas properties
|
|
$431,142
|
|
|
$—
|
|
Federal net operating loss carryforward
|
|
141,308
|
|
|
110,703
|
|
Derivative asset
|
|
39,378
|
|
|
14,823
|
|
Operating lease right-of-use assets
|
|
8,567
|
|
|
29,897
|
|
Asset retirement obligations
|
|
10,134
|
|
|
9,981
|
|
Unvested RSU equity awards
|
|
1,962
|
|
|
4,928
|
|
Other
|
|
11,430
|
|
|
10,445
|
|
Total deferred tax assets
|
|
$643,921
|
|
|
$180,777
|
|
Deferred income tax valuation allowance
|
|
(639,185)
|
|
|
—
|
|
Net deferred tax assets
|
|
$4,736
|
|
|
$180,777
|
|
Deferred tax liability
|
|
|
|
|
Oil and natural gas properties
|
|
$—
|
|
|
($38,546)
|
|
Derivative liability
|
|
—
|
|
|
—
|
|
Operating lease liabilities
|
|
(4,736)
|
|
|
(26,511)
|
|
Total deferred tax liability
|
|
($4,736)
|
|
|
($65,057)
|
|
Net deferred tax asset (liability)
|
|
$—
|
|
|
$115,720
|
|
Deferred Tax Asset Valuation Allowance
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and a net deferred tax asset position at December 31, 2020, driven primarily by the impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the rest of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Beginning in the second quarter of 2020 and continuing through the rest of 2020, based on the evaluation of the evidence available, the Company concluded that it is more likely than not that the net deferred tax assets will not be realized. As a result, the Company has recorded a valuation allowance of $639.2 million, reducing the net deferred tax assets as of December 31, 2020 to zero.
The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.
Carrizo Acquisition
For federal income tax purposes, the Carrizo Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in Carrizo’s assets and liabilities. The Company recorded an opening balance sheet deferred tax asset of $162.6 million related to tax attributes acquired from Carrizo. The acquired income tax attributes primarily consist of future deductions related to oil and gas properties, derivative assets, and federal net operating losses (“NOLs”). The acquired NOLs are subject to an annual limitation under Internal Revenue Code Section 382, as described below, and the Company reduced the total NOL balance and associated deferred tax asset for the NOLs to the amount that was expected at that time to be fully utilized prior to expirations. See above for discussion of the valuation allowance against the Company’s net deferred tax assets.
Due to the issuance of common stock associated with the Carrizo acquisition, the Company incurred a cumulative ownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At December 31, 2020, the Company had approximately $672.9 million of NOLs, including $284.1 million acquired from Carrizo. $414.9 million expire between 2035 and 2037 and $258.0 million have an indefinite carryforward life.
The Company had no significant unrecognized tax benefits at December 31, 2020. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. In the Company’s major tax jurisdictions, the earliest year open to examination is 2016.
Note 13 – Leases
The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.
Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.
Types of Leases
The Company currently has leases associated with contracts for office space, drilling rigs, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below.
Drilling Rigs. The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties.
Office Space. The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years. The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations.
Well Equipment. The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations.
The tables below, which present the components of lease costs and supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.
The table below presents the components of the Company’s lease costs for the year ended December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
|
(In thousands)
|
Components of Lease Costs
|
|
|
|
|
Finance lease costs
|
|
$1,489
|
|
|
$92
|
|
Amortization of right-of-use assets (1)
|
|
1,348
|
|
|
82
|
|
Interest on lease liabilities (2)
|
|
141
|
|
|
10
|
|
Operating lease cost (3)
|
|
46,888
|
|
|
38,076
|
|
Impairment of Operating lease ROU assets (4)
|
|
3,575
|
|
|
16,209
|
|
Short-term lease cost (5)
|
|
1,821
|
|
|
3,640
|
|
Variable lease costs (6)
|
|
259
|
|
|
—
|
|
Total lease costs
|
|
$54,032
|
|
|
$58,017
|
|
(1)Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations.
