The following table sets forth average daily production by operating area for the periods indicated:
Balance Sheet Analysis31
The changes in our balance sheet from December 31, 2017 to June 30, 2018 are discussed below. |
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| Berry Corp. (Successor) |
| June 30, 2018 | | December 31, 2017 |
| (in thousands) |
Cash and cash equivalents | $ | 3,600 |
| | $ | 33,905 |
|
Accounts receivable, net | $ | 56,860 |
| | $ | 54,720 |
|
Restricted cash | $ | 19,710 |
| | $ | 34,833 |
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Other current assets | $ | 14,981 |
| | $ | 14,066 |
|
Property, plant & equipment, net | $ | 1,397,919 |
| | $ | 1,387,191 |
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Other noncurrent assets | $ | 22,086 |
| | $ | 21,687 |
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Accounts payable and accrued liabilities | $ | 113,170 |
| | $ | 97,877 |
|
Derivative instruments-current and long term | $ | 15,010 |
| | $ | 60,165 |
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Liabilities subject to compromise | $ | 19,710 |
| | $ | 34,833 |
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Long term debt | $ | 457,333 |
| | $ | 379,000 |
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Asset retirement obligation | $ | 88,575 |
| | $ | 94,509 |
|
Other noncurrent liabilties | $ | 12,862 |
| | $ | 3,704 |
|
Equity | $ | 808,496 |
| | $ | 859,310 |
|
See “Liquidity and Capital Resources” for a discussion about the changes in cash and cash equivalents, as well as long term debt.
The increase in accounts payable and accrued liabilities is largely the result of the new interest payment obligations on our 2026 Notes, issued in February of 2018 of $11 million.
The decrease in the derivative liability reflects the early termination and replacement of certain hedge contracts to move from a WTI-based position to a Brent-based position and to align our hedging program with higher current commodity prices.
The increase in long term debt represents the issuance of our 2026 Notes in February 2018 in the principal amount of $400 million and the usage of the proceeds to pay down the $379 million balance on our RBL Facility, partially offset by $66 million of additional RBL Facility borrowings in the second quarter of 2018.
The increase in other noncurrent liabilities represents an additional greenhouse gas liability of $9 million for production during the six months ended June 30, 2018 and which is due for payment more than one year from June 30, 2018.
The decrease in equity reflects the $20 million repurchase from certain general unsecured creditors of the right to receive shares of our common stock in settlement of their claims, the declaration of approximately $11 million in dividends on our Series A Preferred Stock and our results of operations.
Results of Operations
Results of Operations -Three Months Ended September 30, 2020 compared to Three Months Ended June 30, 2018 compared to Three Months Ended March 31, 2018.2020. |
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| Berry Corp. (Successor) | |
| Three Months Ended | Three Months Ended | | |
(in thousands) | June 30, 2018 | March 31, 2018 | $ Change | % Change |
Revenues and other: | | | | |
Oil, natural gas and NGL sales | $ | 137,385 |
| $ | 125,624 |
| $ | 11,761 |
| 9 | % |
Electricity sales | 5,971 |
| 5,453 |
| 518 |
| 9 | % |
(Losses) gains on oil and natural gas derivatives | (78,143 | ) | (34,644 | ) | (43,499 | ) | 126 | % |
Marketing and other revenues | 769 |
| 851 |
| (82 | ) | (10 | )% |
| 65,982 |
| 97,284 |
| (31,302 | ) | (32 | )% |
Expenses and other: | | | | |
Lease operating expenses | 41,517 |
| 44,303 |
| (2,786 | ) | (6 | )% |
Electricity generation expenses | 3,135 |
| 4,590 |
| (1,455 | ) | (32 | )% |
Transportation expenses | 2,343 |
| 2,978 |
| (635 | ) | (21 | )% |
Marketing expenses | 407 |
| 580 |
| (173 | ) | (30 | )% |
General and administrative expenses | 12,482 |
| 11,985 |
| 497 |
| 4 | % |
Depreciation, depletion, amortization and accretion | 21,859 |
| 18,429 |
| 3,430 |
| 19 | % |
Taxes, other than income taxes | 8,715 |
| 8,256 |
| 459 |
| 6 | % |
(Gains) losses on sale of assets and other, net | 123 |
| — |
| 123 |
| |
| 90,581 |
| 91,121 |
| (540 | ) | (1 | )% |
Other income and (expenses): | | | | |
Interest expense | (9,155 | ) | (7,796 | ) | (1,359 | ) | 17 | % |
Other, net | (239 | ) | 27 |
| (266 | ) | (985 | )% |
Reorganization items, net | 456 |
| 8,955 |
| (8,499 | ) | (95 | )% |
Income (loss) before income taxes | (33,537 | ) | 7,349 |
| (40,886 | ) | (556 | )% |
Income tax expense (benefit) | (5,476 | ) | 939 |
| (6,415 | ) | (683 | )% |
Net income (loss) | (28,061 | ) | 6,410 |
| (34,471 | ) | (538 | )% |
Dividends on Series A Preferred Stock | (5,650 | ) | (5,650 | ) | — |
| — | % |
Net income (loss) available to common stockholders | $ | (33,711 | ) | $ | 760 |
| $ | (34,471 | ) | (4,536 | )% |
| | | | |
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| Three Months Ended | | | | | | |
| September 30, 2020 | | June 30, 2020 | | $ Change | | % Change | |
| (in thousands) | | | | | | |
Revenues and other: | | | | | | | | | |
Oil, natural gas and NGL sales | $ | 92,239 | | | $ | 70,515 | | | $ | 21,724 | | | 31 | % | | |
Electricity sales | 8,744 | | | 4,884 | | | 3,860 | | | 79 | % | | |
(Losses) gains on oil derivatives | (11,564) | | | (42,267) | | | 30,703 | | | (73) | % | | |
Marketing and other revenues | 330 | | | 321 | | | 9 | | | 3 | % | | |
| | | | | | | | | |
Total revenues and other | $ | 89,749 | | | $ | 33,453 | | | $ | 56,296 | | | 168 | % | | |
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Revenues and Other
Oil, natural gas and NGL sales increased $12by $22 million, or 9%31%, to approximately $137$92 million for the three months ended JuneSeptember 30, 20182020, compared to the three months ended March 31, 2018.June 30, 2020. The increase reflects improvedwas driven by $24 million of higher oil prices and a slight increase in production.partially offset by lower oil volumes.
Electricity sales represent sales to utilities, and increased by approximately $0.5$4 million, or 9%79%, to approximately $6$9 million for the three months ended September 30, 2020 compared to the three months ended June 30, 2020. The increase primarily reflected higher unit sales prices that resulted from a seasonal increase in capacity payments and higher natural gas prices during the third quarter 2020 compared to the second quarter 2020.
Gain or loss on oil derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement gains for the three months ended September 30, 2020 and June 30, 2020 were $36 million and $59 million, respectively. The quarter-over-quarter decrease in settlement gains was driven by higher oil prices relative to the derivative fixed contract prices in the third quarter compared to those of the second quarter of 2020. Each of these quarters had the same average derivative fixed prices and daily notional volumes. The mark-to-market non-cash loss of $48 million for the three months ended September 30, 2020 was due to higher futures prices relative to the derivative fixed prices at September 30, 2020 compared to the non-cash loss of $101 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018. The increase was primarily due to higher seasonal prices.
Losses on oil and natural gas derivatives were approximately $78 million for the three months ended June 30, 2018 compared to losses of approximately $35 million for the three months ended March 31, 2018. The increase represents improved commodity prices relative to the fixed prices of our derivative contracts.
2020.
Marketing and other revenues for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018. Marketing revenues in these periods primarily represent sales of third-party natural gas and were comparable for these periods.the periods presented.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | | | $ Change | | % Change |
| September 30, 2020 | | June 30, 2020 | | | |
| (in thousands, except expenses per Boe) | | | | | | |
Expenses and other: | | | | | | | | | |
Lease operating expenses | $ | 45,243 | | | $ | 40,733 | | | | | $ | 4,510 | | | 11 | % |
Electricity generation expenses | 4,217 | | | 3,022 | | | | | 1,195 | | | 40 | % |
Transportation expenses | 1,768 | | | 1,789 | | | | | (21) | | | (1) | % |
Marketing expenses | 326 | | | 280 | | | | | 46 | | | 16 | % |
General and administrative expenses | 19,173 | | | 18,777 | | | | | 396 | | | 2 | % |
Depreciation, depletion and amortization | 35,905 | | | 37,512 | | | | | (1,607) | | | (4) | % |
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Taxes, other than income taxes | 9,913 | | | 10,449 | | | | | (536) | | | (5) | % |
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(Gain) losses on natural gas derivatives | (15,784) | | | 925 | | | | | (16,709) | | | n/a |
Other operating expenses (income) | 1,648 | | | (1,192) | | | | | 2,840 | | | n/a |
Total expenses and other | 102,409 | | | 112,295 | | | | | (9,886) | | | (9) | % |
Other (expenses) income: | | | | | | | | | |
Interest expense | (8,391) | | | (8,676) | | | | | 285 | | | (3) | % |
Other, net | (3) | | | (6) | | | | | 3 | | | (50) | % |
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Loss before income taxes | (21,054) | | | (87,524) | | | | | 66,470 | | | (76) | % |
Income tax (benefit) expense | (2,190) | | | (22,623) | | | | | 20,433 | | | (90) | % |
Net loss | $ | (18,864) | | | $ | (64,901) | | | | | $ | 46,037 | | | (71) | % |
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Expenses per Boe:(1) | | | | | | | | | |
Lease operating expenses | $ | 17.83 | | | $ | 15.37 | | | | | $ | 2.46 | | | 16 | % |
Electricity generation expenses | 1.66 | | | 1.14 | | | | | 0.52 | | | 46 | % |
Electricity sales(1) | (3.45) | | | (1.84) | | | | | (1.61) | | | 88 | % |
Transportation expenses | 0.69 | | | 0.67 | | | | | 0.02 | | | 3 | % |
Transportation sales(1) | — | | | (0.01) | | | | | 0.01 | | | (100) | % |
Marketing expenses | 0.13 | | | 0.11 | | | | | 0.02 | | | 18 | % |
Marketing revenues(1) | (0.13) | | | (0.11) | | | | | (0.02) | | | 18 | % |
Derivatives settlements paid for gas purchases(1) | 0.24 | | | 2.78 | | | | | (2.54) | | | (91) | % |
Total operating expenses | $ | 16.97 | | | $ | 18.11 | | | | | $ | (1.14) | | | (6) | % |
Total unhedged operating expenses(2) | $ | 16.73 | | | $ | 15.33 | | | | | $ | 1.40 | | | 9 | % |
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Total non-energy operating expenses(4) | $ | 13.34 | | | $ | 12.81 | | | | | $ | 0.53 | | | 4 | % |
Total energy operating expenses(5) | $ | 3.65 | | | $ | 5.30 | | | | | $ | (1.65) | | | (31) | % |
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General and administrative expenses(3) | $ | 7.56 | | | $ | 7.09 | | | | | $ | 0.47 | | | 7 | % |
Depreciation, depletion and amortization | $ | 14.15 | | | $ | 14.16 | | | | | $ | (0.01) | | | — | % |
Taxes, other than income taxes | $ | 3.91 | | | $ | 3.94 | | | | | $ | (0.03) | | | (1) | % |
__________
(1) We report sales of electricity, transportation and marketing and transportation activities (as applicable)sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales reported in "Other Revenues", relate to water and other liquids that we transport on our systems on behalf of third parties.
parties and have not been significant to date. Operating expenses as defined above, decreased to $16.89also include the effect of derivative settlements (received or paid) for gas purchases.
(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $2.08 per Boe for the quarter ended June 30, 2018 from $19.61 per Boe for the quarter ended March 31, 2018, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $3 million, or 6%, to approximately $42 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018. The decrease was primarily due to lower well servicing activity, lower fuel gas costs and increased oil inventory caused by market disruptions in Utah in the quarter ended June 30, 2018. For the same reasons, lease operating expenses per Boe decreased to $17.24$1.77 per Boe for the three months ended September 30, 2020 and June 30, 2018 from $18.80 per Boe for the three months ended March 31, 2018.
Electricity generation expenses decreased by approximately $1.5 million or 32% for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to lower fuel gas costs and reduced cogen operating costs due to replacement of a third party service provider with internal staffing.
Transportation expenses decreased by approximately $0.6 million, or 21%, to approximately $2 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018, primarily due to reduced costs for use of certain third-party systems.
Marketing expenses for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018.
General and administrative expenses increased by approximately $0.5 million, or 4%, to approximately $12 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to increased costs related to preparing to be a public company. The increase in absolute dollars incurred resulted in slightly higher general and administrative expenses of $5.18 per Boe for the three months ended June 30, 2018, compared to $5.09 per Boe for the three months ended March 31, 2018. For the three months ended June 30, 2018 and March 31, 2018, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.7 million and $2.0 million, respectively, and non-cash stock compensation costs of approximately $1.3 million and $1.0 million,2020, respectively.
Depreciation, depletion(4) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and amortization ("DD&A") increased by approximately $3 million, or 19%, to approximately $22 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to increased DD&A rates, slightly higher productiongas purchase derivative settlement (gains) losses.
(5) Total energy operating expenses equals fuel and increased asset retirement accretion expense.
Taxes, Other Than Income Taxes
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| Berry Corp. (Successor) |
| Three Months Ended | Three Months Ended | |
| June 30, 2018 | March 31, 2018 | Variance |
(in thousands) | | | |
Severance taxes | $ | 2,997 |
| $ | 2,764 |
| $ | 233 |
|
Ad valorem and property taxes | 3,141 |
| 3,417 |
| (276 | ) |
Greenhouse gas allowances | 2,577 |
| 2,075 |
| 502 |
|
| $ | 8,715 |
| $ | 8,256 |
| $ | 459 |
|
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For the three months ended June 30, 2018 compared to the three months ended March 31, 2018, greenhouse gas allowance costs increased due to the higher unit cost and increased activity.
Other income and (expenses)
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| Berry Corp. (Successor) |
| Three Months Ended | Three Months Ended | |
| June 30, 2018 | March 31, 2018 | Variance |
(in thousands) | | | |
Interest expense, net of amounts capitalized | $ | (9,155 | ) | $ | (7,796 | ) | $ | (1,359 | ) |
Other, net | (239 | ) | 27 |
| (266 | ) |
| $ | (9,394 | ) | $ | (7,769 | ) | $ | (1,625 | ) |
Interest expense increased for the three months ended June 30, 2018 by $1.4 million or 17%, compared to the three months ended March 31, 2018, due to increased borrowings on the RBL Facility and three months of the interest on the 2026 Notes in the second quarter versus one and a half months in the first quarter.
The following table summarizes the components of reorganization items included in the statement of operations: |
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| Berry Corp. (Successor) |
| Three Months Ended | Three Months Ended | |
(in thousands) | June 30, 2018 | March 31, 2018 | Variance |
Return of Undistributed Funds from Cash Distribution Pool | $ | — |
| $ | 9,000 |
| $ | (9,000 | ) |
Refund of pre-emergence prepaid costs | — |
| 579 |
| (579 | ) |
Legal and other professional advisory fees | (1,178 | ) | (624 | ) | (554 | ) |
Gain on resolution of pre-emergence liabilities | 1,634 |
| — |
| 1,634 |
|
| $ | 456 |
| $ | 8,955 |
| $ | (8,499 | ) |
Reorganization items, net consisted of a gain of approximately $0.5 million for the three months ended June 30, 2018. The gain was primarily due to the resolution of certain pre-emergence liabilities, partially offset by legal and other professional fees. For the three months ended March 31, 2018, the gain of $9 million reflected the return of undistributed funds reserved forpurchase derivative settlement of claims of general unsecured creditors.(gains) losses less electricity sales.
