Delaware | 001-38606 | 81-5410470 | ||
(State or Other Jurisdiction of Incorporation) | (Commission File Number) | (IRS Employer Identification No.) |
☐ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
☐ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
☐ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
☐ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Title of each class Common Stock, par value $0.001 per share | Trading Symbol BRY | Name of each exchange on which registered Nasdaq Global Select Market |
Item 2.02 | Results of Operations and Financial Condition. |
Item 9.01 | Financial Statements and Exhibits. |
Exhibit No. | Description | |
99.1 |
BERRY CORPORATION (bry) | ||
By: | /s/ Cary Baetz | |
Cary Baetz | ||
Executive Vice President and Chief Financial Officer |
• | California production increased 18% over prior year fourth quarter and 11% sequentially |
• | Fourth quarter production mix was 89% oil |
• | Adjusted EBITDA(1) of $87 million and Unhedged Adjusted EBITDA(1) of $72 million |
• | Capital expenditures of $42 million with approximately 84% directed to development in California |
• | Repurchased 1.4 million shares in fourth quarter and nearly 5.1 million shares to date for $50 million |
• | Oil production up 15% compared to prior year and comprised 87% of total production |
• | Adjusted EBITDA of $302 million and Unhedged Adjusted EBITDA of $260 million |
• | Capital expenditures of $211 million with approximately 91% directed to California assets |
• | Repurchased 4.6 million shares for $46 million and paid over $39 million in dividends |
• | Replaced nearly 300%(2) of California reserves and 159%(2) of total company PUD inventory |
• | Increased inventory to over 10,800 locations |
• | Total company PV-10(1) of over $1.8 billion, including $1.7 billion for California |
(1) | Please see "Non-GAAP Financial Measures and Reconciliations" later in this press release for a reconciliation and more information on these Non-GAAP measures. |
(2) | Please see " Non-GAAP Financial Measures and Reconciliations" later in this press release for more information on how we calculate reserve replacement ratios and total company PUD inventory replacement ratios. |
Full-Year 2020 Guidance | Low | High | |
Average Daily Production (MBoe/d) | 29.5 | 32.5 | |
Oil as % of Production | ~90% | ||
Operating Expenses ($/Boe) | $19.00 | $21.00 | |
Taxes, Other than Income Taxes ($/Boe) | $4.00 | $4.50 | |
Adjusted General & Administrative (G&A) expenses ($/Boe) | $4.75 | $5.25 | |
Capital Expenditures ($ millions) | $125 | $145 | |
New Drill Wells | 195 | 225 |
Live Call Date: | Thursday, February 27, 2020 |
Live Call Time: | 9:00 a.m. Eastern Time (6 a.m. Pacific Time) |
Live Call Dial-in: | 877-491-5169 from the U.S. |
720-405-2254 from international locations | |
Live Call Passcode: | 2697719 |
Replay Dates: | Through Thursday, March 11, 2020 |
Replay Dial-in: | 855-859-2056 from the U.S. |
404-537-3406 from international locations | |
Replay Passcode: | 2697719 |
• | financial position, |
• | liquidity, |
• | cash flows, |
• | anticipated financial and operating results, |
• | our capital program and development and production plans, |
• | business strategy, |
• | potential acquisition opportunities, |
• | other plans and objectives for operations, |
• | maintenance capital requirements, |
• | expected production and costs, |
• | reserves, |
• | hedging activities, |
• | return of capital, |