(2)Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations.
(3)For the years ended December 31, 2020 and 2019, approximately $34.2 million and $34.9 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations.
(4)As a result of the downturn in economic conditions in conjunction with our ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its Operating lease ROU assets for the years ended December 31, 2020 and 2019 of $3.6 million and $16.2 million, respectively, which are a component of “Merger and integration expenses” in the consolidated statements of operations.
(5)Short-term lease cost excludes expenses related to leases with a contract term of one month or less.
(6)Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.
The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2020
|
|
2019
|
|
|
(In thousands)
|
Leases
|
|
|
|
|
Operating leases:
|
|
|
|
|
Operating lease ROU assets
|
|
$22,526
|
|
|
$63,908
|
|
|
|
|
|
|
Current operating lease liabilities
|
|
$13,175
|
|
|
$42,858
|
|
Long-term operating lease liabilities
|
|
27,576
|
|
|
37,088
|
|
Total operating lease liabilities
|
|
$40,751
|
|
|
$79,946
|
|
The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
Weighted Average Remaining Lease Terms (In years)
|
|
|
Operating leases
|
|
6.2
|
Financing leases
|
|
3.0
|
|
|
|
Weighted Average Discount Rate
|
|
|
Operating leases
|
|
5.5
|
%
|
Financing leases
|
|
6.7
|
%
|
The table below presents the maturity of the Company’s lease liabilities as of December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Financing Leases
|
|
|
(In thousands)
|
2021
|
|
$14,918
|
|
|
$314
|
|
2022
|
|
5,443
|
|
|
250
|
|
2023
|
|
5,011
|
|
|
233
|
|
2024
|
|
4,936
|
|
|
39
|
|
2025
|
|
3,958
|
|
|
—
|
|
Thereafter
|
|
14,139
|
|
|
—
|
|
Total lease payments
|
|
48,405
|
|
|
836
|
|
Less imputed interest
|
|
(7,654)
|
|
|
(78)
|
|
Total lease liabilities
|
|
$40,751
|
|
|
$758
|
|
Note 14 – Asset Retirement Obligations
The table below summarizes the activity for the Company’s asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
|
(In thousands)
|
Asset retirement obligations, beginning of period
|
|
$49,733
|
|
|
$14,292
|
|
Accretion expense
|
|
3,323
|
|
|
945
|
|
Liabilities incurred
|
|
3,895
|
|
|
615
|
|
Increase due to acquisition of oil and gas properties
|
|
—
|
|
|
26,107
|
|
Liabilities settled
|
|
(2,220)
|
|
|
(3,394)
|
|
Dispositions
|
|
(351)
|
|
|
(1,776)
|
|
Revisions to estimates
|
|
4,710
|
|
|
12,944
|
|
Asset retirement obligations, end of period
|
|
59,090
|
|
|
49,733
|
|
Less: Current asset retirement obligations
|
|
(1,881)
|
|
|
(873)
|
|
Non-current asset retirement obligations
|
|
$57,209
|
|
|
$48,860
|
|
Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2020 and 2019 as long-term restricted investments were $3.5 million, and are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
Note 15 – Accounts Receivable, Net
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
2020
|
|
2019
|
|
(In thousands)
|
Oil and natural gas receivables
|
$100,257
|
|
|
$165,275
|
|
Joint interest receivables
|
11,530
|
|
|
39,114
|
|
Other receivables
|
24,191
|
|
|
6,610
|
|
Total
|
135,978
|
|
|
210,999
|
|
Allowance for credit losses
|
(2,869)
|
|
|
(1,536)
|
|
Total accounts receivable, net
|
$133,109
|
|
|
$209,463
|
|
Note 16 – Accounts Payable and Accrued Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
2020
|
|
2019
|
|
(In thousands)
|
Accounts payable
|
$101,231
|
|
|
$217,578
|
|
Revenues payable
|
162,762
|
|
|
145,816
|
|
Accrued capital expenditures
|
32,493
|
|
|
61,950
|
|
Accrued interest
|
45,033
|
|
|
36,295
|
|
Accrued severance (1)
|
3,846
|
|
|
28,803
|
|
Total accounts payable and accrued liabilities
|
$345,365
|
|
|
$490,442
|
|
(1)See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.