Income taxes
The three months ended June 30, 2018 had a $5.5 million tax benefit compared to income tax expense of $0.9 million for the three months ended March 31, 2018. The effective tax rate was 16% for the three months ended June 30, 2018 and 13% for the three months ended March 31, 2018.
Results of Operations - Three Months Ended June 30, 2018 compared to Three Months Ended June 30, 2017. |
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| Berry Corp. (Successor) | |
| Three Months Ended | Three Months Ended | | |
(in thousands) | June 30, 2018 | June 30, 2017 | $ Change | % Change |
Revenues and other: | | | | |
Oil, natural gas and NGL sales | $ | 137,385 |
| $ | 101,884 |
| $ | 35,501 |
| 35 | % |
Electricity sales | 5,971 |
| 5,712 |
| 259 |
| 5 | % |
(Losses) gains on oil and natural gas derivatives | (78,143 | ) | 23,962 |
| (102,105 | ) | (426 | )% |
Marketing and other revenues | 769 |
| 3,164 |
| (2,395 | ) | (76 | )% |
| 65,982 |
| 134,722 |
| (68,740 | ) | (51 | )% |
Expenses and other: | | |
|
| |
Lease operating expenses | 41,517 |
| 45,726 |
| (4,209 | ) | (9 | )% |
Electricity generation expenses | 3,135 |
| 4,465 |
| (1,330 | ) | (30 | )% |
Transportation expenses | 2,343 |
| 9,404 |
| (7,061 | ) | (75 | )% |
Marketing expenses | 407 |
| 730 |
| (323 | ) | (44 | )% |
General and administrative expenses | 12,482 |
| 22,257 |
| (9,775 | ) | (44 | )% |
Depreciation, depletion, amortization and accretion | 21,859 |
| 20,549 |
| 1,310 |
| 6 | % |
Taxes, other than income taxes | 8,715 |
| 10,249 |
| (1,534 | ) | (15 | )% |
(Gains) losses on sale of assets and other, net | 123 |
| 5 |
| 118 |
| 2,360 | % |
| 90,581 |
| 113,385 |
| (22,804 | ) | (20 | )% |
Other income and (expenses): | | |
|
| |
Interest expense | (9,155 | ) | (4,885 | ) | (4,270 | ) | 87 | % |
Other, net | (239 | ) | 2,916 |
| (3,155 | ) | (108 | )% |
Reorganization items, net | 456 |
| 713 |
| (257 | ) | (36 | )% |
Income (loss) before income taxes | (33,537 | ) | 20,081 |
| (53,618 | ) | (267 | )% |
Income tax expense (benefit) | (5,476 | ) | 7,961 |
| (13,437 | ) | (169 | )% |
Net income (loss) | (28,061 | ) | 12,120 |
| (40,181 | ) | (332 | )% |
Dividends on Series A Preferred Stock | (5,650 | ) | (5,404 | ) | (246 | ) | 5 | % |
Net income (loss) available to common stockholders | $ | (33,711 | ) | $ | 6,716 |
| $ | (40,427 | ) | (602 | )% |
| | | | |
Revenues and Other
Oil, natural gas and NGL sales increased $36 million, or 35% to approximately $137 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017. The increase reflects improved oil prices and an increased mix of oil production compared to gas production as a result of the Hill Acquisition and Hugoton Disposition, partially offset by decreased production on an oil-equivalent basis.
Electricity sales represent sales to utilities and increased by approximately $0.3 million, or 5%, to approximately $6 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. The increase was primarily due to higher volumes sold externally as a result of lower downtime at our cogens in the three months ended June 30, 2018 than the three months ended June 30, 2017.
Losses on oil and natural gas derivatives were approximately $78 million for the three months ended June 30, 2018 compared to approximately $24 million of gains for the three months ended June 30, 2017. Losses on oil and natural gas derivatives for the three months ended June 30, 2018 were primarily due to an increase in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commodity prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues decreased by approximately $2 million, or 76%, to approximately $0.8 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. Marketing revenues in these periods primarily represent sales of third-party natural gas and were comparable for these periods. Other revenues in 2017 comprised mostly helium sales, all of which were derived from our Hugoton asset prior to its disposition in July 2017.
Expenses and Other
WeIn accordance with GAAP, we report sales of electricity, marketing and transportation activities (as applicable) separately in our financial statements as revenues. However, these revenues are viewed and used internally in calculating operating expenses, which are used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
Operating expenses are defined above in “How We Plan and Evaluate Operations”. On a hedged basis, operating expenses, decreased 6% or $1.14 per Boe to $16.97 in the third quarter 2020 from $18.11 in the second quarter 2020. The decrease was largely due to higher electricity sales resulting from higher seasonal capacity payments. During the third quarter 2020, we sustained the cost savings achieved in the first half of 2020, as hedged fuel and non-fuel costs were essentially flat to the second quarter 2020. On an unhedged basis, operating expenses increased by 9% or $1.40 per Boe to $16.73 for the third quarter 2020, compared to $15.33 for the second quarter 2020. This increase was driven by higher unhedged fuel costs in comparison to the second quarter 2020.
Lease operating expenses per Boe increased to $17.83, for the three months ended September 30, 2020, a 16% or $2.46 per Boe increase compared to $15.37 per Boe for the three months ended June 30, 2020 driven by higher unhedged fuel costs related to our California steam operations. Unhedged fuel cost increased $2.31 per Boe, or 65% in the third quarter 2020 from $3.54 for the three months ended June 30, 2020. Non-fuel lease operating expense increased $0.15 per Boe due to lower sales volumes while spending on an absolute dollar basis was $1 million lower including lower facilities gas compression, oil and water processing costs. Lease operating expenses include fuel, maintenance, labor including supervision, vehicles, workover expenses, field office, and tools and supplies. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Electricity generation expenses increased approximately 46% to $1.66 per Boe for the three months ended September 30, 2020, compared to $1.14 per Boe for the three months ended June 30, 2020 due to higher natural gas costs described above and lower sales volumes. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Gains and losses on natural gas purchase derivatives resulted in a $16 million gain for the three months ended September 30, 2020 and a loss of $1 million in the three months ended June 30, 2020. Settlement losses for each of the three months ended September 30, 2020 and June 30, 2020 were $1 million and $7 million, or $0.24 and $2.78 per Boe, respectively, and decreased due to higher gas prices. The mark-to-market valuation gain for the three months ended September 30, 2020 was $17 million compared to a $6 million gain for the prior quarter. Generally, because we are the fixed price payer on these natural gas swaps, increases in the associated futures prices will result in valuation gains.
Transportation expenses were essentially flat at $0.69 per Boe for the three months ended September 30, 2020 compared to $0.67 per Boe for the three months ended June 30, 2020.
Marketing expenses were comparable for the three months ended September 30, 2020 and June 30, 2020.
General and administrative expenses increased by $0.4 million, or 2%, to $19 million for the three months ended September 30, 2020, compared to the three months ended June 30, 2020. For the three months ended September 30, 2020 and June 30, 2020, general and administrative expenses included non-cash stock compensation costs of approximately $3.8 million and $4.4 million, respectively, and certain non-recurring costs of approximately $1.5 million and $0.3 million, respectively. Non-cash stock compensation expense declined from the second quarter 2020 due to the awards that expired or were forfeited in the third quarter 2020 and had been fully expensed at that time. The third quarter 2020 non-recurring costs mainly consisted of costs related to the retirement of former Chief Operating Officer ("COO") and hiring of new COO. Less than 10% of our overhead is capitalized and thus excluded from general and administrative expenses.
Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, were $14 million for each of the three month periods ended September 30, 2020 and June 30, 2020. These cost levels include a slight reduction in headcount since early 2020, although none of these reductions are a result of the current economic environment. Please see “-Non-GAAP Financial Measures” for a reconciliation of adjusted general and administrative expense to general and administrative expenses, the most directly comparable financial measures calculated and presented in accordance with GAAP.
DD&A decreased by $2 million or 4% to approximately $36 million for the three months ended September 30, 2020 compared to the three months ended June 30, 2020. This decrease is attributable to the reduced sales volumes period-over-period.
Taxes, Other Than Income Taxes
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| Three Months Ended | | $ Change | | % Change |
| September 30, 2020 | | June 30, 2020 | |
| (per Boe) | | | | |
Severance taxes | $ | 0.82 | | | $ | 0.70 | | | $ | 0.12 | | | 17 | % |
Ad valorem and property taxes | 1.60 | | | 1.39 | | | 0.21 | | | 15 | % |
Greenhouse gas allowances | 1.49 | | | 1.85 | | | (0.36) | | | (19) | % |
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Total taxes other than income taxes | $ | 3.91 | | | $ | 3.94 | | | $ | (0.03) | | | (1) | % |
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Taxes, other than income taxes, decreased in the three months ended September 30, 2020 by $0.03 per Boe, or 1%, to $3.91. Greenhouse gas ("GHG") costs were lower in the third quarter of 2020 as the prices remained relatively flat while the emission volumes declined. During the third quarter 2020, we experienced higher property tax rates, as well as higher severance tax rates due to the expiration of certain deductions. These changes were also impacted by the decrease in sales volumes in the third quarter 2020.
Other Operating (Income) Expenses
Other operating expenses for the three months ended September 30, 2020 was $2 million comprised mainly of excess abandonment costs and excess storage capacity obtained in response to global oil storage concerns. Other operating income of $1 million for the three months ended June 30, 2020 included refunds from sales taxes paid in prior years and resolved claims from our prior parent company's bankruptcy.
Interest Expense
Interest expense was relatively flat at $8 million for each of the three months ended September 30, 2020 and June 30, 2020.
Income Tax (Benefit) Expense
Our effective tax rate was approximately 10% and 26% for the three months ended September 30, 2020 and June 30, 2020, respectively. The rate in the third quarter 2020 was negatively impacted by adjustments to our
valuation allowance during the quarter related to current year losses and expected future realizability of deferred tax assets.
Three Months Ended September 30, 2020 compared to Three Months Ended September 30, 2019.
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| Three Months Ended September 30, | | $ Change | | % Change |
| 2020 | | 2019 | |
| (in thousands) | | | | |
Revenues and other: | | | | | | | |
Oil, natural gas and NGL sales | $ | 92,239 | | | $ | 141,250 | | | $ | (49,011) | | | (35) | % |
Electricity sales | 8,744 | | | 7,460 | | | 1,284 | | | 17 | % |
(Losses) gains on oil derivatives | (11,564) | | | 45,509 | | | (57,073) | | | n/a |
Marketing and other revenues | 330 | | | 453 | | | (123) | | | (27) | % |
Total revenues and other | $ | 89,749 | | | $ | 194,672 | | | $ | (104,923) | | | (54) | % |
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Revenues and Other
Oil, natural gas and NGL sales decreased by $49 million, or 35% to approximately $92 million for the three months ended September 30, 2020 when compared to the three months ended September 30, 2019. This variance was driven by $40 million of lower commodity prices, as well as $9 million of lower volumes.
Electricity sales represent sales to utilities, and increased by $1.3 million, or 17%, to approximately $9 million for the three months ended September 30, 2020 when compared to the three months ended September 30, 2019. The increase was equally split between higher unit sales prices and higher sales volumes.
Gain or loss on oil derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement gains for the three months ended September 30, 2020 and September 30, 2019 were $36 million and $17 million, respectively. The quarter-over-quarter increase in settlement gains was driven by lower oil prices relative to our derivative fixed contract prices and more volumes hedged in the third quarter of 2020 compared to the third quarter of 2019. The mark-to-market non-cash loss of $48 million for the three months ended September 30, 2020 was due to higher futures prices relative to our derivative fixed contract prices at September 30, 2020. The mark-to-market non-cash gain of $29 million for the three months ended September 30, 2019, was primarily due to lower futures prices relative to our derivative fixed contract prices at September 30, 2019.
Marketing and other revenues were comparable for the periods presented.
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| Three Months Ended September 30, | | $ Change | | % Change |
| 2020 | | 2019 | |
| (in thousands, except expenses per Boe) | | | | |
Expenses and other: | | | | | | | |
Lease operating expenses | $ | 45,243 | | | $ | 50,957 | | | $ | (5,714) | | | (11) | % |
Electricity generation expenses | 4,217 | | | 3,781 | | | 436 | | | 12 | % |
Transportation expenses | 1,768 | | | 2,067 | | | (299) | | | (14) | % |
Marketing expenses | 326 | | | 398 | | | (72) | | | (18) | % |
General and administrative expenses | 19,173 | | | 16,434 | | | 2,739 | | | 17 | % |
Depreciation, depletion and amortization | 35,905 | | | 27,664 | | | 8,241 | | | 30 | % |
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Taxes, other than income taxes | 9,913 | | | 9,249 | | | 664 | | | 7 | % |
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(Gain) losses on natural gas derivatives | (15,784) | | | 3,008 | | | (18,792) | | | n/a |
Other operating expenses (income) | 1,648 | | | (550) | | | 2,198 | | | n/a |
Total expenses and other | 102,409 | | | 113,008 | | | (10,599) | | | (9) | % |
Other (expenses) income: | | | | | | | |
Interest expense | (8,391) | | | (8,597) | | | 206 | | | (2) | % |
Other, net | (3) | | | (77) | | | 74 | | | (96) | % |
Reorganization items, net | — | | | (170) | | | 170 | | | (100) | % |
(Loss) income before income taxes | (21,054) | | | 72,820 | | | (93,874) | | | n/a |
Income tax (benefit) expense | (2,190) | | | 20,171 | | | (22,361) | | | n/a |
Net (loss) income | $ | (18,864) | | | $ | 52,649 | | | $ | (71,513) | | | n/a |
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Expenses per Boe:(1) | | | | | | | |
Lease operating expenses | $ | 17.83 | | | $ | 18.74 | | | $ | (0.91) | | | (5) | % |
Electricity generation expenses | 1.66 | | | 1.39 | | | 0.27 | | | 19 | % |
Electricity sales(1) | (3.45) | | | (2.74) | | | (0.71) | | | 26 | % |
Transportation expenses | 0.69 | | | 0.76 | | | (0.07) | | | (9) | % |
Transportation sales(1) | — | | | (0.01) | | | 0.01 | | | (100) | % |
Marketing expenses | 0.13 | | | 0.15 | | | (0.02) | | | (13) | % |
Marketing revenues(1) | (0.13) | | | (0.15) | | | 0.02 | | | (13) | % |
Derivatives settlements paid for gas purchases(1) | 0.24 | | | 0.77 | | | (0.53) | | | (69) | % |
Total operating expenses | $ | 16.97 | | | $ | 18.90 | | | $ | (1.93) | | | (10) | % |
Total unhedged operating expenses(2) | $ | 16.73 | | | $ | 18.13 | | | $ | (1.40) | | | (8) | % |
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Total non-energy operating expenses(4) | $ | 13.34 | | | $ | 14.09 | | | $ | (0.75) | | | (5) | % |
Total energy operating expenses(5) | $ | 3.65 | | | $ | 4.81 | | | $ | (1.16) | | | (24) | % |
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General and administrative expenses(3) | $ | 7.56 | | | $ | 6.04 | | | $ | 1.52 | | | 25 | % |
Depreciation, depletion and amortization | $ | 14.15 | | | $ | 10.17 | | | $ | 3.98 | | | 39 | % |
Taxes, other than income taxes | $ | 3.91 | | | $ | 3.40 | | | $ | 0.51 | | | 15 | % |
__________
(1) We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery.
We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses as defined above, decreased to $16.89also include the effect of derivative settlements (received or paid) for gas purchases.
(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $2.08 per Boe for the quarter ended June 30, 2018 from $17.20 per Boe for the quarter ended June 30, 2017, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $4 million, or 9%, to approximately $42 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. The decrease was primarily due to a decrease in the price of fuel gas used in operations. Further, lease operating expenses per Boe increased to $17.24$0.91 per Boe for the three months ended JuneSeptember 30, 2018 from $14.622020 and September 30, 2019, respectively.