• | payment of future dividends, |
• | future repurchases of stock or debt, |
• | capital investments and other guidance. |
• | volatility of oil, natural gas and natural gas liquids (NGL) prices; |
• | price and availability of natural gas and electricity; |
• | availability and the timing of required permits and approvals and our inability to meet existing or new conditions imposed on those permits and approvals; |
• | our ability to meet our planned drilling schedule, including our inability to obtain permits on a timely basis or at all, and our ability to successfully drill wells that produce oil and natural gas in commercially viable quantities; |
• | the impact of current laws and regulations, and of pending or future legislative or regulatory changes, 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; |
• | our ability to use derivative instruments to manage commodity price risk; |
• | inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures and to meet working capital requirements; |
• | the impact of environmental, health and safety, and other governmental regulations, and of current or pending or future legislation; |
• | uncertainties associated with estimating proved reserves and related future cash flows; |
• | our ability to replace our reserves through exploration and development activities; |
• | lower-than-expected production or reserves from development projects or higher-than-expected decline rates; |
• | untimely or unavailable drilling and completion equipment or crew unavailability or lack of access to necessary resources for drilling, completing and operating wells; |
• | our ability to make acquisitions and successfully integrate any acquired businesses; |
• | catastrophic events; |
• | market fluctuations in electricity prices and the cost of steam; and |
• | other material risks that appear in the Risk Factors section of our Annual Report on Form 10-K and other periodic reports filed with the Securities and Exchange Commission. |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ and shares in thousands, except per share amounts) | |||||||||||||||||||
Consolidated Statement of Operations Data: | |||||||||||||||||||
Revenues and other: | |||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 156,336 | $ | 141,250 | $ | 142,861 | $ | 565,596 | $ | 552,874 | |||||||||
Electricity sales | 6,844 | 7,460 | 9,517 | 29,397 | 35,208 | ||||||||||||||
Gains (losses) on oil derivatives | (45,544 | ) | 45,509 | 127,160 | (37,998 | ) | (4,621 | ) | |||||||||||
Marketing revenues | 437 | 413 | 534 | 2,094 | 2,322 | ||||||||||||||
Other revenues | 55 | 40 | 274 | 316 | 774 | ||||||||||||||
Total revenues and other | 118,128 | 194,672 | 280,346 | 559,405 | 586,557 | ||||||||||||||
Expenses and other: | |||||||||||||||||||
Lease operating expenses | 59,529 | 50,957 | 51,308 | 216,294 | 188,776 | ||||||||||||||
Electricity generation expenses | 4,785 | 3,781 | 6,764 | 19,490 | 20,619 | ||||||||||||||
Transportation expenses | 2,124 | 2,067 | 2,220 | 8,059 | 9,860 | ||||||||||||||
Marketing expenses | 403 | 398 | 716 | 2,073 | 2,140 | ||||||||||||||
General and administrative expenses | 15,710 | 16,434 | 16,130 | 62,643 | 54,026 | ||||||||||||||
Depreciation, depletion, amortization and accretion | 30,102 | 27,664 | 24,253 | 106,006 | 86,271 | ||||||||||||||
Impairment of oil and gas properties | 51,081 | — | — | 51,081 | — | ||||||||||||||