Note 17 – Commitments and Contingencies
The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of oil, natural gas, or produced water to be delivered, as of December 31, 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
2025
|
|
2026 and Thereafter
|
|
Total
|
|
|
(In thousands)
|
Operating leases (1)
|
|
$10,601
|
|
$5,443
|
|
$5,011
|
|
$4,936
|
|
$3,958
|
|
$14,139
|
|
$44,088
|
Drilling rig contracts (2)
|
|
4,317
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,317
|
|
Delivery commitments (3)
|
|
12,401
|
|
|
10,980
|
|
|
11,553
|
|
|
12,451
|
|
|
12,417
|
|
|
39,291
|
|
|
99,093
|
|
Produced water disposal commitments (4)
|
|
21,355
|
|
|
18,320
|
|
|
10,775
|
|
|
7,975
|
|
|
4,267
|
|
|
741
|
|
|
63,433
|
|
Total
|
|
$48,674
|
|
$34,743
|
|
$27,339
|
|
$25,362
|
|
$20,642
|
|
$54,171
|
|
$210,931
|
(1)Operating leases primarily consist of contracts for office space. See “Note 13 – Leases” for additional information.
(2)Drilling rig contracts represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs. In January 2021, the Company extended one of its drilling rig contracts for a term of one year. The gross contractual obligation for this extended drilling rig contract is approximately $5.5 million and is not included in the table above as it was entered into subsequent to December 31, 2020.
(3)Delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas.
(4)Produced water disposal commitments represent contractual obligations the Company has entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.
Operating leases
As of December 31, 2020, the Company had contracts for two horizontal drilling rigs. The contract terms will end on various dates between March 2021 and May 2021.
Other commitments
The following table includes the Company’s current oil sales contracts and firm transportation agreements as of December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type of Commitment (1)
|
|
Region
|
|
Execution Date
|
|
Start Date
|
|
End Date
|
|
Committed
Volumes (Bbls/d)
|
Oil sales contract
|
|
Eagle Ford
|
|
November 2020
|
|
January 2021
|
|
December 2021
|
|
10,000
|
Oil sales contract
|
|
Permian
|
|
August 2020
|
|
August 2020
|
|
December 2021
|
|
7,500
|
Oil sales contract
|
|
Permian
|
|
July 2019
|
|
August 2021
|
|
July 2026
|
|
5,000
|
Oil sales contract
|
|
Permian
|
|
June 2019
|
|
January 2020
|
|
December 2024
|
|
10,000
|
Oil sales contract
|
|
Permian
|
|
August 2018
|
|
April 2020
|
|
March 2022
|
|
15,000
|
Firm transportation agreement (2)(3)
|
|
Permian
|
|
June 2019
|
|
August 2020
|
|
July 2030
|
|
10,000
|
Firm transportation agreement (2)
|
|
Permian
|
|
August 2018
|
|
April 2020
|
|
March 2027
|
|
15,000
|
(1)For each of the commitments shown in the table above, the committed barrels may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes the Company markets on their behalf.
(2)Each of the firm transportation agreements shown in the table above grant the Company access to delivery points in several locations along the Gulf Coast.
(3)The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively.