(4) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(5) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
Expenses and Other
Operating expenses, including hedge effects, decreased by 10% or $1.93 per Boe to $16.97 per Boe for the third quarter 2020 compared to $18.90 per Boe for the third quarter 2019. This decrease included $0.91 per Boe lower lease operating expenses and $0.44 of higher electricity sales margin and $0.53 per Boe of more favorable gas hedge settlements in 2020. Additionally, operating expenses, on an unhedged basis, were 8%, or $1.40 per Boe lower for the three months ended September 30, 2020 compared to the three months ended September 30, 2019 due to these same non-hedge factors.
As a result of our 2020 cost savings and efficiency initiatives, we experienced a positive and substantial impact on lease operating expenses in 2020 when compared to 2019. Lease operating expenses were $17.83 per Boe for the three months ended JuneSeptember 30, 2017, primarily due to increased oil production to 80% of total production from 56% of total production as2020, a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) which adversely impacted costs per Boe. Replacing low cost natural gas production with oil production in 2017 had a disproportionate impact (oil volume rose 10% and gas volume decreased 62% but cost5% or $0.91 per Boe rose 18%), on our costs per Boe when comparing these respective periods.
Electricity generation expenses decreased approximately $1 million or 30%reduction compared to $3 million$18.74 for the three months ended JuneSeptember 30, 20182019. Non-fuel lease operating expense decreases included $0.65 of lower costs related to maintenance, as well as $0.46 in facilities gas compression and the three months ended June 30, 2017, primarily due to a decreaseoil and water processing costs. On an absolute dollar basis, non-fuel lease operating expenses declined $4 million in the price of natural gas.
Transportation expenses decreased by approximately $7 million, or 75%, to approximately $2 million for the three months ended June 30, 2018,third quarter 2020 compared to the three months ended June 30, 2017, primarilysame period last year. Lease operating fuel cost related to our California steam operations were unchanged during the third quarter 2020 from the same quarter 2019 due to the Hugoton Disposition of gas properties,more efficient steam consumption per Boe, which required significant transportation expense because gas transportation is generally borne by the seller and oil transportation costs are borne by the buyer.
Marketing expenses decreased $0.3 million or 44% to $0.4 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the decrease inoffset higher natural gas prices. Lease operating expenses include fuel, maintenance, labor including supervision, vehicles, workover expenses, field office, tools and supplies. Fuel costs excluded the effects of natural gas derivative settlements discussed below.
General and administrativeElectricity generation expenses decreased byincreased approximately $10 million, or 44%,19% to approximately $12 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the management change in conjunction with our emergence from bankruptcy. The reduction in absolute dollars spent, as well as lower production volumes resulted in lower general and administrative expenses of $5.18$1.66 per Boe for the three months ended JuneSeptember 30, 2018,2020 from $1.39 per Boe for the same period in 2019 primarily due to higher natural gas costs previously mentioned, as well as the impact of lower Boe volumes. Fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements.
Gains and losses on natural gas purchase derivatives for the three months ended September 30, 2020 and September 30, 2019 resulted in a gain of $16 million and a loss of $3 million, respectively. Settlement losses for each of the three months ended September 30, 2020 and 2019, were $1 million and $2 million, or $0.24 and $0.77 per Boe, respectively, and decreased due to higher gas prices during 2020. The mark-to-market valuation gain for the three months ended September 30, 2020 was $17 million compared to $7.11$1 million of loss for the same period in 2019, consistent with the changes in futures prices at the end of each period. Because we are the fixed price payer on these natural gas swaps, generally, increases in the associated price index creates valuation gains.
Transportation expenses were down $0.07 per Boe to $0.69 for the three months ended September 30, 2020 compared to the three months ended September 30, 2019 as a result of lower natural gas sales volumes.
Marketing expenses decreased 13% to $0.13 per Boe for the three months ended JuneSeptember 30, 2017.2020, compared to $0.15 per Boe for the three months ended September 30, 2019 mostly due to lower gas prices.
General and administrative expenses increased $3 million, or 17%, to approximately $19 million for the three months ended September 30, 2020 compared to the three months ended September 30, 2019. For the three months
ended JuneSeptember 30, 2018,2020 and September 30, 2019, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.7 million and non-cash stock compensation costs of approximately $1.3 million. For the three months ended June 30, 2017,$3.8 million and $2.3 million, respectively, and non-recurring costs of approximately $1.5 million and $0.2 million, respectively.
Adjusted general and administrative expenses, included non-recurring restructuring and other costs of approximately $17 million and nowhich exclude non-cash stock compensation costs.costs and non-recurring costs, were $14 million for each of the three month periods ended September 30, 2020 and September 30, 2019.
DD&A increased by approximately $1$8 million, or 6%30%, to approximately $22$36 million for the three months ended JuneSeptember 30, 20182020 compared to the three months ended JuneSeptember 30, 2017,2019, primarily due to higher depreciation and depletion rates for 2020, partially offset by lower sales volumes. On a per Boe basis, period-over-period DD&A increased $3.98 to $14.15 from $10.17 due to our increasing capital development program throughout 2019 and the Hill Acquisition. The Hill property which had a higher depletion rate than the Hugoton field.
first quarter of 2020, compared to prior periods.
Taxes, Other Than Income Taxes
| | | Berry Corp. (Successor) | | Three Months Ended September 30, | | $ Change | | % Change |
| Three Months Ended | | | 2020 | | 2019 | |
| June 30, 2018 | June 30, 2017 | Variance | | (per Boe) | | | | |
(in thousands) | | |
Severance taxes | $ | 2,997 |
| $ | 2,466 |
| $ | 531 |
| Severance taxes | $ | 0.82 | | | $ | 0.67 | | | $ | 0.15 | | | 22 | % |
Ad valorem and property taxes | 3,141 |
| 4,498 |
| (1,357 | ) | Ad valorem and property taxes | 1.60 | | | 1.23 | | | 0.37 | | | 30 | % |
Greenhouse gas allowances | 2,577 |
| 3,285 |
| (708 | ) | Greenhouse gas allowances | 1.49 | | | 1.50 | | | (0.01) | | | (1) | % |
Total taxes other than income taxes | | Total taxes other than income taxes | $ | 3.91 | | | $ | 3.40 | | | $ | 0.51 | | | 15 | % |
| $ | 8,715 |
| $ | 10,249 |
| $ | (1,534 | ) | |
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Taxes, other than income taxes decreased by approximately $1.5 million orincreased 15% to $3.91 per Boe for the three months ended JuneSeptember 30, 20182020 compared to the three months ended June 30, 2017 due to (i) an increase in gross sales revenue which is the basis for severance taxes, (ii) lower ad valorem and property taxes due to reduced tax assessments in 2018 and (iii) lower prices for greenhouse gas emission credits, partially offset by an increase in emissions in 2018.
Other income and (expenses)
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| Berry Corp. (Successor) |
| Three Months Ended | Three Months Ended | |
| June 30, 2018 | June 30, 2017 | Variance |
(in thousands) | | | |
Interest expense, net of amounts capitalized | $ | (9,155 | ) | $ | (4,885 | ) | $ | (4,270 | ) |
Other, net | (239 | ) | 2,916 |
| (3,155 | ) |
| $ | (9,394 | ) | $ | (1,969 | ) | $ | (7,425 | ) |
Interest expense increased$3.40 per Boe for the three months ended JuneSeptember 30, 2018 by approximately $4 million or 87%, compared2019. The increase was largely due to the three months ended June 30, 2017, primarilyhigher property tax rates combined with lower sales volumes, as well as increased severance tax rates due to the additionexpiration of interest expense on the 2026 Notes, which were issuedcertain deductions in February 2018, partially offset by lower interest on the RBL Facility due to the decrease in borrowings period over period.2020.
The following table summarizes the components of reorganization items included in the statement of operations:Other Operating (Income) Expenses |
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| Berry Corp. (Successor) |
| Three Months Ended | Three Months Ended | |
(in thousands) | June 30, 2018 | June 30, 2017 | Variance |
Legal and other professional advisory fees | (1,178 | ) | (3,199 | ) | 2,021 |
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Gain on resolution of pre-emergence liabilities | 1,634 |
| 3,912 |
| (2,278 | ) |
| $ | 456 |
| $ | 713 |
| $ | (257 | ) |
Reorganization items, net consisted of a gain of approximately $0.5 millionOther operating expenses for the three months ended JuneSeptember 30, 2018, compared2020 was $2 million, comprised mainly of excess abandonment costs and excess storage capacity obtained in response to the $0.7 million gainglobal oil storage concerns. Other operating income for the three months ended JuneSeptember 30, 2017. The second quarter 2018 gain2019 were $1 million and consisted mainly of excess abandonment costs.
Interest Expense
Interest expense was primarily due tocomparable in the resolution of certain pre-emergence liabilities, partially offset by legalthree months ended September 30, 2020 and other professional fees. The 2017 gain amount was primarily due to a resolution of certain pre-emergence liabilities of $3.9 million partially offset by legal and professional fees to resolve outstanding bankruptcy-related claims.September 30, 2019.
Income tax benefit was $5.5 millionReorganization items, net
Reorganization items, net were not material for the three months ended JuneSeptember 30, 2018, compared to the income2020 and September 30, 2019.
Income Tax (Benefit) Expense
Our effective tax expense of $8.0 millionrate was 10% for the three months ended JuneSeptember 30, 2017 due to recording pre-tax loss in 2018 compared to pre-tax income in 2017. The decrease in the effective tax rates from 40% in 2017 to 16% in 2018 was primarily a result of the new tax laws for 2018.
Results of Operations - Six Months Ended June 30, 20182020 compared to the Six Months ended June 30, 2017 , including the successor and predecessor periods.
Our results of operations28% for the sixthree months ended JuneSeptember 30, 2017 are reflected2019. The rate in the tablesthird quarter 2020 was negatively impacted by adjustments to our valuation allowance during the quarter related to current year losses and narrative discussion that follow in two distinct periods, the four months ended Juneexpected future realizability of deferred tax assets.
Nine Months Ended September 30,
2017 and the two months ended February 28, 2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations2020 compared to
the six months ended JuneNine Months Ended September 30,
2017 are used to provide comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for comparing the periods presented.2019. |
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| Berry Corp. (Successor) | Berry LLC (Predecessor) | | |
| (a) | (b) | (c) | (a)-((b)+(c)) | |
| Six Months Ended | Four Months Ended | Two Months Ended | | |
| June 30, 2018 | June 30, 2017 | February 28, 2017 | $ Change | % Change |
(in thousands) | | | | | |
Revenues and other: | | | | | |
Oil, natural gas and NGL sales | $ | 263,010 |
| $ | 135,562 |
| $ | 74,120 |
| $ | 53,328 |
| 25 | % |
Electricity sales | 11,423 |
| 6,603 |
| 3,655 |
| 1,165 |
| 11 | % |
(Losses) gains on oil and natural gas derivatives | (112,787 | ) | 48,085 |
| 12,886 |
| (173,758 | ) | (285 | )% |
Marketing and other revenues | 1,619 |
| 4,127 |
| 2,057 |
| (4,565 | ) | (74 | )% |
| 163,265 |
| 194,377 |
| 92,718 |
| (123,830 | ) | (43 | )% |
Expenses and other: | | | | — |
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Lease operating expenses | 85,819 |
| 58,790 |
| 28,238 |
| (1,209 | ) | (1 | )% |
Electricity generation expenses | 7,725 |
| 5,613 |
| 3,197 |
| (1,085 | ) | (12 | )% |
Transportation expenses | 5,321 |
| 13,059 |
| 6,194 |
| (13,932 | ) | (72 | )% |
Marketing expenses | 987 |
| 1,000 |
| 653 |
| (666 | ) | (40 | )% |
General and administrative expenses | 24,466 |
| 31,800 |
| 7,964 |
| (15,298 | ) | (38 | )% |
Depreciation, depletion, amortization and accretion | 40,288 |
| 27,571 |
| 28,149 |
| (15,432 | ) | (28 | )% |
Taxes, other than income taxes | 16,972 |
| 13,330 |
| 5,212 |
| (1,570 | ) | (8 | )% |
(Gains) losses on sale of assets and other, net | 123 |
| 5 |
| (183 | ) | 301 |
| (169 | )% |
| 181,701 |
| 151,168 |
| 79,424 |
| (48,891 | ) | (21 | )% |
Other income and (expenses): | | | | — |
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Interest expense | (16,951 | ) | (6,600 | ) | (8,245 | ) | (2,106 | ) | 14 | % |
Other, net | (212 | ) | 2,916 |
| (63 | ) | (3,065 | ) | (107 | )% |
Reorganization items, net | 9,411 |
| (593 | ) | (507,720 | ) | 517,724 |
| (102 | )% |
Income (loss) before income taxes | (26,188 | ) | 38,932 |
| (502,734 | ) | 437,614 |
| (94 | )% |
Income tax expense (benefit) | (4,537 | ) | 15,435 |
| 230 |
| (20,202 | ) | (129 | )% |
Net income (loss) | (21,651 | ) | 23,497 |
| (502,964 | ) | 457,816 |
| (95 | )% |
Dividends on Series A Preferred Stock | (11,301 | ) | (7,196 | ) | — |
| (4,105 | ) | 57 | % |
Net income (loss) available to common stockholders | $ | (32,952 | ) | $ | 16,301 |
| $ | (502,964 | ) | $ | 453,711 |
| (93 | )% |
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| Nine Months Ended September 30, | | $ Change | | % Change |
| 2020 | | 2019 | |
| (in thousands) | | | | |
Revenues and other: | | | | | | | |
Oil, natural gas and NGL sales | $ | 284,852 | | | $ | 409,259 | | | $ | (124,407) | | | (30) | % |
Electricity sales | 19,089 | | | 22,553 | | | (3,464) | | | (15) | % |
Gains on oil derivatives | 157,398 | | | 7,546 | | | 149,852 | | | n/a |
Marketing and other revenues | 1,128 | | | 1,918 | | | (790) | | | (41) | % |
Total revenues and other | $ | 462,467 | | | $ | 441,276 | | | $ | 21,191 | | | 5 | % |
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Revenues and Other
Oil, natural gas and NGL sales increased approximately $53decreased by $124 million, or 25%30% to approximately $263$285 million for the sixnine months ended JuneSeptember 30, 20182020 when compared to the sixnine months ended JuneSeptember 30, 2017, including the successor and predecessor periods.2019. The increase reflects improveddecrease was driven by $139 million attributable to lower oil prices and an increased mix of oil production compared$4 million attributable to lower gas production as a result of the Hill Acquisition and Hugoton Disposition,prices. These decreases were partially offset by decreased overall production, as well as slightly lower gas prices.approximately $21 million attributable to higher oil volumes.
Electricity sales which represent sales to utilities and increased by approximately $1decreased $3 million or 11%,15% to approximately $11$19 million for the sixnine months ended JuneSeptember 30, 2018,2020 when compared to the sixnine months ended JuneSeptember 30, 2017, including2019. The decrease was mostly due to lower unit sales prices that were driven by lower natural gas prices.
Gain or loss on oil derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement gains for the successornine months ended September 30, 2020 and predecessor periods,September 30, 2019 were $119 million and $29 million, respectively. The increase in settlement gains was driven by lower oil prices relative to the derivative fixed prices and more volumes hedged in the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019. The mark-to-market non-cash gain of $38 million for the nine months ended September 30, 2020 was due to lower futures prices relative to the derivative fixed prices at September 30, 2020. The loss of $21 million for the nine months ended September 30, 2019, was primarily due to higher volumes sold externally as a result of lower downtime at our cogens.