Taxes, other than income taxes | 11,962 | 9,249 | 7,829 | 40,645 | 33,117 | ||||||||||||||
(Gains) losses on natural gas derivatives | (3,385 | ) | 3,008 | (4,477 | ) | 6,957 | (6,357 | ) | |||||||||||
Other operating expenses (income) | 774 | (550 | ) | (3,269 | ) | 4,588 | (2,747 | ) | |||||||||||
Total expenses and other | 173,085 | 113,008 | 101,474 | 517,836 | 385,705 | ||||||||||||||
Other income (expenses): | |||||||||||||||||||
Interest expense | (7,871 | ) | (8,597 | ) | (8,820 | ) | (34,234 | ) | (35,648 | ) | |||||||||
Other, net | — | (77 | ) | 108 | 80 | 243 | |||||||||||||
Total other income (expenses) | (7,871 | ) | (8,674 | ) | (8,712 | ) | (34,154 | ) | (35,405 | ) | |||||||||
Reorganization items, net | — | (170 | ) | 1,498 | (426 | ) | 24,690 | ||||||||||||
Income (loss) before income taxes | (62,828 | ) | 72,820 | 171,658 | 6,989 | 190,137 | |||||||||||||
Income tax expense (benefit) | (55,844 | ) | 20,171 | 39,890 | (36,550 | ) | 43,035 | ||||||||||||
Net income (loss) | (6,984 | ) | 52,649 | 131,768 | 43,539 | 147,102 | |||||||||||||
Series A preferred stock dividends and conversion to common stock | — | — | — | — | (97,942 | ) | |||||||||||||
Net income (loss) attributable to common stockholders | $ | (6,984 | ) | $ | 52,649 | $ | 131,768 | $ | 43,539 | $ | 49,160 | ||||||||
Net income (loss) per share attributable to common stockholders | |||||||||||||||||||
Basic(a) | $ | (0.09 | ) | $ | 0.65 | $ | 1.56 | $ | 0.54 | $ | 0.85 | ||||||||
Diluted(a) | $ | (0.09 | ) | $ | 0.65 | $ | 1.56 | $ | 0.53 | $ | 0.85 | ||||||||
Weighted-average common shares outstanding - basic(a) | 80,435 | 80,982 | 84,367 | 81,379 | 57,743 | ||||||||||||||
Weighted-average common shares outstanding - diluted(a) | 80,435 | 81,051 | 84,592 | 81,951 | 57,932 | ||||||||||||||
Adjusted net income (loss)(b) | $ | 33,189 | $ | 32,760 | $ | 34,809 | $ | 110,228 | $ | 100,001 | |||||||||
Weighted-average common shares outstanding - diluted | 80,788 | 81,051 | 84,592 | 81,951 | 79,633 | ||||||||||||||
Diluted earnings per share on adjusted net income | $ | 0.41 | $ | 0.40 | $ | 0.41 | $ | 1.35 | $ | 1.26 | |||||||||
Adjusted EBITDA(b) | $ | 86,995 | $ | 83,931 | $ | 81,669 | $ | 302,184 | $ | 257,924 | |||||||||
Adjusted EBITDA unhedged(b) | $ | 71,529 | $ | 68,778 | $ | 72,990 | $ | 259,987 | $ | 296,406 | |||||||||
Levered free cash flow(b) | $ | 27,695 | $ | 2,126 | $ | 9,531 | $ | 17,802 | $ | 45,787 | |||||||||
Levered free cash flow unhedged(b) | $ | 12,229 | $ | (13,027 | ) | $ | 852 | $ | (24,395 | ) | $ | 84,269 |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ and shares in thousands, except per share amounts) | |||||||||||||||||||
Adjusted general and administrative expenses(b) | $ | 13,421 | 13,940 | $ | 11,533 | $ | 51,226 | $ | 40,668 | ||||||||||
Effective Tax Rate | 89 | % | 28 | % | 23 | % | (523 | )% | 23 | % | |||||||||
Cash Flow Data: | |||||||||||||||||||
Net cash provided by (used in) operating activities(c) | $ | 86,036 | $ | 65,320 | $ | 94,511 | $ | 241,829 | $ | 105,471 | |||||||||
Net cash provided by (used in) investing activities | $ | (57,361 | ) | $ | (60,285 | ) | $ | (35,438 | ) | $ | (225,025 | ) | $ | (121,440 | ) | ||||
Net cash provided by (used in) financing activities | $ | (28,675 | ) | $ | (5,262 | ) | $ | (14,306 | ) | $ | (85,484 | ) | $ | 15,911 |