Note 18 – Subsequent Events (Unaudited)
Hedging
Subsequent to December 31, 2020, the Company entered into the following derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
For the Full Year of
|
|
Oil contracts (WTI)
|
2021
|
|
2022
|
|
Collar contracts
|
|
|
|
|
Total volume (Bbls)
|
920,000
|
|
|
1,355,000
|
|
|
Weighted average price per Bbl
|
|
|
|
|
Ceiling (short call)
|
$60.18
|
|
|
$60.00
|
|
|
Floor (long put)
|
$47.50
|
|
|
$45.00
|
|
|
Short call swaption contracts 1
|
|
|
|
|
Total volume (Bbls)
|
—
|
|
|
1,825,000
|
|
(2)
|
Weighted average price per Bbl
|
$—
|
|
|
$52.18
|
|
|
(1) In February 2021, the Company terminated a total of 920,000 Bbls of short call swaption contracts for the second half of 2021 and simultaneously executed the full year 2022 short call swaption contracts shown in the table above.
(2) The short call swaption contracts shown in the table above have exercise expiration dates of December 31, 2021.
|
|
|
|
|
|
|
|
|
|
For the Full Year of
|
|
Natural gas contracts (Henry Hub)
|
2022
|
|
Collar contracts (two-way collars)
|
|
|
Total volume (MMBtu)
|
1,800,000
|
|
|
Weighted average price per MMBtu
|
|
|
Ceiling (short call)
|
$3.88
|
|
|
Floor (long put)
|
$2.78
|
|
|
Additionally, in January 2021, the Company paid approximately $3.1 million to terminate 184,000 Bbls of crude ICE Brent swaps. In February 2021, the Company executed offsetting crude ICE Brent swaps on 159,300 Bbls, resulting in a locked-in loss of approximately $2.9 million which the Company will pay as the applicable contracts settle.
Exercise of Warrants
In January and February 2021, certain entities that were issued September 2020 Warrants and November 2020 Warrants provided notice and exercised their outstanding warrants. As a result of these exercises, the Company issued a total of 6.4 million shares of its common stock in exchange for 8.4 million outstanding warrants determined on a net share settlement basis. The exercise of the September 2020 Warrants also resulted in settlement of the associated derivative liability which at December 31, 2020 was $79.4 million.
Note 19 - Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Estimated Reserves
For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
Extrapolation of performance history and material balance estimates were utilized by the Company’s both D&M and Ryder Scott to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.
The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
Proved reserves
|
|
2020
|
|
2019
|
|
2018
|
Oil (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
346,361
|
|
|
180,097
|
|
|
107,072
|
|
Purchase of reserves in place
|
|
—
|
|
|
183,382
|
|
|
30,756
|
|
Sales of reserves in place
|
|
(9,673)
|
|
|
(17,980)
|
|
|
—
|
|
Extensions and discoveries
|
|
25,678
|
|
|
45,663
|
|
|
67,763
|
|
Revisions to previous estimates
|
|
(49,336)
|
|
|
(33,136)
|
|
|
(16,051)
|
|
|
|
|
|
|
|
|
Production
|
|
(23,543)
|
|
|
(11,665)
|
|
|
(9,443)
|
|
End of period
|
|
289,487
|
|
|
346,361
|
|
|
180,097
|
|
Natural Gas (MMcf)
|
|
|
|
|
|
|
Beginning of period
|
|
757,134
|
|
|
350,466
|
|
|
179,410
|
|
Purchase of reserves in place
|
|
—
|
|
|
455,158
|
|
|
53,563
|
|
Sale of reserves in place
|
|
(20,389)
|
|
|
(86,856)
|
|
|
—
|
|
Extensions and discoveries
|
|
44,282
|
|
|
82,566
|
|
|
103,149
|
|
Revisions to previous estimates
|
|
(198,628)
|
|
|
(24,482)
|
|
|
29,791
|
|
|