Losses on oil and natural gas derivatives increased to approximately $113 million in the six months ended June 30, 2018, compared to gains of approximately $61 million in the six months ended June 30, 2017, including the successor and predecessor periods. Losses on oil and natural gas derivatives in 2018 were primarily due to an increase in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commodityfutures prices relative to the derivative fixed prices of our derivative contracts.at September 30, 2019.
Marketing and other revenues decreased approximately $5 million or 74%were lower for the sixnine months ended JuneSeptember 30, 2018 when2020, compared to the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, primarily2019 due to the lost helium sales revenue as a resultlower average gas prices.
Expenses and other | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, | | $ Change | | % Change |
| 2020 | | 2019 | |
| (in thousands, except expenses per Boe) | | | | |
Expenses and other: | | | | | | | |
Lease operating expenses | $ | 136,727 | | | $ | 156,765 | | | $ | (20,038) | | | (13) | % |
Electricity generation expenses | 11,186 | | | 14,705 | | | (3,519) | | | (24) | % |
Transportation expenses | 5,379 | | | 5,935 | | | (556) | | | (9) | % |
Marketing expenses | 1,036 | | | 1,670 | | | (634) | | | (38) | % |
General and administrative expenses | 57,287 | | | 46,932 | | | 10,355 | | | 22 | % |
Depreciation, depletion and amortization | 108,746 | | | 75,904 | | | 32,842 | | | 43 | % |
Impairment of oil and gas properties | 289,085 | | | — | | | 289,085 | | | 100 | % |
Taxes, other than income taxes | 24,714 | | | 28,683 | | | (3,969) | | | (14) | % |
| | | | | | | |
(Gain) losses on natural gas derivatives | (2,824) | | | 10,342 | | | (13,166) | | | n/a |
Other operating expenses | 2,658 | | | 3,814 | | | (1,156) | | | (30) | % |
Total expenses and other | 633,994 | | | 344,750 | | | 289,244 | | | 84 | % |
Other (expenses) income: | | | | | | | |
Interest expense | (25,987) | | | (26,362) | | | 375 | | | (1) | % |
Other, net | (15) | | | 79 | | | (94) | | | n/a |
Reorganization items, net | — | | | (426) | | | 426 | | | (100) | % |
(Loss) income before income taxes | (197,529) | | | 69,817 | | | (267,346) | | | n/a |
Income tax expense (benefit) | 1,536 | | | 19,294 | | | (17,758) | | | (92) | % |
Net (loss) income | $ | (199,065) | | | $ | 50,523 | | | $ | (249,588) | | | n/a |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Expenses per Boe:(1) | | | | | | | |
Lease operating expenses | $ | 17.12 | | | $ | 20.31 | | | $ | (3.19) | | | (16) | % |
Electricity generation expenses | 1.40 | | | 1.91 | | | (0.51) | | | (27) | % |
Electricity sales(1) | (2.39) | | | (2.92) | | | 0.53 | | | (18) | % |
Transportation expenses | 0.67 | | | 0.77 | | | (0.10) | | | (13) | % |
Transportation sales(1) | (0.01) | | | (0.03) | | | 0.02 | | | (67) | % |
Marketing expenses | 0.13 | | | 0.22 | | | (0.09) | | | (41) | % |
Marketing revenues(1) | (0.12) | | | (0.21) | | | 0.09 | | | (43) | % |
Derivatives settlements paid (received) for gas purchases(1) | 1.55 | | | 0.25 | | | 1.30 | | | n/a |
Total operating expenses | $ | 18.35 | | | $ | 20.28 | | | $ | (1.93) | | | (10) | % |
Total unhedged operating expenses(2) | $ | 16.80 | | | $ | 20.03 | | | $ | (3.23) | | | (16) | % |
| | | | | | | |
Total non-energy operating expenses(4) | $ | 13.41 | | | $ | 14.75 | | | $ | (1.34) | | | (9) | % |
Total energy operating expenses(5) | $ | 4.94 | | | $ | 5.54 | | | $ | (0.60) | | | (11) | % |
| | | | | | | |
General and administrative expenses(3) | $ | 7.17 | | | $ | 6.08 | | | $ | 1.09 | | | 18 | % |
Depreciation, depletion and amortization | $ | 13.62 | | | $ | 9.84 | | | $ | 3.78 | | | 38 | % |
Taxes, other than income taxes | $ | 3.10 | | | $ | 3.72 | | | $ | (0.62) | | | (17) | % |
__________
(1) We report sales of electricity, transportation and marketing and transportation activities (as applicable)sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses increased to $18.24also include the effect of derivative settlements (received or paid) for gas purchases.
(2) Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.
(3) Includes non-recurring costs and non-cash stock compensation expense, in aggregate, of approximately $1.85 per Boe and $1.18 per Boe for the sixnine months ended JuneSeptember 30, 2018 from $15.782020 and September 30, 2019, respectively.
(4) Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.
(5) Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.
Expenses and Other
Operating expenses, including hedge effects, decreased 10% or $1.93 per Boe to $18.35 for the sixnine months ended JuneSeptember 30, 2017 including the successor and predecessor periods, for the reasons described below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses in absolute dollars for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods, reflected lower fuel gas costs offset by higher activity in 2018 compared to 2017. Lease operating expenses per Boe increased to $18.012020 from $20.28 per Boe for the sixnine months ended JuneSeptember 30, 2018, from $13.692019 due to $3.19 per Boe lower lease operating expenses, partially offset by $1.30 per Boe of higher gas hedge settlement losses and $0.02 decrease in electricity sales margin. Additionally, operating expenses, on an unhedged basis were $16.80 per Boe for the sixnine months ended JuneSeptember 30, 2017, including2020 which was approximately 16% lower than the successor and predecessor periods. The increase in oil productionnine months ended September 30, 2019 due to 80% of total production from 56% as a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) adversely impacted coststhese same non-hedge factors.
Lease operating expenses decreased to $17.12 per Boe in 2018for the nine months ended September 30, 2020, a 16% or $3.19 per Boe reduction compared to 2017.$20.31 for the nine months ended September 30, 2019. The decrease was driven primarily by lower unhedged fuel prices related to our California steam operations and other cost savings. Unhedged fuel cost decreased $2.01 per Boe during the nine months ended September 30, 2020 from $6.81 in the same period of 2019 as natural gas prices declined 30%. Compared to the nine months ended September 30, 2019, the 2020 lease operating non-fuel expenses decreased $1.18, or $6 million on an absolute dollar basis, primarily due to cost savings initiatives and efficiency measures implemented beginning in the second quarter of 2020. These initiatives resulted in lower maintenance and outside services costs of $1.22 per Boe when compared to the nine months ended September 30, 2019. Fuel costs exclude the effects of natural gas derivative settlements mentioned elsewhere.
Electricity generation expenses were comparabledecreased approximately 27% to $1.40 per Boe for the sixnine months ended JuneSeptember 30, 2018 and2020 from $1.91 per Boe for the sixsame period in 2019 primarily driven by lower fuel cost. Decreased fuel costs included in electricity generation expenses exclude the effects of natural gas derivative settlements discussed elsewhere.
Gain or loss on natural gas purchase derivatives for the nine months ended JuneSeptember 30, 2017, including2020 and September 30, 2019 was a gain of $3 million and a loss of $10 million, respectively. The settlement loss for the successornine months ended September 30, 2020 was $12 million, or $1.55 per Boe, compared to a settlement loss of $2 million, or $0.25 per Boe for same period in 2019, consistent with the changes in futures prices at the end of each period. The mark-to-market valuation gain or loss for each of the periods ended September 30, 2020 and predecessor periods.September 30, 2019 was a gain of $15 million and a loss of $8 million respectively.
Transportation expenses decreased by approximately $14 million or 72%13% to $0.67 per Boe for the sixnine months ended JuneSeptember 30, 20182020, compared to $0.77 per Boe for the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, primarily2019, mainly due to the Hugoton disposition of gas properties, which required significant transportation expense because gas transportation is generally borne by the seller and oil transportation costs are borne by the buyer.lower volumes shipped from our Rockies assets.
Marketing expenses decreased $0.7 million or 40%41% to $0.13 per Boe for the sixnine months ended JuneSeptember 30, 20182020, compared to $0.22 per Boe for the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, primarily2019 due to lower gas prices. Marketing expenses in these periods, which exclude the decrease ineffects of hedging, represented the cost of natural gas prices.purchased from and sold to third parties.
General and administrative expenses decreasedincreased by approximately $15$10 million, or 22%, for the sixnine months ended JuneSeptember 30, 20182020 compared to the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods, in terms of absolute dollars, primarily due to the reduced spending on non-recurring restructuring and other costs, slightly offset by increased headcount-related costs. This activity was consistent with our post-emergence efforts to build out our corporate structure while reducing restructuring costs. This also resulted in a decrease in general and administrative expenses per Boe to $5.14 in 2018 from $6.25 in 20172019. For the sixnine months ended JuneSeptember 30, 20182020 and 2017,September 30, 2019, general and administrative expenses included non-recurring restructuringnon-cash stock compensation costs of approximately $11 million and other$6 million, respectively, and non-recurring costs of approximately $4 million and $24$3 million, respectively,respectively.
Adjusted general and administrative expenses, which exclude non-cash stock compensation costs and non-recurring costs, were $43 million for the nine months ended September 30, 2020 compared to $38 million for the nine months ended September 30, 2019. The year-over-year increases in both general and administrative expenses and adjusted general and administrative expenses were primarily due to increased costs associated with supporting the company's growth, including the expansion of approximately $2.3 millionour corporate affairs department and none, respectively.activities whose purpose is to support our efforts and participation in the regulatory, political and legislative process primarily in California.
Depreciation, depletion and amortization decreased by approximately $15DD&A increased $33 million, or 28%43%, to approximately $109 million for the sixnine months ended JuneSeptember 30, 20182020 compared to the sixnine months ended JuneSeptember 30, 2017, including successor and predecessor periods,2019, primarily due to the increase inincreased production and higher depreciation and depletion rates for 2020. On a per Boe basis, period-over-period DD&A increased $3.78 to $13.62 from $9.84 due to our increasing capital development program throughout 2019 and the first quarter of 2020, compared to prior periods.
Impairment of oil and gas reservesproperties
As discussed above, we recorded a non-cash pre-tax asset impairment charge of $289 million on properties in 2018, which resulted in lower DD&A ratesUtah and certain California locations for the fair market revaluation of our assets in fresh start accounting which resulted in a lower depreciable asset base in the periods following our emergence from bankruptcy.
nine months ended September 30, 2020.
Taxes, Other Than Income Taxes
| | | Berry Corp. (Successor) | Berry LLC (Predecessor) | | | Nine Months Ended September 30, | | $ Change | | % Change |
| Six Months Ended | Four Months Ended | Two Months Ended | | | 2020 | | 2019 | |
| June 30, 2018 | June 30, 2017 | February 28, 2017 | Variance | | (per Boe) | | | | |
| (a) | (b) | (c) | (a)-((b)+(c)) | |
(in thousands) | | | | |
Severance taxes | $ | 5,761 |
| $ | 3,611 |
| $ | 1,540 |
| $ | 610 |
| Severance taxes | $ | 0.74 | | | $ | 0.57 | | | $ | 0.17 | | | 30 | % |
Ad valorem and property taxes | 6,558 |
| 5,572 |
| 2,108 |
| (1,122 | ) | Ad valorem and property taxes | 1.46 | | | 1.31 | | | 0.15 | | | 11 | % |
Greenhouse gas allowances | 4,653 |
| 4,146 |
| 1,564 |
| (1,057 | ) | Greenhouse gas allowances | 0.90 | | | 1.84 | | | (0.94) | | | (51) | % |
Total taxes other than income taxes | | Total taxes other than income taxes | $ | 3.10 | | | $ | 3.72 | | | $ | (0.62) | | | (17) | % |
| $ | 16,972 |
| $ | 13,329 |
| $ | 5,212 |
| $ | (1,569 | ) | |
|
Liquidity and Capital Resources
Currently, we expect our primary sources of liquidity and capital resources will be internally generated free cash flow from operations after debt service, or levered free cash flow,Levered Free Cash Flow, and as needed, borrowings under the RBL Facility, described below. As of September 30, 2020, we had liquidity of $192 million, consisting of $49 million cash in the bank and borrowing availability of $143 million under our RBL Facility. Depending upon market conditionsThe RBL Facility currently has a $200 million borrowing base with a $200 million elected commitment and other factors, we have issued and may issue additional equity and debt securities; however,borrowing availability of $150 million until the next semi-annual borrowing base redetermination that is scheduled to occur in November 2020, at which time we expect our operationsthe availability to continuereturn to generate sufficient levered free cash flow at current commodity prices to fund maintenance operations and organic growth.this elected commitment amount. We currently believe that our liquidity and capital resources will be sufficient to conduct our business and operations for the next 12 months.
In February 2018, we issuedWe currently expect our 2026 Notes, which resultedoperations to continue to generate positive Levered Free Cash Flow in net proceeds to us2020 and for the combined two-year down-cycle through the end of 2021, even at the currently depressed commodity price levels, given our current hedge positions and based on our current operating plans. We currently have essentially all of our expected oil production hedged in the fourth quarter of 2020 at nearly $60 per barrel, as well as additional 2021 hedge positions at nearly $46 per barrel for approximately 19,000 Bbls/d in the first half of 2021 and approximately 11,000 Bbls/d in the second half of 2021 at $46 per barrel. As of September 30, 2020, our oil hedge positions had a fair value of approximately $391 million after deducting expenses$45 million. However, our business, like other producers, has been and is expected to continue to be negatively affected by the ongoing and evolving volatility, uncertainty, and turmoil in the oil and gas industry created by the COVID-19 demand destruction and the initial purchasers’ discount. We usedunknown supply levels caused by OPEC+’s actions, as further discussed under “Business Environment, Market Conditions and Outlook” in this report. Additionally in October 2020, we hedged 12,500 MMBtu/d of our 2021 Rockies gas production at nearly $3.00 per MMBtu.
In terms of immediate risks, if we were forced to shut-in a significant amount of our California production, as well as curtail some of our Utah and Colorado production, this could have a material, adverse effect on our financial and operational results. If we are forced to shut in production, we will incur additional costs to bring those associated wells back online, as well as additional costs and operating expenses while production is shut-in to, among other things, maintain the net proceedshealth of the reservoirs, meet contractual obligations and protect our interests, but without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we also need to repay borrowingsshut-in steam injection for the reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could decrease, which could result in a reduction to our borrowing base under the RBL Facility and used the remainder for general corporate purposes.
our liquidity.
In March 2018,the longer term, if depressed oil prices were to persist through 2021 and longer as currently predicted by the forward curve for oil, we may not be able to continue to generate the same level of Levered Free Cash Flow we are currently generating and our boardliquidity and capital resources may not be sufficient to conduct our business and operations in the longer term until commodity prices recover. In light of directors approvedcontinuing uncertainty, negative commodity price outlook, and significant risks mentioned above and further discussed elsewhere in this report (including under Part II, Item 1.A. “Risk Factors”), we continue to plan for a cumulative paid-in-kindprolonged downturn and our strategy to survive is focused on preserving cash, reducing costs and maintaining business continuity. We have significantly reduced our initially planned 2020 capital expenditures and non-employee operating and general and administrative expenses and we are focused on achieving additional cost reductions and improving operational efficiencies. We also temporarily suspended our quarterly cash dividend, starting with the second quarter of 2020, and year-to-date we have not repurchased any common stock under our authorized share repurchase program. As mentioned above, we enhanced our hedge positions for 2020, and to a lesser extent for 2021. Depending on the Series A Preferred Stocktiming and rate of the eventual recovery and our outlook, we may potentially use Levered Free Cash Flow to opportunistically repurchase our bonds to strengthen our balance sheet to withstand an extended low commodity price environment, to explore accretive acquisitions that would strengthen our asset base or to fund our 2021 capital expenditures in the event there is a shortfall next year. Although we continue to actively work to mitigate the evolving challenges of this severe industry downturn on our operations, our financial condition and our employees and contractors, there is no certainty that the measures we take will ultimately be sufficient. We are unable to reasonably predict when, or to what extent, commodity prices and the overall markets and global economy will stabilize, and the pace of any subsequent
recovery for the periods through Decemberoil and gas industry. Further, to what extent these events do ultimately impact our business, liquidity, financial condition, and results of operations is highly uncertain and dependent on numerous evolving factors that cannot be predicted, including the severity and duration of the COVID-19 pandemic and future actions by OPEC+.