(a) | Our weighted-average common shares outstanding increased beginning in the third quarter of 2018 for additional shares from our initial public offering and preferred stock conversion. We retrospectively adjusted for 2,770,000 shares issued instead of the 7,080,000 shares that were reserved for holders of allowed Unsecured Notes and General Unsecured Claims in our earnings per share calculations for 2018. |
(b) | See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”. |
(c) | Year ended December 31, 2018 includes approximately $127 million paid to early terminate unsettled derivative contracts. The elective cancellation was effected to realign our hedging pricing with current market rates and move from NYMEX WTI to ICE Brent underlying. Had we not elected to cancel these derivative contracts our net cash provided by operating activities would have been approximately $230 million. |
Berry Corporation (bry) | |||||||
December 31, 2019 | December 31, 2018 | ||||||
($ and shares in thousands) | |||||||
Balance Sheet Data: | |||||||
Total current assets | $ | 100,432 | $ | 229,022 | |||
Total property, plant and equipment, net | $ | 1,576,267 | $ | 1,442,708 | |||
Total current liabilities | $ | 156,628 | $ | 144,118 | |||
Long-term debt | $ | 394,319 | $ | 391,786 | |||
Total equity | $ | 972,448 | $ | 1,006,446 | |||
Outstanding common stock shares as of(d) | 79,543 | 81,202 |
(d) | At December 31, 2018, excludes 2,770,000 common stock shares negotiated with general unsecured creditors electing to settle claims in exchange for common shares subsequent to December 31, 2018. |
California (San Joaquin and Ventura basins) | Utah (Uinta basin) | Colorado (Piceance basin) | ||||||||||||||||||
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ in thousands, unless noted otherwise) | ||||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 498,325 | $ | 471,802 | $ | 59,383 | $ | 65,605 | $ | 7,740 | $ | 10,657 | ||||||||
Operating income(a) | $ | 230,500 | $ | 185,965 | $ | 7,624 | $ | 15,066 | $ | (48,955 | ) | $ | 6,346 | |||||||
Depreciation, depletion, and amortization (DD&A) | $ | 93,025 | $ | 72,260 | $ | 11,754 | $ | 10,420 | $ | 1,055 | $ | 646 | ||||||||
Impairment of oil and gas properties | $ | — | $ | — | $ | — | $ | — | $ | 51,081 | $ | — | ||||||||
Average daily production (MBoe/d) | 22.6 | 19.7 | 5.0 | 5.0 | 1.4 | 1.7 | ||||||||||||||
Production (oil % of total) | 100 | % | 100 | % | 54 | % | 48 | % | 2 | % | 1 | % | ||||||||
Realized sales prices: | ||||||||||||||||||||
Oil (per Bbl) | $ | 60.51 | $ | 65.64 | $ | 45.72 | $ | 57.30 | $ | 52.36 | $ | 61.50 | ||||||||
NGLs (per Bbl) | $ | — | $ | — | $ | 17.08 | $ | 26.95 | $ | — | $ | — | ||||||||
Gas (per Mcf) | $ | — | $ | — | $ | 2.94 | $ | 2.68 | $ | 2.26 | $ | 2.75 | ||||||||
Capital expenditures(b) | $ | 191,955 | $ | 125,565 | $ | 10,229 | $ | 16,738 | $ | 603 | $ | 613 | ||||||||
Total proved reserves (MMBoe) | 122 | 106 | 15 | 19 | 1 | 18 |
(a) | Operating income includes oil, natural gas and NGL sales, marketing revenues, other revenues, and scheduled oil derivative settlements, offset by operating expenses, general and administrative expenses, DD&A, impairment of oil and gas properties, and taxes, other than income taxes. |
(b) | Excludes corporate capital expenditures. |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
Realized Prices | |||||||||||||||||||
Oil without hedge ($/Bbl) | $ | 59.28 | $ | 57.92 | $ | 61.48 | $ | 58.93 | $ | 64.76 | |||||||||
Effects of scheduled derivative settlements ($/Bbl) | $ | 5.70 | $ | 7.31 | $ | 2.88 | $ | 4.68 | $ | (5.09 | ) | ||||||||