|
|
|
|
|
|
Production
|
|
(40,801)
|
|
|
(19,718)
|
|
|
(15,447)
|
|
End of period
|
|
541,598
|
|
|
757,134
|
|
|
350,466
|
|
NGLs (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
67,462
|
|
|
—
|
|
|
—
|
|
Purchase of reserves in place
|
|
—
|
|
|
67,597
|
|
|
—
|
|
Sale of reserves in place
|
|
(3,049)
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
|
8,349
|
|
|
—
|
|
|
—
|
|
Revisions to previous estimates
|
|
30,214
|
|
|
—
|
|
|
—
|
|
Production
|
|
(6,850)
|
|
|
(135)
|
|
|
—
|
|
End of period
|
|
96,126
|
|
|
67,462
|
|
|
—
|
|
Total (MBoe)
|
|
|
|
|
|
|
Beginning of period
|
|
540,012
|
|
|
238,508
|
|
|
136,974
|
|
Purchase of reserves in place
|
|
—
|
|
|
326,838
|
|
|
39,683
|
|
Sale of reserves in place
|
|
(16,120)
|
|
|
(32,456)
|
|
|
—
|
|
Extensions and discoveries
|
|
41,407
|
|
|
59,424
|
|
|
84,955
|
|
Revisions to previous estimates
|
|
(52,227)
|
|
|
(37,216)
|
|
|
(11,086)
|
|
|
|
|
|
|
|
|
Production
|
|
(37,193)
|
|
|
(15,086)
|
|
|
(12,018)
|
|
End of period
|
|
475,879
|
|
|
540,012
|
|
|
238,508
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
Proved developed reserves
|
|
2020
|
|
2019
|
|
2018
|
Oil (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
152,687
|
|
|
92,202
|
|
|
51,920
|
|
End of period
|
|
128,923
|
|
|
152,687
|
|
|
92,202
|
|
Natural gas (MMcf)
|
|
|
|
|
|
|
Beginning of period
|
|
320,676
|
|
|
218,417
|
|
|
104,389
|
|
End of period
|
|
238,119
|
|
|
320,676
|
|
|
218,417
|
|
NGLs (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
24,844
|
|
|
—
|
|
|
—
|
|
End of period
|
|
43,315
|
|
|
24,844
|
|
|
—
|
|
Total proved developed reserves (MBoe)
|
|
|
|
|
|
|
Beginning of period
|
|
230,977
|
|
|
128,605
|
|
|
69,318
|
|
End of period
|
|
211,925
|
|
|
230,977
|
|
|
128,605
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
193,674
|
|
|
87,895
|
|
|
55,152
|
|
End of period
|
|
160,564
|
|
|
193,674
|
|
|
87,895
|
|
Natural gas (MMcf)
|
|
|
|
|
|
|
Beginning of period
|
|
436,458
|
|
|
132,049
|
|
|
75,021
|
|
End of period
|
|
303,479
|
|
|
436,458
|
|
|
132,049
|
|
NGLs (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
42,618
|
|
|
—
|
|
|
—
|
|
End of period
|
|
52,811
|
|
|
42,618
|
|
|
—
|
|
Total proved undeveloped reserves (MBoe)
|
|
|
|
|
|
|
Beginning of period
|
|
309,035
|
|
|
109,903
|
|
|
67,656
|
|
End of period
|
|
263,954
|
|
|
309,035
|
|
|
109,903
|
|
Total proved reserves
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
346,361
|
|
|
180,097
|
|
|
107,072
|
|
End of period
|
|
289,487
|
|
|
346,361
|
|
|
180,097
|
|
Natural gas (MMcf)
|
|
|
|
|
|
|
Beginning of period
|
|
757,134
|
|
|
350,466
|
|
|
179,410
|
|
End of period
|
|
541,598
|
|
|
757,134
|
|
|
350,466
|
|
NGLs (MBbls)
|
|
|
|
|
|
|
Beginning of period
|
|
67,462
|
|
|
—
|
|
|
—
|
|
End of period
|
|
96,126
|
|
|
67,462
|
|
|
—
|
|
Total proved reserves (MBoe)
|
|
|
|
|
|
|
Beginning of period
|
|
540,012
|
|
|
238,508
|
|
|
136,974
|
|
End of period
|
|
475,879
|
|
|
540,012
|
|
|
238,508
|
|
Total Proved Reserves
For the year ended December 31, 2020, the Company’s net decrease in proved reserves of 64.1 MMBoe was primarily due to the following:
•Increase of 41.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 11.7 MMBoe were proved developed reserves;
•Decrease of 52.2 MMBoe for revisions of previous estimates that were primarily comprised of:
◦26.2 MMBoe reduction due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31% as compared to December 31, 2019. Included in the decrease are 2.1 MMBoe associated with proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil;
◦24.2 MMBoe reduction due to anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts;
◦24.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation;
◦14.7 MMBoe increase due to the volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of the Company’s natural gas processing agreements which allow it to take title to NGLs resulting from the processing of its natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, the Company presented its reserve volumes for NGLs with natural gas;
◦7.5 MMBoe increase due to reduced assumptions for operational expenses as the Company continues to improve its field practices during the integration of the properties acquired from Carrizo;
•Decrease of 16.1 MMBoe for sales of reserves in place primarily associated with the ORRI Transaction and the sale of substantially all of the Company’s non-operated assets; and
•Decrease of 37.2 MMBoe for production.
For the year ended December 31, 2019, the Company’s net increase in proved reserves of 301.5 MMBoe was primarily due to the following:
•Increase of 326.8 MMBoe for purchases of reserves in place related to the acquisition of Carrizo Oil & Gas, Inc. in late 2019;
•Increase of 59.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed reserves;
•Decrease of 32.5 MMBoe as a result of sales of reserves in place, primarily associated with our Ranger Divestiture which totaled 27.1 MMBoe;
•Decrease of 37.2 MMBoe for revisions of previous estimates that were primarily comprised of:
◦21.7 MMBoe reduction due to the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates, primarily in the Midland Basin, as the Company advances larger scale development concepts across its multi-zone inventory;
◦9.8 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans, primarily related to certain fields within the Company’s Delaware Basin acreage, that were moved outside of the five-year development window primarily driven by the acquisition of Carrizo Oil & Gas, Inc. in December 2019, which afforded us the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency through larger scale development concepts as well as preserve our co-development philosophy to optimize resource capture from multiple zones;
◦5.7 MMBoe reduction due to pricing; and
•Decrease of 15.1 MMBoe for production.
For the year ended December 31, 2018, the Company’s net increase in proved reserves of 101.5 MMBoe was primarily due to the following:
•Increase of 85.0 MMBoe through extensions and discoveries, 28.2 MMBoe of which were proved developed reserves, as a result of development efforts in the Permian where the Company drilled 70 gross (57.5 net) wells;
•Increase of 39.7 MMBoe for purchases of reserves in place, of which 29.8 MMBoe were proved developed reserves, primarily related to the Company’s acquisition from Cimarex Energy Company in August 2018;
•Decrease of 11.1 MMBoe for revisions of previous estimates that were primarily comprised of:
◦9.1 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans that were moved outside of the five-year development window primarily driven by larger pad development concepts and co-development of zones;
◦2.0 MMBoe related to technical revisions of PUDs; and
•Decrease of 12.0 MMBoe for production.