The RBL Facility
On July 31, 2017. The cumulative dividend was 0.050907 per share and approximately 1,825,000 shares2017, we entered into a credit agreement providing for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base (“RBL Facility”), which is further discussed in total. AlsoNote 2, Debt, in March 2018, the board approved a $0.158 per share, or approximately $5.6 million, cash dividend onNotes to the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the payments were to stockholdersCondensed Consolidated Financial Statements in Part I, Item 1 of record as of March 15, 2018. In May 2018, the board of directors approved a $0.15 per share, or approximately $5.6 million cash dividend, on the Series A Preferred Stock for the quarter endedthis report. On June 30, 2018. The payment was made to stockholders of record as of June 7, 2018.
In July,23, 2020, we completed our IPOthe regular Spring borrowing base redetermination and as a result, on July 26, 2018, our common stock began trading onentered into Limited Waiver and Amendment No. 5 to Credit Agreement (the “Amendment”), with the NASDAQ Global Select Market under the ticker symbol BRY. The Company sold 10,497,849 shares and the selling stockholders sold 2,545,630 shares at a price of $14.00 per share. We used a portion of our proceeds to repurchase 1,802,196 shares of our common stock owned by Benefit Street Partners and Oaktree Capital Management. After giving effectlenders which, among other changes to the IPO andcredit agreement described in the share repurchase,Amendment, (1) decreases the number of shares of our common stockborrowing base to $200 million; (2) decreases the elected commitment to $200 million; (3) limits the maximum borrowing availability to $150 million until the next semi-annual borrowing base redetermination which is scheduled to occur in November 2020 at which time we expect the availability to return to this elected commitment amount; (4) implements certain anti-cash hoarding provisions, including the requirement to repay outstanding increased by 8,695,653. We andloans on a weekly basis in the selling stockholders have granted the underwriters the option to purchase up to an additional 1,534,895 shares and 421,626 shares of common stock, respectively, on the same terms and conditions set forth above.
In connection with the IPO, each of the 37.7 million shares of our Series A Preferred Stock was automatically converted into 1.05 shares of our common stock or 39.6 million shares in aggregate and the right to receive a cash payment of $1.75. The cash payment was reduced in respectamount of any cash dividend paid byon the Company on suchbalance sheet (subject to certain exceptions) in excess of $30 million; (5) waives certain events of default arising from the failure to timely deliver certain hedging reports; and (6) further limits dividends and share repurchases. As of Series A Preferred Stock for any period commencing on or after April 1, 2018. BecauseSeptember 30, 2020 we paid the second quarter preferred dividend of $0.15 per share in June, the cash payment for the conversion was reduced to $1.60 per share, orhad no borrowings outstanding, approximately $60 million.
The Company received approximately $136$7 million in net proceeds from the offering after deducting underwriting discounts and offering expenses payable by us. We did not receive any proceeds from the sale by the selling stockholders. We used approximately $24 millionletters of the net proceeds to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the offering) from funds affiliated with Benefit Street Partners and Oaktree Capital Management.
Of the remaining approximately $112 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the $60 million we borrowed on the RBL Facility to make the payment to the holders of our Series A Preferred Stock in connection with the conversion of preferred stock to common stock. We used the remainder for general corporate purposes. On August 20, 2018, we had approximately $388 million of available borrowing capacity under the RBL Facilitycredit outstanding, and approximately $36 million of cash on hand.
On August 21, 2018, our board of directors approved a $0.12 per share quarterly cash dividend on our common stock on a pro-rata basis from the date of our IPO through September 30, 2018 which will result in a payment of $0.09 per share.
The RBL Facility contains certain financial covenants, including the maintenance of (i) a Leverage Ratio (as defined in the RBL Facility) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the RBL Facility) not to be less than 1.00:1.00. As of June 30, 2018, our Leverage Ratio and Current Ratio were 2.63:1.00 and 3.18:1.00, respectively. As of June 30, 2018 our borrowing base was approximately $400 million and we had $327$143 million available for borrowing under the RBL Facility. At June 30, 2018, we were in compliance with the financial covenants under the RBL Facility. In connection with the issuance of the 2026 Notes, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. Borrowing base redeterminations generally become effective on, or about, each May 1 and November, 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations.
Historically,The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. The RBL Facility requires us to maintain on a consolidated basis as of each quarter-end (i) a Leverage Ratio of no more than 4.0 to 1.0 and (ii) a Current Ratio of at least 1.0 to 1.0. The RBL Facility also contains customary restrictions. As of September 30, 2020, our Leverage Ratio and Current Ratio were 1.5 to 1.0 and 2.7 to 1.0, respectively. In addition, the Predecessor utilized funds from debt offerings, borrowingsRBL Facility currently provides that to the extent we incur unsecured indebtedness, including any amounts raised in the future, the borrowing base will be reduced by an amount equal to 25% of the amount of such unsecured debt. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under its credit facilitythe RBL Facility and net cash provided by operating activities,exercise all of their other rights and remedies, including foreclosure on all of the collateral. We were in compliance with all financial covenants under the RBL Facility as well as funding from our former parent, for capital resources and liquidity, and the primary use of capital was for the development of oil and natural gas properties.September 30, 2020.
Hedging
We have protected a significant portionsubstantially all of our anticipated cash flows throughin 2020, as well as a significant portion in 2021, using our commodity hedging program, including through fixed-price derivative contracts. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge gas purchases to protect against price increases. Our generally low-decline production base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our 2020 and 2021 hedging positions. For information regarding risks related to our hedging program, see “Item 1A. Risk Factors—Risks Related to Our Business and Industry” in our Annual Report.
As of JuneSeptember 30, 2018,2020, we have hedgedhad the following crude oil production and gas purchases hedges.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Q4 2020 | | 1H 2021 | | 2H 2021 |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Fixed Price Oil Swaps (Brent): | | | | | | | | | | | |
Hedged volume (MBbls) | | | | | | | 2,208 | | | 3,438 | | | 2,084 | |
Weighted-average price ($/Bbl) | | | | | | | $ | 59.85 | | | $ | 45.82 | | | $ | 46.17 | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
Purchased Oil Calls Options (Brent): | | | | | | | | | | | |
Hedged volume (MBbls) | | | | | | | 276 | | | — | | | — | |
Weighted-average price ($/Bbl) | | | | | | | $ | 65.00 | | | $ | — | | | $ | — | |
Fixed Price Gas Purchase Swaps (Kern, Delivered): | | | | | | | | | | | |
Hedged volume (MMBtu) | | | | | | | 5,060,000 | | | 9,045,000 | | | 5,535,000 | |
Weighted-average price ($/MMBtu) | | | | | | | $ | 2.76 | | | $ | 2.71 | | | $ | 2.73 | |
Fixed Price Gas Purchase Swaps (SoCal Citygate): | | | | | | | | | | | |
Hedged volume (MMBtu) | | | | | | | 155,000 | | | — | | | — | |
Weighted-average price ($/MMBtu) | | | | | | | $ | 3.80 | | | $ | — | | | $ | — | |
In October 2020, we added 12,500 MMBtu/d of approximately 2.1 MMBbls for 2018, 3.7 MMBbls for 2019fixed price gas sales swaps at an average price of $2.96, indexed to Northwest Pipeline Rocky Mountains and 0.5 MMBbls for 2020.
Future cash flows are subject to a number of variables discussed in "Risk Factors". Further, our capital investment budgetCIG, for the year endedperiod January 1, 2021 through December 31, 2021.
The following table summarizes the historical results of our hedging activities.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Three Months Ended | | Nine Months Ended |
| September 30, 2020 | | June 30, 2020 | | September 30, 2019 | | September 30, 2020 | | September 30, 2019 |
Crude Oil (per Bbl): | | | | | | | | | |
Realized sales price, before the effects of derivative settlements | $ | 39.88 | | | $ | 28.98 | | | $ | 57.92 | | | $ | 39.00 | | | $ | 58.79 | |
Effects of derivative settlements | $ | 16.28 | | | $ | 25.42 | | | $ | 7.31 | | | $ | 16.97 | | | $ | 4.30 | |
Oil with hedges ($/Bbl) | $ | 56.16 | | | $ | 54.40 | | | $ | 65.23 | | | $ | 55.97 | | | $ | 63.09 | |
Purchased Natural Gas (per MMBtu): | | | | | | | | | |
Purchase price, before the effects of derivative settlements | $ | 2.69 | | | $ | 1.74 | | | $ | 2.67 | | | $ | 2.25 | | | $ | 3.17 | |
Effects of derivative settlements | $ | 0.10 | | | $ | 1.11 | | | $ | 0.30 | | | $ | 0.60 | | | $ | 0.09 | |
Purchased Natural Gas with hedges | $ | 2.79 | | | $ | 2.85 | | | $ | 2.97 | | | $ | 2.85 | | | $ | 3.26 | |
Cash Dividends
Our Board of Directors approved $0.12 per share quarterly cash dividend on our common stock for the first quarter of 2020, which we paid in April 2020. In April 2020, in connection with the current low oil price environment, we temporarily suspended our quarterly dividend until oil prices recover. As of October 31, 2020, the Company has paid approximately $65 million in dividends, since the inception of its dividend program in the third quarter of 2018.
Stock Repurchase Program
In December 2018, our Board of Directors adopted a program for the opportunistic repurchase of up to $100 million of our common stock. Based on the Board’s evaluation of market conditions for our common stock at that time, they authorized initial repurchases of up to $50 million under the program. In February 2020, the Board of
Directors authorized the repurchase of the remaining $50 million of our $100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and amount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not allocateobligate Berry Corp. to purchase shares during any amountsperiod or at all. Any shares acquired will be available for acquisitionsgeneral corporate purposes. The Company repurchased a total of oil5,057,682 shares under the stock repurchase program for approximately $50 million as of December 31, 2019. For the nine months ended September 30, 2020, we did not repurchase any shares under the stock repurchase program.
Bond Repurchase Program
In February 2020, our Board of Directors adopted a program to spend up to $75 million for the opportunistic repurchase of our 2026 Notes. The manner, timing and natural gas properties. If we make acquisitions, weamount of any purchases will be determined based on our evaluation of market conditions, compliance with outstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to purchase the 2026 Notes during any period or at all. We have not yet repurchased any bonds under the bond repurchase program.
Corporate Organization
Berry Corp., as Berry LLC’s parent company, has no independent assets or operations. Any guarantees of potential future registered debt securities by Berry Corp. or Berry LLC would be requiredfull and unconditional. Berry Corp. and Berry LLC currently do not have any other subsidiaries. In addition, there are no significant restrictions upon the ability of Berry LLC to reduce the expected level of capital investmentsdistribute funds to Berry Corp. by distribution or seek additional capital. If we require additional capital we may seek such capital through borrowingsloan other than under the RBL Facility. None of the assets of Berry Corp. or Berry LLC represent restricted net assets.
The RBL Facility joint venture partnerships, production payment financings, asset sales, additional offeringspermits Berry LLC to make distributions to Berry Corp. so long as both before and after giving pro forma effect to such distribution no default or borrowing base deficiency exists, availability equals or exceeds 20% of debtthe then effective borrowing base, and Berry Corp. demonstrates a pro forma leverage ratio less than or equity securities or other means. We cannot be sure that needed
capital would be available on acceptable terms or at all. If weequal to 2.5 to 1.0. The conditions are unable to obtain funds on acceptable terms, we may be required to curtail our current development programs, which could resultcurrently met with significant declines in our production.
See "-Capital Expenditures and Capital Budget" for a description of our 2018 capital expenditure budget.margin.
Statements of Cash Flows
The following is a comparative cash flow summary:
|
| | | | | | | | | |
| Berry Corp. (Successor) | Berry LLC (Predecessor) |
| Six Months Ended | Four Months Ended | Two Months Ended |
| June 30, 2018 | June 30, 2017 | February 28, 2017 |
(in thousands) | | | |
Net cash: | | | |
Provided by (used in) operating activities | $ | (49,548 | ) | $ | 44,937 |
| $ | 22,431 |
|
Used in investing activities | (42,347 | ) | (72,328 | ) | (3,133 | ) |
Provided by (used in) financing activities | 46,467 |
| (15,000 | ) | (162,668 | ) |
Net decrease in cash, cash equivalents and restricted cash | $ | (45,428 | ) | $ | (42,391 | ) | $ | (143,370 | ) |
| | | |
| | | | | | | | | | | | |
| | |
| Nine Months Ended September 30, | |
| 2020 | | 2019 | |
| (in thousands) |
Net cash: | | | | |
Provided by operating activities | $ | 144,419 | | | $ | 164,267 | | |
Used in investing activities | (74,522) | | | (176,138) | | |
Used in financing activities | (22,277) | | | (56,809) | | |
Net increase (decrease) in cash and cash equivalents | $ | 47,620 | | | $ | (68,680) | | |
Operating Activities
Cash used in operating activities was approximately $50 million for the six months ended June 30, 2018 compared to cash provided by operating activities of approximately $67 milliondecreased for the sixnine months ended JuneSeptember 30, 2017, including the successor and predecessor periods. The amounts used in 2018 included $1272020 by approximately $20 million for early-terminated hedges which offset $77 million of cash provided by other operating activities. Aside from the impact of these early hedge terminations, the decrease in cash used in operating activities in the first six months of 2018when compared to 2017 reflected higherthe nine months ended September 30, 2019, due to decreased sales of $129 million, and lower costs, slightlyincreased general and administrative expenses of $6 million. These decreases were partially offset by negativeincreased derivatives settlements received of $80 million, decreased lease operating expenses and electricity generation expenses of $24 million, decreased taxes, other than income taxes of $4 million, and working capital effects.changes of $7 million.
Investing Activities
The following provides a comparative summary of cash flowflows from investing activities:
| | | | | | | | | | | | |
| | |
| Nine Months Ended September 30, | |
| 2020 | | 2019 | |
| (in thousands) |
Capital expenditures:(1) | | | | |
Development of oil and natural gas properties | $ | (58,370) | | | $ | (157,281) | | |
Purchase of other property and equipment | (3,951) | | | (12,394) | | |
Changes in capital investment accruals | (10,347) | | | (4,613) | | |
| | | | |
Acquisition of properties and equipment and other | (2,104) | | | (2,819) | | |
Proceeds from sale of properties and equipment and other | 250 | | | 969 | | |
| | | | |
Cash used in investing activities | $ | (74,522) | | | $ | (176,138) | | |
|
| | | | | | | | | |
| Berry Corp. (Successor) | Berry LLC (Predecessor) |
| Six Months Ended | Four Months Ended | Two Months Ended |
(in thousands) | June 30, 2018 | June 30, 2017 | February 28, 2017 |
Capital expenditures (1) | $ | (45,369 | ) | $ | (32,878 | ) | $ | (3,158 | ) |
Proceeds from sale of properties and equipment and other | 3,022 |
| — |
| 25 |
|
Deposit on acquisition of properties | — |
| (39,450 | ) | — |
|
Cash used in investing activities: | $ | (42,347 | ) | $ | (72,328 | ) | $ | (3,133 | ) |
__________(1) basedBased on actual cash payments rather than accruals.
Cash used in investing activities was approximately $42decreased $102 million for the sixnine months ended JuneSeptember 30, 2018. The decrease in cash used for investing activities for the six months ended June 30, 20182020 when compared to the same period in 2017 including the successor and predecessor periods, was2019, primarily due to the deposit made for the acquisition of the Hill propertya decrease in 2017 offset by increased capital spending in accordance with the six months ended June 30, 2018.revised 2020 capital budget.