Oil with hedge ($/Bbl) | $ | 64.98 | $ | 65.23 | $ | 64.36 | $ | 63.61 | $ | 59.67 | |||||||||
Natural gas ($/Mcf) | $ | 2.60 | $ | 2.12 | $ | 3.86 | $ | 2.66 | $ | 2.74 | |||||||||
NGLs ($/Bbl) | $ | 14.60 | $ | 12.10 | $ | 20.39 | $ | 17.02 | $ | 26.74 | |||||||||
Index Prices | |||||||||||||||||||
Brent oil ($/Bbl) | $ | 62.42 | $ | 62.03 | $ | 68.08 | $ | 64.16 | $ | 71.69 | |||||||||
WTI oil ($/Bbl) | $ | 57.02 | $ | 56.33 | $ | 58.81 | $ | 57.03 | $ | 64.81 | |||||||||
Kern, Delivered natural gas ($/MMBtu)(a) | $ | 2.99 | $ | 2.50 | $ | 4.40 | $ | 3.14 | $ | 3.36 | |||||||||
Henry Hub natural gas (S/MMBtu) | $ | 2.40 | $ | 2.38 | $ | 3.64 | $ | 2.56 | $ | 3.15 |
(a) | Kern, Delivered Index is the relevant index used for gas purchases in California. |
Q1 2020 | Q2 2020 | Q3 2020 | Q4 2020 | FY 2021 | |||||||||||||||
Fixed Price Oil Swaps (Brent): | |||||||||||||||||||
Hedged volume (MBbls) | 1,729 | 1,456 | 1,472 | 1,472 | 730 | ||||||||||||||
Weighted-average price ($/Bbl) | $ | 63.92 | $ | 64.30 | $ | 64.21 | $ | 64.21 | $ | 58.50 | |||||||||
Fixed Price Oil Swaps (WTI): | |||||||||||||||||||
Hedged volume (MBbls) | 91 | 30 | — | — | — | ||||||||||||||
Weighted-average price ($/Bbl) | $ | 61.75 | $ | 61.75 | $ | — | $ | — | $ | — | |||||||||
Fixed Price Gas Purchase Swaps (Kern, Delivered): | |||||||||||||||||||
Hedged volume (MMBtu) | 5,005,000 | 5,005,000 | 5,060,000 | 2,315,000 | 900,000 | ||||||||||||||
Weighted-average price ($/MMBtu) | $ | 2.89 | $ | 2.89 | $ | 2.89 | $ | 2.79 | $ | 2.50 | |||||||||
Fixed Price Gas Purchase Swaps (SoCal Citygate): | |||||||||||||||||||
Hedged volume (MMBtu) | 455,000 | 455,000 | 460,000 | 155,000 | — | ||||||||||||||
Weighted-average price ($/MMBtu) | $ | 3.80 | $ | 3.80 | $ | 3.80 | $ | 3.80 | $ | — |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ in thousands except per Boe amounts) | |||||||||||||||||||
Expenses: | |||||||||||||||||||
Lease operating expenses | $ | 59,529 | $ | 50,957 | $ | 51,308 | $ | 216,294 | $ | 188,776 | |||||||||
Electricity generation expenses | 4,785 | 3,781 | 6,764 | 19,490 | 20,619 | ||||||||||||||
Electricity sales(1) | (6,844 | ) | (7,460 | ) | (9,517 | ) | (29,397 | ) | (35,208 | ) | |||||||||
Transportation expenses | 2,124 | 2,067 | 2,220 | 8,059 | 9,860 | ||||||||||||||
Transportation sales(1) | (55 | ) | (40 | ) | (274 | ) | (316 | ) | (774 | ) | |||||||||
Marketing expenses | 403 | 398 | 716 | 2,073 | 2,140 | ||||||||||||||
Marketing revenues(1) | (437 | ) | (413 | ) | (534 | ) | (2.094 | ) | (2,322 | ) | |||||||||
Derivative settlements (received) paid for gas purchases(a) | (906 | ) | 2,088 | (2,407 | ) | 1,050 | (2,407 | ) | |||||||||||
Total operating expenses(a) | $ | 58,599 | $ | 51,378 | $ | 48,276 | $ | 217,251 | $ | 180,684 | |||||||||
Expenses per Boe:(a) | |||||||||||||||||||
Lease operating expenses | $ | 20.69 | $ | 18.74 | $ | 19.96 | $ | 20.42 | $ | 19.16 | |||||||||
Electricity generation expenses | 1.66 | 1.39 | 2.63 | 1.84 | 2.09 | ||||||||||||||
Electricity sales | (2.38 | ) | (2.74 | ) | (3.70 | ) | (2.77 | ) | (3.57 | ) | |||||||||
Transportation expenses | 0.74 | 0.76 | 0.86 | 0.76 | 1.00 | ||||||||||||||
Transportation sales | (0.02 | ) | (0.01 | ) | (0.11 | ) | (0.03 | ) | (0.08 | ) | |||||||||
Marketing expenses | 0.14 | 0.15 | 0.28 | 0.20 | 0.22 | ||||||||||||||
Marketing revenues | (0.15 | ) | (0.15 | ) | (0.21 | ) | (0.20 | ) | (0.24 | ) | |||||||||