Capitalized Costs
Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
2020
|
|
2019
|
Oil and natural gas properties:
|
|
(In thousands)
|
Evaluated properties
|
|
$7,894,513
|
|
|
$7,203,482
|
|
Unevaluated properties
|
|
1,733,250
|
|
|
1,986,124
|
|
Total oil and natural gas properties
|
|
9,627,763
|
|
|
9,189,606
|
|
Accumulated depreciation, depletion, amortization and impairment
|
|
(5,538,803)
|
|
|
(2,520,488)
|
|
Total oil and natural gas properties capitalized
|
|
$4,088,960
|
|
|
$6,669,118
|
|
Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
Acquisition costs:
|
|
(In thousands)
|
Evaluated properties
|
|
$—
|
|
|
$49,572
|
|
|
$347,305
|
|
Unevaluated properties
|
|
30,696
|
|
|
107,347
|
|
|
466,816
|
|
Development costs
|
|
379,900
|
|
|
189,259
|
|
|
259,410
|
|
Exploration costs
|
|
122,865
|
|
|
309,013
|
|
|
323,458
|
|
Total costs incurred
|
|
$533,461
|
|
|
$655,191
|
|
|
$1,396,989
|
|
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2020. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
Oil ($/Bbl)
|
|
$37.44
|
|
|
$53.90
|
|
|
$58.40
|
|
Natural gas ($/Mcf)
|
|
$1.02
|
|
|
$1.55
|
|
|
$3.64
|
|
NGLs ($/Bbl)
|
|
$11.10
|
|
|
$15.58
|
|
|
$—
|
|
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure
|
|
|
For the Year Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
Future cash inflows
|
|
$12,458,033
|
|
|
$20,891,469
|
|
|
$11,794,080
|
|
Future costs
|
|
|
|
|
|
|
Production
|
|
(5,433,496)
|
|
|
(6,717,088)
|
|
|
(2,923,959)
|
|
Development and net abandonment
|
|
(2,204,301)
|
|
|
(3,058,861)
|
|
|
(1,429,787)
|
|
Future net inflows before income taxes
|
|
4,820,236
|
|
|
11,115,520
|
|
|
7,440,334
|
|
Future income taxes
|
|
(65,405)
|
|
|
(941,768)
|
|
|
(782,470)
|
|
Future net cash flows
|
|
4,754,831
|
|
|
10,173,752
|
|
|
6,657,864
|
|
10% discount factor
|
|
(2,444,441)
|
|
|
(5,222,726)
|
|
|
(3,716,571)
|
|
Standardized measure of discounted future net cash flows
|
|
$2,310,390
|
|
|
$4,951,026
|
|
|
$2,941,293
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure
|
|
|
For the Year Ended December 31,
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
(In thousands)
|
Standardized measure at the beginning of the period
|
|
$4,951,026
|
|
|
$2,941,293
|
|
|
$1,556,682
|
|
Sales and transfers, net of production costs
|
|
(649,781)
|
|
|
(579,744)
|
|
|
(481,306)
|
|
Net change in sales and transfer prices, net of production costs
|
|
(2,719,579)
|
|
|
(387,970)
|
|
|
222,802
|
|
Net change due to purchases of in place reserves
|
|
—
|
|
|
2,975,296
|
|
|
554,697
|
|
Net change due to sales of in place reserves
|
|
(202,928)
|
|
|
(303,526)
|
|
|
—
|
|
Extensions, discoveries, and improved recovery, net of future production and development costs incurred
|
|
250,759
|
|
|
607,146
|
|
|
1,001,873
|
|
Changes in future development cost
|
|
361,008
|
|
|
205,398
|
|
|
40,483
|
|
Previously estimated development costs incurred
|
|
318,470
|
|
|
134,037
|
|
|
91,900
|
|
Revisions of quantity estimates
|
|
(671,800)
|
|
|
(420,488)
|
|
|
(167,096)
|
|
Accretion of discount
|
|
536,958
|
|
|
314,921
|
|
|
157,676
|
|
Net change in income taxes
|
|
383,999
|
|
|
(210,641)
|
|
|
(187,841)
|
|
Changes in production rates, timing and other
|
|
(247,742)
|
|
|
(324,696)
|
|
|
151,423
|
|
Aggregate change
|
|
(2,640,636)
|
|
|
2,009,733
|
|
|
1,384,611
|
|
Standardized measure at the end of period
|
|
$2,310,390
|
|
|
$4,951,026
|
|
|
$2,941,293
|
|
Note 20 - Supplemental Quarterly Financial Information (Unaudited)