Financing Activities
Cash providedused by financing activities was approximately $46$22 million for the sixnine months ended JuneSeptember 30, 20182020 and wasdecreased by approximately $35 million from the nine months ended September 30, 2019. The decrease is largely due to receiving $391 million net proceeds from the issuance of our 2026 Notes offset by payments on our RBL Facility, additional net
borrowings of $313 million, the repurchase of a right to our shares of $20 million, which is reflected as treasury stock cash dividends declared on our Series A Preferred Stockpurchases of $36 million in the aggregate amount of $11 million and $9 million of debt issuance costs. For the sixnine months ended JuneSeptember 30, 2017, including2019 and none in the successor and predecessor periods,nine months ended September 30, 2020. Additionally, we paid fewer dividends in 2020 by approximately $10 million. Partially offsetting the positive cash impact of these activities, we reduced our net cash used in financing activities related to payments on our previous credit facilities ofborrowings by approximately $513$12 million offset by the receipt of proceeds from the issuance of our Series A Preferred Stock of $335 million.
Debt
2026 Notes Offering
In February 2018, we issued $400 million in aggregate principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the issuance to repay the $379 million outstanding balance on the RBL Facility in 2020 compared to 2019.
Balance Sheet Analysis
The changes in our balance sheet from December 31, 2019 to September 30, 2020 are discussed below.
| | | | | | | | | | | |
| |
| September 30, 2020 | | December 31, 2019 |
| (in thousands) |
Cash and cash equivalents | $ | 47,620 | | | $ | — | |
Accounts receivable, net | $ | 48,798 | | | $ | 71,867 | |
Derivative instruments assets - current and long-term | $ | 59,669 | | | $ | 9,691 | |
| | | |
Other current assets | $ | 20,318 | | | $ | 19,399 | |
Property, plant & equipment, net | $ | 1,260,755 | | | $ | 1,576,267 | |
Other non-current assets | $ | 9,297 | | | $ | 12,974 | |
Accounts payable and accrued liabilities | $ | 95,237 | | | $ | 151,811 | |
Derivative instruments liabilities - current and long-term | $ | 1,516 | | | $ | 4,958 | |
| | | |
Long-term debt | $ | 393,219 | | | $ | 394,319 | |
Deferred income taxes liability - long-term | $ | 9,318 | | | $ | 9,057 | |
Asset retirement obligation - long-term | $ | 136,392 | | | $ | 124,019 | |
Other non-current liabilities | $ | 36,150 | | | $ | 33,586 | |
Equity | $ | 774,625 | | | $ | 972,448 | |
See "Liquidity and usedCapital Resources" for discussions about the remainderchanges in cash and cash equivalents.
The $23 million decrease in accounts receivable was driven mostly by lower sales, both price and volume period-over-period, partially offset by higher hedge settlements at each period-end.
The $53 million increase in derivative assets and liabilities reflected the net appreciation in the mark-to-market values of the derivatives, lower forward curve prices relative to the contract fixed price, at the end of each period presented, as well as the change in positions held at the end of each period and the settlements received and paid throughout the periods.
The $316 million decrease in property, plant and equipment was largely the result of the $289 million impairment on our oil and gas properties in the first quarter of 2020, as well as depreciation expense of $101 million, partially offset by capital investments of $61 million, $6 million of acquisitions and capitalized interest and $6 million for general corporate purposes.asset retirement obligations.
We may, at our option, redeem all or aThe $4 million decrease in other non-current assets is mainly due to deferred debt issuance cost amortization.
The $57 million decrease in accounts payable and accrued liabilities included approximately $21 million of decreased accruals and spending for various capital and operating costs due to the reduced level of these costs in 2020, $13 million fewer royalties accrued due to decreased sales, $12 million reclassified from current to long-term portion of the 2026 Notesasset retirement obligation based on budgeted spending and regulatory requirements, and the $10 million impact of dividends accrued at any time on or after February 15, 2021. We are also entitledthe end of 2019 with no corresponding accrual at September 30, 2020.
The increase in long-term deferred income taxes liability is due to redeem up to 35%the income tax expense and change in current portion due during the period.
The $12 million increase in the long-term portion of the aggregate principal amountasset retirement obligation from $124 million at December 31, 2019 to $136 million at September 30, 2020 was due to $7 million of accretion, $6 million of liabilities incurred and $12 million of reclassification from the 2026 Notes before February 15, 2021, with an amountcurrent portion due to changes in budgeted spending and regulatory requirements. These increases were partially offset by $12 million of cash not greater thanliabilities settled during the net proceeds that we raise in certain equity offerings at a redemption price equal to 107%period.
Table of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any. In addition, prior to February 15, 2021, we may redeem some or all of the 2026 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus any accrued and unpaid interest. If we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.Contents The 2026 Notes are our senior unsecured obligationsincrease in other non-current liabilities was driven by higher greenhouse gas liabilities as a result of periodic emissions and rank equally in right ofslight price increases. This liability is due for payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The notes are fully and unconditionally guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries (othermore than Berry LLC). The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the 2026 Notes.one year from September 30, 2020.
The indenture governing the 2026 Notes contains restrictive covenants that may limit our abilitydecrease in equity of $198 million was due to among other things:net loss of $199 million and $10 million of common stock dividends declared. These decreases were partially offset by $11 million of stock-based incentive equity awards, net of taxes.
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness
transfer, sell or dispose of assets;
make investments;
create certain liens securing indebtedness;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets; and
engage in transactions with affiliates.
The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of our subsidiaries.
The RBL Facility
On July 31, 2017, Berry LLC, as borrower, entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base, and provided an initial commitment of $500 million. The RBL Facility also provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the RBL Facility on a dollar for dollar basis. Borrowing base redeterminations become effective on or about each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations. In connection with the issuance of the 2026 Notes, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. As of June 30, 2018, we had $66 million in borrowings and
approximately $7 million in letters of credit outstanding and borrowing availability of $327 million under the RBL Facility. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.
The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary London interbank offered rate plus an applicable margin ranging from 2.50% to 3.50% per annum, and (ii) a customary base rate plus an applicable margin ranging from 1.50% to 2.50% per annum, in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average daily unused amount of the borrowing availability under the RBL Facility. We have the right to prepay any borrowings under the RBL Facility with prior notice at any time without a prepayment penalty, other than customary “breakage” costs with respect to eurodollar loans.
Berry Corp. guarantees, and each future subsidiary of Berry Corp. (other than Berry LLC), with certain exceptions, is required to guarantee, our obligations and obligations of the other guarantors under the RBL Facility and under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). In addition, pursuant to a Guaranty Agreement dated as of July 31, 2017 (the “Guaranty Agreement”), Berry LLC guarantees the Guaranteed Obligations. The lenders under the RBL Facility hold a mortgage on at least 85% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions. The RBL Facility, with certain exceptions, also requires that any future subsidiaries of Berry LLC will also have to grant mortgages, security interests and equity pledges.
The RBL Facility requires us to maintain on a consolidated basis as of September 30, 2017 and each quarter-end thereafter (i) a Leverage Ratio of no more than 4.00 to 1.00 and (ii) a Current Ratio of at least 1.00 to 1.00. The RBL Facility also contains customary restrictions that may limit our ability to, among other things:
incur or guarantee additional indebtedness;
transfer, sell or dispose of assets;
make loans to others;
make investments;
merge with another entity;
make or declare dividends;
hedge future production or interest rates;
enter into transactions with affiliates;
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral.
Lawsuits, Claims, Commitments, Contingencies and Contractual ObligationsContingencies
In the normal course of business, we, or our subsidiary, are the subject of, or party to, lawsuits, environmentalpending or threatened legal proceedings, contingencies and other claims and other contingenciescommitments involving a variety of matters that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civilfines and penalties, remediation costs, or injunctive or declaratory relief.
On May 11, 2016 our predecessor entity filed the Chapter 11 Proceeding. Our bankruptcy case was jointly administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et. al., Case No. 16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding. On the Effective Date the plan became effective and was implemented. The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at JuneSeptember 30, 20182020 and December 31, 2017. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.2019. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations.
For information related to Berry LLC’s emergence from bankruptcy and the terms of the RBL Facility, see “—Chapter 11 Bankruptcy and Our Emergence” and “Description of Other Indebtedness—The RBL Facility.”
We, or our subsidiary, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of JuneSeptember 30, 2018,2020, we are not aware of material indemnity claims pending or threatened against us.
Counterparty Credit Risk
We accounthave certain commitments under contracts, including purchase commitments for goods and services. Prior to our commodity derivatives at fair value. We had three commodity derivative counterparties at2017 emergence, Berry entered into a Carry and Earning Agreement with Encana, effective June 30, 2018 and five at7, 2006, in connection with our Piceance assets which, among other things, required us to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2017.2019, we fulfilled the obligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We did not receive collateralwill defend the matter vigorously, however, given the uncertainty of litigation and the preliminary stage of the case, among other things, at this time we cannot estimate the reasonable possible loss, if any, that may result from anythis action.
Contractual Obligations
The following is a summary of our counterparties.commitments and contractual obligations as of September 30, 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due |
| | Total | | Less Than 1 Year | | 1-3 Years | | 3-5 Years | | Thereafter |
| | (in thousands) |
Debt obligations: | | | | | | | | | | |
RBL Facility | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
2026 Notes | | 400,000 | | | — | | | — | | | — | | | 400,000 | |
Interest(1) | | 150,529 | | | 28,000 | | | 56,000 | | | 56,000 | | | 10,529 | |
Other: | | | | | | | | | | |
| | | | | | | | | | |
Asset retirement obligations(2) | | 150,092 | | | 13,700 | | | — | | | — | | | 136,392 | |
Off-Balance Sheet arrangements: | | | | | | | | | | |
Processing, transportation and storage contracts(3) | | 9,822 | | | 5,350 | | | 4,472 | | | — | | | — | |
Operating lease obligations | | 11,552 | | | 1,848 | | | 3,724 | | | 3,100 | | | 2,880 | |
Other purchase obligations(4) | | 35,100 | | | 18,000 | | | 17,100 | | | — | | | — | |
Total contractual obligations | | $ | 757,095 | | | $ | 66,898 | | | $ | 81,296 | | | $ | 59,100 | | | $ | 549,801 | |
__________
(1) Represents interest on the 2026 Notes computed at 7.0% through contractual maturity in 2026.
(2) Represents the estimated future asset retirement obligations on a discounted basis. We minimizedo not show the credit risklong-term asset retirement obligations by year as we are not able to precisely predict the timing of our derivative instruments by limiting our exposurethese amounts. Because these costs typically extend many years into the future, estimating these future costs requires management to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangementsmake estimates and judgments that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty nettingrevisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See Note 6 for additional information.
(3) Amounts include payments which will become due under long-term agreements governing such derivativesto purchase goods and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Off-Balance Sheet Arrangements
During the six months ended June 30, 2018, there were no significant changes in our consolidated contractual obligations from those reportedservices used in the prospectus.normal course of business to secure transportation of our natural gas production to market, as well as, pipeline, processing and storage capacity.
(4) We have certain commitments under contracts, including purchase commitments for goods and services. We previously had an obligation to a counterparty in connection with our Piceance assets to either build a road or secure a license for alternative access, in lieu of paying a $6 million penalty. As of December 31, 2019, we fulfilled the obligation by delivering the access license pursuant to the agreement. On January 30, 2020, Caerus Piceance LLC, the successor of Encana's interests filed a claim in the City and County of Denver District Court challenging the sufficiency of such access, which we dispute. We will defend the matter vigorously, however, given the uncertainty of litigation and the preliminary stage of the case, among other things, at this time we cannot estimate the reasonable possible loss, if any, that may result from this action. We currently have a drilling commitment in which we are required to drill 97 wells with an estimated total cost of $29 million by August 2022 and 40 of those wells are required to be drilled by July 2021.
Recently AdoptedCritical Accounting Policies and Disclosure Changes
Estimates
See Note 1, Accounting and Disclosure Changes,Basis of Presentation, in the Notes to Consolidated Condensed Financial Statements in Part I, Item 1 of this Form 10-Q.
Safe Harbor StatementCautionary Note Regarding Outlook and Forward-Looking Information
Statements
The information included or incorporated by reference in this documentQuarterly Report includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, maintenance capital requirements,for sustained production levels, expected production and costs, reserves, hedging activities, capital investmentsexpenditures, return of capital, improvement of recovery factors and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal,
guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect us are discussed below in Part II, Item 1A. “Risk Factors” in this Quarterly Report, as well as in Part I, Item 1A. “Risk Factors” our results of operationsmost recent Annual Report on Form 10-K and financial position appear in Risk Factors inother filings with the prospectus.
Securities and Exchange Commission.
Factors (but not necessarily all the factors) that could cause results to differ include among others:
•the length, scope and severity of the ongoing COVID-19 pandemic, including the effects of related public health concerns and the impact of actions taken by governmental authorities and other third parties in response to the pandemic and its impact on commodity prices, supply and demand considerations, and storage capacity;
•global economic trends, geopolitical risks and general economic and industry conditions, such as those resulting from the COVID-19 pandemic and from the actions of foreign producers, importantly including OPEC+ and changes in OPEC+'s production levels;
•volatility of oil, natural gas and NGL prices;prices, including the sharp decline in crude oil prices that occurred in the first quarter and second quarter of 2020;
•the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;
•the California and global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources;
•supply of and demand for oil, natural gas and NGLs;
•disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations;
•inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, and meet our working capital requirements;requirements or fund planned investments;
•price fluctuations and availability of natural gas;gas and electricity and the cost of steam;
•our ability to use derivative instruments to manage commodity price risk;
impact•the regulatory environment, including availability or timing of, environmental, health and safety,conditions imposed on, obtaining and/or maintaining permits and other governmental regulations, and of current approvals, including those necessary for drilling and/or pending legislation;development projects;
uncertainties associated with estimating proved reserves and related future cash flows;
our inability to replace our reserves through exploration and development activities;
•our ability to meet our proposedplanned drilling schedule, including due to our ability to obtain permits on a timely basis or at all, and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
•uncertainties associated with estimating proved reserves and related future cash flows;
•our ability to replace our reserves through exploration and development activities;
•drilling and production results, including lower–than–expected production, reserves or resources from development projects or higher–than–expected decline rates;
•our ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating wells;
•changes in tax laws;
•effects of competition;
•uncertainties and liabilities associated with acquired and divested assets;
•our ability to make acquisitions and successfully integrate any acquired businesses;
market fluctuations in electricity prices and the cost of steam;
asset impairments from commodity price declines;
•large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
•geographical concentration of our operations;
•the creditworthiness and performance of our ability to improve our financial results and profitability following our emergence from bankruptcy and other risks and uncertainties relatedcounterparties with respect to our emergence from bankruptcy;hedges;
changes in tax laws;
•impact of derivatives legislation affecting our ability to hedge;
•failure of risk management and ineffectiveness of internal controls;
concerns about climate change•catastrophic events, including wildfires, earthquakes and other air quality issues;pandemics;
catastrophic events;•environmental risks and liabilities under federal, state, tribal and local laws and regulations (including remedial actions);
•potential liability resulting from pending or future litigation;
•our ability to recruit and/or retain key members of our senior management and key technical employees;
•information technology failures or cyber attacks:attacks; and
•governmental actions and political conditions, as well as the actions by other third parties that are beyond our control.
WeExcept as required by law, we undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.
All forward-looking statements, expressed or implied, included in this reportprospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For the three months ended JuneSeptember 30, 2018,2020, there were no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations (Incorporating Item 7A)- Quantitative and Qualitative Disclosures About Market Risk, in the prospectus.2019 Annual Report, except as discussed below.