Derivative settlements (received) paid for gas purchases | (0.31 | ) | 0.77 | (0.94 | ) | 0.10 | (0.24 | ) | |||||||||||
Total operating expenses (per Boe)(b) | $ | 20.37 | $ | 18.90 | $ | 18.77 | $ | 20.32 | $ | 18.33 | |||||||||
Total unhedged operating expenses(b) | $ | 20.68 | $ | 18.13 | $ | 19.71 | $ | 20.22 | $ | 18.57 | |||||||||
Total MBoe | 2,877 | 2,719 | 2,571 | 10,594 | 9,855 |
(a) | 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 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 also includes the effect of derivative settlements (received or paid) for gas purchases. |
(b) | Total unhedged operating expenses equals total operating expenses less the derivatives settlements paid for gas purchases |
Berry Corporation (bry) | ||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | ||||||||||
Net Oil, Natural Gas and NGLs Production Per Day(a): | ||||||||||||||
Oil (MBbl/d) | ||||||||||||||
California | 25.5 | 23.0 | 21.7 | 22.6 | 19.7 | |||||||||
Utah | 2.2 | 2.7 | 2.0 | 2.7 | 2.3 | |||||||||
Colorado | — | — | — | — | — | |||||||||
Total oil | 27.7 | 25.7 | 23.7 | 25.3 | 22.0 | |||||||||
Natural gas (MMcf/d) | ||||||||||||||
California | — | — | — | — | — | |||||||||
Utah | 10.7 | 12.1 | 9.8 | 11.2 | 12.0 | |||||||||
Colorado | 8.2 | 8.8 | 9.6 | 8.8 | 10.1 | |||||||||
East Texas(b) | — | — | 2.8 | — | 4.2 | |||||||||
Total natural gas | 18.9 | 20.9 | 22.1 | 20.0 | 26.3 | |||||||||
NGLs (MBbl/d) | ||||||||||||||
California | — | — | — | — | — | |||||||||
Utah | 0.4 | 0.4 | 0.6 | 0.4 | 0.6 | |||||||||
Colorado | — | — | — | — | — | |||||||||
Total NGLs | 0.4 | 0.4 | 0.6 | 0.4 | 0.6 | |||||||||
Total Production (MBoe/d)(c) | 31.3 | 29.6 | 28.0 | 29.0 | 27.0 |
(a) | Production represents volumes sold during the period. |
(b) | On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin. |
(c) | Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis. |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
(in thousands) | |||||||||||||||||||
Capital expenditures (accrual basis) | $ | 41,877 | $ | 63,488 | $ | 53,326 | $ | 211,095 | $ | 147,831 |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ thousands, except per share amounts) | |||||||||||||||||||
Net income (loss) | $ | (6,984 | ) | $ | 52,649 | $ | 131,768 | $ | 43,539 | $ | 147,102 | ||||||||
Subtract: prior period income tax credits | (38,653 | ) | — | — | (38,653 | ) | — | ||||||||||||
Add (Subtract): | |||||||||||||||||||
(Gains) losses on oil and natural gas derivatives | 42,159 | (42,501 | ) | (131,637 | ) | 44,955 | (1,735 | ) | |||||||||||
Net cash received (paid) for scheduled derivative settlements | 15,466 | 15,153 | 8,679 | 42,197 | (38,482 | ) | |||||||||||||
Other operating expenses (income) | 774 | (550 | ) | (3,269 | ) | 4,588 | (2,747 | ) | |||||||||||
Impairment of oil & gas properties | 51,081 | — | — | 51,081 | — | ||||||||||||||
Restructuring and other non-recurring costs | — | 219 | 1,414 | 3,061 | 6,773 | ||||||||||||||
Reorganization items, net | — | 170 | (1,498 | ) | 426 | (24,690 | ) | ||||||||||||
Total additions (subtractions), net | 109,480 | (27,509 | ) | (126,311 | ) | 146,308 | (60,881 | ) | |||||||||||
Income tax (expense) benefit of adjustments at effective tax rate(1) | (30,654 | ) | 7,620 | 29,352 | (40,966 | ) | 13,780 | ||||||||||||
Adjusted net income (loss) | $ | 33,189 | $ | 32,760 | $ | 34,809 | $ | 110,228 | $ | 100,001 | |||||||||
Basic EPS on adjusted net income | $ | 0.41 | $ | 0.40 | $ | 0.41 | $ | 1.35 | $ | 1.73 | |||||||||