The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
First Quarter (3)
|
|
Second Quarter (4)
|
|
Third Quarter (5)
|
|
Fourth Quarter (6)
|
|
|
(In thousands, except per share amounts)
|
Total operating revenues
|
|
$289,919
|
|
|
$157,234
|
|
|
$290,026
|
|
|
$295,968
|
|
Income (loss) from operations
|
|
47,860
|
|
|
(1,361,676)
|
|
|
(629,707)
|
|
|
(513,329)
|
|
Net income (loss)
|
|
216,565
|
|
|
(1,564,731)
|
|
|
(680,384)
|
|
|
(505,071)
|
|
Income (loss) available to common stockholders
|
|
216,565
|
|
|
(1,564,731)
|
|
|
(680,384)
|
|
|
(505,071)
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders per common share (1)(2)
|
|
|
|
|
|
|
|
|
Basic
|
|
$5.46
|
|
|
($39.41)
|
|
|
($17.12)
|
|
|
($12.71)
|
|
Diluted
|
|
$5.46
|
|
|
($39.41)
|
|
|
($17.12)
|
|
|
($12.71)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
First Quarter (7)
|
|
Second Quarter (8)
|
|
Third Quarter (9)
|
|
Fourth Quarter (10)
|
|
|
(In thousands, except per share amounts)
|
Total operating revenues
|
|
$153,047
|
|
|
$167,052
|
|
|
$155,378
|
|
|
$196,095
|
|
Income from operations
|
|
43,225
|
|
|
58,509
|
|
|
52,544
|
|
|
18,380
|
|
Net income (loss)
|
|
(19,543)
|
|
|
55,180
|
|
|
55,834
|
|
|
(23,543)
|
|
Income (loss) available to common stockholders
|
|
(21,367)
|
|
|
53,357
|
|
|
47,180
|
|
|
(23,543)
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders per common share (1) (2)
|
|
|
|
|
|
|
|
|
Basic
|
|
($0.94)
|
|
|
$2.34
|
|
|
$2.07
|
|
|
($0.95)
|
|
Diluted
|
|
($0.94)
|
|
|
$2.34
|
|
|
$2.07
|
|
|
($0.95)
|
|
(1) The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period.
(2) Income (loss) available to common stockholders per common share has been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020. See “Note 11 - Stockholders’ Equity” for additional information.
(3) First quarter of 2020 included the following:
a. $252.0 million gain on derivative contracts
b. $15.8 million of merger and integration expenses associated with the merger with Carrizo
(4) Second quarter of 2020 included the following:
a. $1.3 billion impairment of evaluated oil and gas properties
b. $127.0 million loss on derivative contracts
c. $8.1 million of merger and integration expenses associated with the merger with Carrizo
(5) Third quarter of 2020 included the following:
a. $685.0 million impairment of evaluated oil and gas properties
b. $27.0 million loss on derivative contracts
c. $2.5 million of merger and integration expenses associated with the merger with Carrizo
(6) Fourth quarter of 2020 included the following:
a. $585.8 million impairment of evaluated oil and gas properties
b. $125.7 million loss on derivative contracts
c. $1.6 million of merger and integration expenses associated with the merger with Carrizo
d. $170.4 million gain on extinguishment of debt
(7) First quarter of 2019 included the following:
a. $67.3 million loss on derivative contracts
(8) Second quarter of 2019 included the following:
a. $14.0 million gain on derivative contracts
(9) Third quarter of 2019 included the following:
a. $21.8 million gain on derivative contracts
b. $5.9 million of merger and integration expenses associated with the merger with Carrizo
c. $8.3 million loss on redemption of Preferred Stock
(10) Fourth quarter of 2019 included the following:
a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.
b. $68.4 million of merger and integration expenses associated with the merger with Carrizo
c. $30.7 million loss on derivative contracts
d. $4.9 million loss on extinguishment of debt