Price Risk
Our most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues, certain costs such as fuel gas, and cash flows are likewise affected. In addition, aAdditional non-cash write-down ofimpairment charges for our oil and gas properties may be required if commodity prices experience further significant declines.
We have hedged a significant decline.large portion of our expected crude oil production and our natural gas purchase requirements to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls and puts to hedge. We do not enter into derivative contracts for speculative trading purposes and we have not accounted for our derivatives as cash-flow or fair-value hedges. We continuously consider the level of our oil production and gas purchases that is appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity prices, our expected capital and operating costs, our overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of hedging contained in any credit facility or other debt instrument applicable at the time.
We determine the fair value of our oil and natural gas derivatives using valuation techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We validate data provided by third parties by understanding the valuation inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. At JuneSeptember 30, 2018,2020, the fair value of our hedge positions was a net liabilityasset of approximately $15 million, as determined from prices provided by external sources that are not actively quoted.$58 million. A 10% increase in the oil and natural gas index prices above the JuneSeptember 30, 20182020 prices would result in a net liability of approximately $57 million, which represents a decrease in the fair value ofnet asset to approximately $42 million; conversely, a 10% decrease in the oil and natural gas index prices below the JuneSeptember 30, 20182020 prices would result in a net liability of approximately $4 million, which represents an increase in the fair value ofnet asset to approximately $11$99 million. For additional information about derivative activity, see Note 4.3, Derivatives, in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report.
Counterparty Actual gains or losses recognized related to our derivative contracts depend exclusively on the price of the underlying commodities on the specified settlement dates provided by the derivative contracts.
Credit Risk
We had three commodityOur credit risk relates primarily to trade receivables and derivative counterparties at June 30, 2018, which were all liability positions. We did not receive collateral from anyfinancial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For derivative instruments entered into as part of our counterparties. We minimize the credit risk of our derivative instruments by limiting our exposure to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangements that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateral or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivativesprogram, we are subject to counterparty netting under agreements governing such derivativescredit risk to the extent the counterparty is unable to meet its settlement commitments. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and thereforecontinue to monitor their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.
As of September 30, 2020, the substantial majority of the credit exposure related to our derivative financial instruments was with investment grade counterparties. We believe exposure to credit-related losses at September 30, 2020 was not material and actual losses associated with credit risk of loss due to counterparty nonperformance is somewhat mitigated.
have not been material for all periods presented.
Interest Rate Risk
Our RBL Facility has a variable interest rate on outstanding balances. As of JuneSeptember 30, 2018, there were $66 million outstanding2020, we had no borrowings under our RBL Facility which incurredand thus the interest at floating rates. See Note 3 for additional information regarding interest rates on outstanding debt. As of June 30, 2018, a 1% increase in the respective market rate would result in an estimated $0.7 million increase in annual interest expense.risk exposure is not material. The 2026 Notes have a fixed interest rate and thus we are not exposed to interest rate risk on these.these instruments. See Note 2, Debt, in the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this report for additional information regarding interest rates on our outstanding debt.
Item 4. Controls and Procedures
Our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officerthey each concluded that our disclosure controls and procedures were effective as of JuneSeptember 30, 2018.2020.
There were no changes in the Company’s internal control over financial reporting during the third quarter of 2020 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II – Other Information
Item 1. Legal Proceedings
For information regarding legal proceedings, see Note 54 to the condensed consolidated financial statements in Part I of this Form 10-Q and Note 75 to our consolidated financial statements for the year ended December 31, 20172019 included in the prospectus.Annual Report.
Item 1A. Risk Factors
WeIn addition to factors noted in our most recent Annual Report, additional factors that may impact our financial and operational results, include the following:
Attempts by several states to restrict the production of oil and gas could negatively impact our operations and result in decreased demand for fossil fuels within the state.
Recently, California and Colorado, have taken several actions that could adversely impact oil and gas production in those states. On September 23, 2020, Governor Gavin Newsom of California issued an executive order (the "Order") that seeks to reduce both the supply of and demand for fossil fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of greenhouse gases, including, but not limited to: phasing out the sale of emissions-producing vehicles; developing strategies for the closure and repurposing of oil & gas facilities in California; and ending the issuance of new hydraulic fracturing permits in the state by 2024. The Order also directs CalGEM to finish its review of public health and safety concerns from the impacts of oil extraction activities and propose significantly strengthened regulations, which may include setbacks, to address these concerns by December 31, 2020. Any of these developments may adversely impact both demand for our products or production from our properties.
While the Order does not impose a ban on the issuance of hydraulic fracturing permits, Governor Newsom has announced plans to ask the legislature to pass legislation to this effect. While several California legislators have already indicated that they intend to propose such a ban, the ultimate outcome of any proposed legislation remains uncertain at this time, as past measures to further impose additional stringent requirements upon oil and gas activities in the California legislature were not successful. For example, in both 2019 and 2020, California considered legislation to impose a statewide setback distance between certain oil and natural gas operations and residences, schools, and healthcare facilities. However, in both cases, the proposal failed to receive the approval of the California State Senate.
Separately, in September 2020, the Colorado Oil and Gas Conservation Commission (“COGCC”) announced that it will consider imposing a 2,000-foot setback requirement for drilling and fracking operations statewide, allowing for variances subject to certain conditions. The vote on this rulemaking is expected to take place at the COGCC’s November 6, 2020 meeting. While we cannot predict the final outcome of the COGCC’s actions, any regulation restricting the siting of oil and gas facilities or otherwise imposing more stringent operating controls may adversely impact production from our properties.
The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our operations and financial condition will depend on future developments, which are highly uncertain and cannot be predicted.
In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19. This pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. This resulted in a significant reduction in demand for and prices of crude oil, natural gas and NGL, which was compounded by the announcement by Saudi Arabia of a significant increase in its maximum crude oil production capacity as well as the announcement by Russia that previously agreed upon oil production cuts between members of OPEC+ would expire on August 1, 2020.
In mid-April 2020, members of OPEC+ agreed to certain production cuts; however, these cuts only slightly offset the significant decrease in demand resulting from the COVID-19 pandemic and related economic repercussions. During the second quarter of 2020, the price of Brent crude oil reached historic low of just under $20 per barrel. Although pricing has strengthened slightly, it is still lower than pre-pandemic levels and the current futures forward curve for Brent crude indicates that prices are expected to continue at low levels for an extended time. As of November 1, 2020, the benchmark Brent oil price was $37.46 per barrel as compared to the average benchmark Brent oil price of $63.15 per barrel used to determine our 2019 year end reserves based on SEC pricing.
Additionally, although the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. During the second quarter of 2020, we experienced an adverse widening in the price differential between Brent and California crude due to the lack of local demand and storage capacity. This differential widening improved in the third quarter 2020 as the market storage concerns began to soften, however, if California pricing remains weak, or declines, our financial and operating results will be adversely affected.
If the reduced demand for, and prices of, crude oil and NGLs continue for a prolonged period, our operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected. At the end of March 2020, the Company reduced its planned capital expenditures by more than 50%, which negatively impacted production during the second and third quarters 2020 and may negatively impact future production levels due to the natural production decline of our assets. This, combined with expected lower commodity prices, could materially adversely affect our cash flows and the quantity and value of estimated proved reserves that may be attributed to our properties. A persistent price decline could adversely affect the economics of our existing wells and planned future wells, result in additional impairment charges to existing properties and cause us to delay or abandon planned drilling operations as uneconomical.
Our operations also may be adversely affected if significant portions of our workforce - and that of our customers and suppliers - are unable to work effectively, including because of illness, quarantines, government actions, or other restrictions in connection with the pandemic. Over the later part of March, we implemented workplace restrictions in response to developing government directives and we are continuing to monitor national, state and local government directives where we have operations and/or offices. For several months, most of our personnel worked remotely and many of our key vendors, service suppliers and partners have been as well. Although we managed the transition to temporary work from home arrangements and subsequent office re-openings without a significant loss in business continuity, we incurred additional costs and experienced some inefficiencies during the second and third quarters 2020 as a result. If the ongoing outbreak were to worsen, and additional restrictions be implemented, we may again have to consider remote work arrangements, and certain operational and other business processes could slow which may result in longer time to execute critical business functions, higher operating costs and uncertainties regarding the quality of services and supplies, any of which could adversely affect our operating results for as long as the current pandemic persists and potentially for some time after the pandemic subsides.
The extent to which the COVID-19 pandemic adversely affects our business, results of operations, and financial condition will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by governmental authorities and other third parties in response to the pandemic.
Our ability to operate profitably and our financial condition are highly dependent on energy prices. The outbreak of COVID-19 followed by certain actions taken by OPEC+ caused crude oil prices to decline significantly beginning in the first quarter of 2020 and prices have remained weak and below pre-pandemic levels. If oil prices continue to decline or remain at current levels for a prolonged period, our business, financial condition and results of operations may be materially and adversely affected.
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to various risks
wide fluctuations in response to relatively minor changes in supply and uncertaintiesdemand. Historically, the markets for oil and natural gas have been extremely volatile and these markets will likely continue to be volatile in the coursefuture. The prices we receive for our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
•changes in global supply and demand for oil and natural gas, including changes in demand resulting from general and specific economic conditions relating to the business cycle and other factors (e.g., global health epidemics such as the recent COVID-19 pandemic);
•the actions of OPEC / OPEC+;
•the price and quantity of imports of foreign oil and natural gas;
•political conditions, including embargoes, in or affecting other oil-producing activity;
•the level of global oil and natural gas exploration and production activity
•the level of global oil and natural gas inventories;
•weather conditions;
•technological advances affecting energy consumption; and
•the price and availability of alternative fuels.
Global economic growth drives demand for energy from all sources, including fossil fuels. Historically, when the U.S. and global economies experience weakness, demand for energy has declined. Similarly, should growth in global energy production outstrip demand, excess supplies may arise. Declines in demand and excess supplies may result in accompanying declines in commodity prices and deterioration of our business. A discussionfinancial position along with our ability to operate profitably and our ability to obtain financing to support operations.
In the first quarter of 2020, crude oil prices fell sharply and dramatically, due in part to significantly decreased demand as a result of the COVID-19 pandemic coupled with the increase in supply from the actions of OPEC+. On June 6, 2020, members of OPEC+ agreed to certain production cuts, which slightly offset the decrease in demand resulting from the COVID-19 pandemic. In August 2020, these production cuts were eased slightly and the current output reduction levels are expected to remain through the end of the year.
During the second and third quarters 2020, oil prices recovered slightly from the historical low levels at the beginning of the second quarter as global demand began to increase gradually with containment of the COVID-19 outbreak in areas around the globe and the supply surge was curtailed as members of OPEC+ agreed to certain production cuts. This recovery appears fragile and has flattened, with oil price volatility remaining elevated and oil demand remaining below pre-COVID-19 pandemic levels. Demand, and pricing, may again decline due to the ongoing COVID-19 pandemic, particularly if there is a resurgence of the outbreak during the latter part of the year as some are predicting, although the extent of the additional impact on our industry and our business cannot be reasonably predicted at this time. If storage availability also becomes further constrained, Brent and/or California oil prices may go materially lower and could potentially even become negative as WTI oil prices did on April 20, 2020. If crude oil prices continue to decline or remain at current levels for a prolonged period, our operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected.
Additionally, although the California market generally receives Brent-influenced pricing, California oil prices are determined ultimately by local supply and demand dynamics. Even as Brent pricing fell during the second quarter 2020, we experienced an adverse widening in the price differential between Brent and the California benchmark due to the lack of local demand and storage capacity. Although market conditions improved and the differential widening softened toward the end of the second quarter 2020, if California pricing remains weak, or declines, our financial and operating results will be adversely affected.
Past declines in prices reduced, and any declines that may occur in the future can be expected to reduce, our revenues and profitability as well as the value of our reserves. Such declines adversely affect well and reserve economics and may reduce the amount of oil and natural gas that we can produce economically, resulting in deferral or cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve
sufficiently to support such operations. Any extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
The marketability of our production is dependent upon transportation and storage facilities and other facilities, most of which we do not control, and the availability of such riskstransportation and uncertaintiesstorage capabilities, which have been severely limited by recent market conditions related to the COVID-19 pandemic and the current oversupply of oil and natural gas. If additional facilities do not become available, or, even if such facilities are available, but we are unable to access such facilities on commercially reasonable terms, our operations will likely be interrupted, our production could be curtailed, and our revenues reduced, among other consequences.
The marketing of oil, natural gas and NGLs production depends in large part on the availability, proximity and capacity of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities, as well as the existence of adequate markets. Because of the significantly reduced demand for oil and natural gas as a result of the COVID-19 pandemic and the current oversupply of oil and natural gas in the market, available storage and transportation capacity for our production is limited and may become completely unavailable in the near future. Storage became scarce during the second quarter of 2020 due to the unprecedented dual impact of a severe global oil demand decline coupled with a substantial increase in supply. As traditional tanks filled, large quantities of oil were being stored in offshore tankers around the world, including off the coast of California. Where storage was available, such as offshore tankers, storage costs increased sharply. If the imbalance between supply and demand and the related shortage of storage capacity worsen, the prices we receive for our production could deteriorate and could potentially even become negative as WTI oil prices did on April 20, 2020.
During the second quarter of 2020, we obtained additional storage capacity to support our planned production for the remainder of the year and into 2021. As market conditions improved, we released a portion of the capacity. However, the risk remains that storage for oil may be foundunavailable and our existing capacity may be insufficient to support planned production rates in the event of demand for our oil deteriorating again or a supply surge or both. If we are unable to obtain additional storage capacity if needed, we could be forced to shut-in a significant amount of our California production, as well as curtail some of our Utah and Colorado production, which could have a material, adverse effect on our financial condition, liquidity and operational results. Whether and when we will have to reduce or shut-in production, and the extent and duration to which we may have to do so, cannot be reasonably predicted at this time. If we are forced to shut in production, we will incur additional costs to bring the associated wells back online. While production is shut in, we will likely incur additional costs and operating expenses to, among other things, maintain the health of the reservoirs, meet contractual obligations and protect our interests, but without the associated revenue. Additionally, depending on the duration of the shut-in, and whether we have also shut-in steam injection for the associated reservoirs rather than incur those costs, the wells may not, initially or at all, come back online at similar rates to those at the time of shut-in. Depending on the duration of the steam injection shut-in time, and the resulting inefficiency and economics of restoring the reservoir to its energetic and heated state, our proved reserve estimates could be decreased and there could be potential additional impairments and associated charges to our earnings. A reduction in our reserves could also result in a reduction to our borrowing base under the heading Risk FactorsRBL Facility and our liquidity. The ultimate significance of the impact of any production disruptions, including the extent of the adverse impact on our financial and operational results, will be dictated by the length of time that such disruptions continue which will, in turn, depend on the how long storage remains filled and unavailable to us, which is largely based on the lack of demand for our products due to the impact of the COVID-19 impact, the duration of which is currently unknowable.
In addition to the constraints we face due to storage capacity shortages, the volume of oil and natural gas that we can produce is subject to limitations resulting from pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, and physical damage to the gathering, transportation, storage, processing, fractionation, refining or export facilities that we utilize. The curtailments arising from these and similar circumstances may last from a few days to several months or longer and, in many cases, we may be provided only limited, if any, advance notice as to when these circumstances will arise and their duration. Any such shut in or curtailment, or any inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.
We may not be able to use a portion of our net operating loss carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations, which could adversely affect our net income and cash flows.
We currently have substantial U.S. federal and state net operating loss (“NOL”) carryforwards and U.S. federal general business credits (subject to change each quarter; as of December 31, 2019 estimated U.S. federal and state NOL carryforwards of approximately $122 million and $42 million, respectively, and U.S. federal general business credits of approximately $48 million). Our ability to use these tax attributes to reduce our future U.S. federal and state income tax obligations depends on many factors, including our future taxable income, which cannot be assured. In addition, our ability to use NOL carryforwards and other tax attributes may be subject to significant limitations under Section 382 and Section 383 of the Internal Revenue Code of 1986, as amended (the “Code”). Under those sections of the Code, if a corporation undergoes an “ownership change” (as defined in Section 382 of the Code), the corporation’s ability to use its pre-change NOL carryforwards and other tax attributes may be substantially limited.
Determining the limitations under Section 382 of the Code is technical and highly complex. A corporation generally will experience an ownership change if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. We may in the prospectus.future undergo an ownership change under Section 382 of the Code. If an ownership change occurs, our ability to use our NOL carryforwards and other tax attributes to reduce our future U.S. federal and state income tax obligations may be materially limited, which could adversely affect our net income and cash flows.
The payment of dividends will be at the discretion of our Board of Directors. While we have regularly declared a quarterly dividend since our July 2018 IPO, including a dividend of $0.12 per share for the first quarter of 2020, the payment and amount of future dividend payments, if any, are subject to declaration by our Board of Directors. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deems relevant. Additionally, covenants contained in our RBL Facility and the indentures governing our 2026 Notes could limit the payment of dividends. In April 2020, in response to the unprecedented impact on our business from the significant decline in oil prices and the COVID-19 pandemic, we temporarily suspended our quarterly dividend until oil prices recover. We are under no obligation to make dividend payments on our common stock and cannot be certain when such payments may resume in the future.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds and Issuer Purchases of Equity Securities
DuringStock Repurchase Program
In December 2018, our Board of Directors adopted a program for the quarter ended June 30, 2018, we issued 190,260 RSUs and 117,088 PRSUsopportunistic repurchase of up to certain$100 million of our employeescommon stock. Based on the Board’s evaluation of market conditions for our common stock at that time, they authorized initial repurchases of up to $50 million under the program. In February 2020, the Board of Directors authorized the repurchase of the remaining $50 million of our $100 million repurchase program. Repurchases may be made from time to time in the open market, in privately negotiated transactions or by other means, as determined in the Company's sole discretion. The manner, timing and directors in connectionamount of any purchases will be determined based on our evaluation of market conditions, stock price, compliance with services providedoutstanding agreements and other factors, may be commenced or suspended at any time without notice and does not obligate Berry Corp. to us by such persons. As of August 21, 2018, 681,092 RSUs and 749,833 PRSUs remain outstanding. We also granted 1,566purchase shares of restricted stock to employees in connection with services provided to us by such persons.during any period or at all. Any shares acquired will be available for general corporate purposes.
The offers, sales and issuancesCompany repurchased a total of the securities described in the preceding paragraph were deemed to be exempt from registration either under Rule 701 promulgated5,057,682 shares under the Securities Act in that the transactions were under compensatory benefit plans and contracts relating to compensation, or under Section 4(a)(2) of the Securities Act in that the transactions were between an issuer and members of its senior executive management and did not involve any public offering within the meaning of Section 4(a)(2).
Use of Proceeds
On July 30, 2018, we completed our IPO of common stock pursuant to our registration statement on Form S-1 (File 333-226011), as amended and declared effective by the SEC on July 25, 2018. Goldman Sachs & Co. LLC, Wells Fargo Securities, LLC and BMO Capital Markets Corp. served as representatives of the several underwritersrepurchase program for the IPO. The offering did not terminate before all of the shares in the IPO that were registered in the registration statement were sold. Upon completion of the IPO, we and the selling stockholders sold 13,043,479 shares at a price to the public of $14.00 per share, raising approximately $183 million of gross proceeds, with gross proceeds to Berry of approximately $147 million and gross proceeds to the selling stockholders of approximately $36 million. Of the 13,043,479 shares sold to the public, 10,497,849 shares were issued and sold by us, and 2,545,630 shares were sold by the selling stockholders named in the prospectus. We incurred expenses in connection with the IPO of approximately $2.6$50 million as of JulyDecember 31, 2019. For the nine months ended September 30, 2018. After subtracting underwriting discounts and commissions of approximately $8.8 million and offering expenses, Berry received net proceeds of approximately $136 million. None of the expenses associated with our IPO were paid to directors, officers or persons owning ten percent or
more of our common stock or to their associates, or to our affiliates. We2020, we did not receiverepurchase any proceeds fromshares under the salestock repurchase program.
We used approximately $24 million of the net proceeds from the IPO to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the IPO) from funds affiliated with Benefit Street Partners and Oaktree Capital Management, each of which owned more than ten percent of our common stock prior to the IPO and repurchase. Of the remaining approximately $112 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the amounts we borrowed on the RBL Facility to make the payment to the holders of our Series A Preferred Stock in connection with the conversion of the Series A Preferred Stock to common stock. We used the remainder for working capital.
Item 5. Other Disclosures
Amended and Restated Employment Agreements with Arthur T. Smith, Cary D. Baetz and Gary A. Grove
On August 22, 2018, Berry LLC, a wholly-owned subsidiary of the Company, entered into amended and restated employment agreements with its Chief Executive Officer, Arthur T. “Trem” Smith (the “Smith Agreement”), its Chief Financial Officer, Cary D. Baetz (the “Baetz Agreement”) and its Chief Operating Officer, Gary A. Grove (the “Grove Agreement” and, together with the Smith Agreement and the Baetz Agreement, the “Amended Agreements”), in each case, to replace the executive’s previous employment agreement with the Company (each, a “Prior Agreement”). The Amended Agreements became effective as of August 22, 2018.
Each Amended Agreement modifies certain terms of the corresponding Prior Agreement, including the following:
Each executive is eligible to receive an annual equity award, as determined by the board of directors of the Company or a committee thereof.
Upon a termination of each executive’s employment under certain circumstances, the executive is eligible to receive (a) any earned but unpaid annual bonus for the year prior to the year of termination, (b) a prorated annual bonus for the year of termination and (c) severance in an amount equal to 18 months’ worth, for Mr. Smith, and 12 months’ worth, for Messrs. Baetz and Grove (or, following a Qualifying Termination (as defined in the applicable Amended Agreement), 24 months’ worth for Mr. Smith and 18 months’ worth for Messrs. Baetz and Grove) of the sum of the applicable executive’s base salary and target annual bonus, and reimbursement of up to an equivalent number of months’ worth of health insurance premiums.
Modifies the definition of Good Reason in certain respects.
With respect to the Smith Agreement, Mr. Smith is eligible to receive an annual bonus in a target amount equal to 100% of his then-current base salary.
All other material terms contained in the Prior Agreements remain substantially unchanged in the Amended Agreements. Copies of the Smith Agreement, Baetz Agreement and Grove Agreement are attached hereto as Exhibits 10.14, 10.15 and 10.16, respectively, and are incorporated herein by reference. The description of the material changes to the Prior Agreements contained herein is qualified in its entirety by reference to the full text of the Amended Agreements.
Item 6. Exhibits
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Exhibit Number | | Description |
3.1 | | |
Exhibit Number | | Description |
3.1 | | |
3.2 | | |
3.3 | | |
3.4 | | |
3.510.1 | | |
10.1 | | |
10.2 | | |
10.3 | | |
10.4 | | |
10.5 | | |
10.6 | | |
10.7 | | |
10.8 | | |
10.9 | | |
10.10 | | |
10.11 | | |
10.12 | | |
10.13 | | |
10.14* | | |
10.15* | | |
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31.1* | | |
10.16* | | |
31.1* | | |
31.2* | | |
32.1** | | |
101.INS* | | Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document) |
101.SCH* | | Inline XBRL Taxonomy Extension Schema Document |
101.CAL* | | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
101.DEF* | | Inline XBRL Taxonomy Extension Definition Linkbase Document |
101.LAB* | | Inline XBRL Taxonomy Extension Label Linkbase Data Document |
101.PRE* | | Inline XBRL Taxonomy Extension Presentation Linkbase Document |
| |
* | Filed herewith. |
** | Furnished herewith. |
__________
* Filed herewith.
GLOSSARY OF OIL AND NATURAL GASCOMMONLY USED TERMS
The following are abbreviations and definitions of certain terms that may be used in this report, which are commonly used in the oil and natural gas industry:
“Absolute TSR”means absolute total stockholder return.
“AROs”means asset retirement obligations.
“Adjusted EBITDA” is a non-GAAP financial measure defined as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including gains and losses on sale of assets, restructuring costs and reorganization items.
“Adjusted G&A” or “Adjusted General and Administrative Expenses” is a non-GAAP financial measure defined as general and administrative expenses adjusted for restructuring and other non-recurring costs and non-cash stock compensation expense.
“Adjusted Net Income (Loss)” is a non-GAAP financial measure defined as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items and the income tax expense or benefit of these adjustments using our effective tax rate.
“API” gravity means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity scale developed by the American Petroleum Institute.
“basin” means a large area with a relatively thick accumulation of sedimentary rocks.
“Bbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.
“BLM” means for the U.S. Bureau of Land Management.
“Boe” means barrel of oil equivalent, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.
“Boe/d” means Boe per day.
“Break even” means the Brent price at which we expect to generate positive Levered Free Cash Flow.
“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.
“Btu” means one British thermal unit-aunit—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
“CAA” is an abbreviation for the Clean Air Act, which governs air emissions.
“CalGEM” is an abbreviation for the California Geologic Energy Management Division.
“Cap-and-trade” is a statewide program in California established by the Global Warming Solutions Act of 2006 which outlined an enforceable compliance obligation beginning with 2013 GHG emissions and currently extended through 2030.
“CARB” is an abbreviation for the California Air Resources Board.
“CCA” or “CCAs” is an abbreviation for California carbon allowances.
“CERCLA” is an abbreviation for the Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous substances have been released into the environment (commonly known as “Superfund”).
“Clean Water Rule” refers to the rule issued in August 2015 by the EPA and U.S. Army Corps of Engineers which expanded the scope of the federal jurisdiction over wetlands and other types of waters.
“COGCC” is an abbreviation for the Colorado Oil and Gas Conservation Commission.
“Completion” means the installation of permanent equipment for the production of oil or natural gas.
“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“CPUC” is an abbreviation for the California Public Utilities Commission.
“CWA” is an abbreviation for the Clean Water Act, which governs discharges to and excavations within the waters of the United States.
“DD&A” means depreciation, depletion & amortization.
“Development drilling”or “Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.
“Diatomite” means a sedimentary rock composed primarily of siliceous, diatom shells.
“Differential” means an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.
"EH&S" is an abbreviation for Environmental, Health & Safety.
“Enhanced oil recovery” means a technique for increasing the amount of oil that can be extracted from a field.
“EOR” means enhanced oil recovery.
“Estimated ultimate recoveryEPA” or is an abbreviation for the United States Environmental Protection Agency.
“EUREPS” meansis an abbreviation for earnings per share.
“ESA” is an abbreviation for the sum of reserves remaining as of a given date and cumulative production as of that date. EUR is shown on a combined basis for oil and natural gas.federal Endangered Species Act.
“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.
“FASB” is an abbreviation for the Financial Accounting Standards Board.
“FERC” is an abbreviation for the Federal Energy Regulatory Commission.
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
“FIP” is an abbreviation for Federal Implementation Plan.
“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.
“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.
“GAAP” is an abbreviation for U.S. generally accepted accounting principles.
“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
“Gross AcresGHG” or “GHGs” is an abbreviation for greenhouse gases.
“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working interest.
“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.
“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.
“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability.
“Horizontal drilling” means a wellbore that is drilled laterally.
“ICE” means Intercontinental Exchange.
“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.
“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.
“IOR” means improved oil recovery.
“IPO”is an abbreviation for initial public offering.
“LCFS” is an abbreviation for low carbon fuel standard.
“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.
“Levered Free Cash Flow” is a non-GAAP financial measure defined as Adjusted EBITDA less interest expense, dividends and capital expenditures.
“LIBOR” is an abbreviation for London Interbank Offered Rate.
“MBbl” means one thousand barrels of oil, condensate or NGLs.
“MBbl/d” means MBbl per day.
“MBoe” means one thousand barrels of oil equivalent.
“MBoe/d” means MBoe per day.
“Mcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.
“MMBbl” means one million barrels of oil, condensate or NGLs.
“MMBoe” means one million barrels of oil equivalent.
“MMBtu” means one million Btus.
“MMBtu/d” means MMBtu per day.
“MMcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.
“MMcf/d” means MMcf per day.
“MTBA” is an abbreviation for Migratory Bird Treaty Act.
“MW” means megawatt.
“MWHs”means megawatt hours.
“NAAQS” is an abbreviation for the National Ambient Air Quality Standard.
“NASDAQ” means Nasdaq Global Select Market.
“NEPA” is an abbreviation for the National Environmental Policy Act, which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands.
“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.
“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
“NGA” is an abbreviation for the Natural Gas Act.
“NGL” or “NGLs” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
“NRI” is an abbreviation for net revenue interest.
“NYMEX” means New York Mercantile Exchange.
“Oil” means crude oil or condensate.
“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.
“OSHA” is an abbreviation for the Occupational Safety and Health Act of 1970.
“OTC”means over-the-counter
“PALs” is an abbreviation for project approval letters.
“PCAOB” is an abbreviation for the Public Company Accounting Oversight Board.
“PDNP” is an abbreviation for proved developed non-producing.
“PDP” is an abbreviation for proved developed producing.
“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.
“PHMSA” is an abbreviation for the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration.
“Play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations.
“Porosity” means the total pore volume per unit volume of rock.
“PPA” is an abbreviation for power purchase agreement.
“Production costs” means costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.
“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.
“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing equipment and operating methods.
“Proved reserves” means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“PSUs” means performance-based restricted stock units
“PURPA” is an abbreviation for the Public Utility Regulatory Policies Act.
“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. While this measure does not include the effect of income
taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.
“QF” means qualifying facility.
“RCRA” is an abbreviation for the Resource Conservation and Recovery Act, which governs the management of solid waste.
“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.
“Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.
“Relative TSR” means relative total stockholder return.
“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.
“RSUs” is an abbreviation for restricted stock units.
“SARs” is an abbreviation for stock appreciation rights.
“SDWA” is an abbreviation for the Safe Drinking Water Act, which governs the underground injection and disposal of wastewater;.
“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.
“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.
“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“SPCC plans” means spill prevention, control and countermeasure plans.
“Steamflood” means cyclic or continuous steam injection.
“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Stimulating” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.
“Strip Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules with the exception of pricing that is based on average annual forward-month ICE (Brent) oil and NYMEX Henry Hub natural gas contract pricing in effect on a given date to reflect the market expectations as of that date.
“Superfund” is a commonly known term for CERLA.
“UIC” is an abbreviation for the Underground Injection Control program.
“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.
“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Unproved reserves” means reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
“Wellbore” means the hole drilled by the bit that is equipped for natural gasresource production on a completed well. Also called well or borehole.
“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.
“Workover” means maintenance on a producing well to restore or increase production.
“WST” is an abbreviation for well stimulation treatment.
“WTI” means West Texas Intermediate.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | Berry Corporation (bry) |
| BERRY PETROLEUM CORPORATION | (Registrant) |
| (Registrant) | |
Date: | November 4, 2020 | /s/ Cary Baetz |
Date: August 23, 2018 | /s/ Michael S. Helm | Cary Baetz |
| Michael S. Helm |
| Chief Accounting Officer |
| (Duly Authorized Officer and Principal Accounting Officer) |
| |
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Date: August 23, 2018 | /s/ Cary Baetz |
| Cary Baetz |
| Executive Vice President and |
| | Chief Financial Officer |
| | (Principal Financial Officer) |
| | |
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Date: | November 4, 2020 | /s/ M. S. Helm |
| | Michael S. Helm |
| | Chief Accounting Officer |
| | (Principal Accounting Officer) |