Diluted EPS on adjusted net income | $ | 0.41 | $ | 0.40 | $ | 0.41 | $ | 1.35 | $ | 1.26 | |||||||||
Weighted average shares outstanding - basic | 80,435 | 80,982 | 84,367 | 81,379 | 57,743 | ||||||||||||||
Weighted average shares outstanding - diluted | 80,788 | 81,309 | 84,592 | 81,379 | 79,633 |
(1) | Excludes prior year income tax credits from the total additions (subtractions), net line item and the tax effect the prior tax credits have on the current year effective tax rate. |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ thousands) | |||||||||||||||||||
Net income (loss) | $ | (6,984 | ) | $ | 52,649 | $ | 131,768 | $ | 43,539 | $ | 147,102 | ||||||||
Add (Subtract): | |||||||||||||||||||
Interest expense | 7,871 | 8,597 | 8,820 | 34,234 | 35,648 | ||||||||||||||
Income tax expense (benefit) | (55,845 | ) | 20,171 | 39,890 | (36,550 | ) | 43,035 | ||||||||||||
Depreciation, depletion, and amortization | 30,102 | 27,664 | 24,253 | 106,006 | 86,271 | ||||||||||||||
Impairment of oil and gas properties | 51,081 | — | — | 51,081 | — | ||||||||||||||
Derivative (gains) losses | 42,160 | (42,501 | ) | (131,637 | ) | 44,955 | (1,735 | ) | |||||||||||
Net cash received (paid) for scheduled derivative settlements | 15,466 | 15,153 | 8,679 | 42,197 | (38,482 | ) | |||||||||||||
Other operating expenses (income) | 774 | (550 | ) | (3,269 | ) | 4,588 | (2,747 | ) | |||||||||||
Stock compensation expense | 2,370 | 2,360 | 3,249 | 8,647 | 6,750 | ||||||||||||||
Restructuring and other non-recurring costs | — | 219 | 1,414 | 3,061 | 6,773 | ||||||||||||||
Reorganization items, net | — | 170 | (1,498 | ) | 426 | (24,690 | ) | ||||||||||||
Adjusted EBITDA | $ | 86,995 | $ | 83,931 | $ | 81,669 | $ | 302,184 | $ | 257,924 | |||||||||
Net cash (received) paid for scheduled derivative settlements | (15,466 | ) | (15,153 | ) | (8,679 | ) | (42,197 | ) | 38,482 | ||||||||||
Adjusted EBITDA unhedged | $ | 71,529 | $ | 68,778 | $ | 72,990 | $ | 259,987 | $ | 296,406 | |||||||||
Net cash provided by operating activities | $ | 86,036 | $ | 65,320 | $ | 94,511 | $ | 241,829 | $ | 105,471 | |||||||||
Add (Subtract): | |||||||||||||||||||
Cash interest payments | 584 | 14,864 | 562 | 30,720 | 19,761 | ||||||||||||||
Cash income tax (refunds) | (3 | ) | — | (1,901 | ) | (2 | ) | (1,901 | ) | ||||||||||
Cash reorganization item (receipts) payments | — | — | (174 | ) | — | 832 | |||||||||||||
Restructuring and other non-recurring costs | — | 219 | 1,414 | 3,061 | 6,773 | ||||||||||||||
Derivative early termination payment | — | — | — | — | 126,949 | ||||||||||||||
Other changes in operating assets and liabilities | 378 | 3,528 | (12,743 | ) | 26,576 | 39 | |||||||||||||
Adjusted EBITDA | $ | 86,995 | $ | 83,931 | $ | 81,669 | $ | 302,184 | $ | 257,924 | |||||||||
Net cash (received) paid for scheduled derivative settlements | (15,466 | ) | (15,153 | ) | (8,679 | ) | (42,197 | ) | 38,482 | ||||||||||
Adjusted EBITDA unhedged | $ | 71,529 | $ | 68,778 | $ | 72,990 | $ | 259,987 | $ | 296,406 |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ thousands) | |||||||||||||||||||
Adjusted EBITDA | $ | 86,995 | $ | 83,931 | $ | 81,669 | $ | 302,184 | $ | 257,924 | |||||||||
Subtract: | |||||||||||||||||||
Capital expenditures - accrual basis | (41,877 | ) | (63,488 | ) | (53,326 | ) | (211,095 | ) | (147,831 | ) | |||||||||
Interest expense | (7,871 | ) | (8,597 | ) | (8,820 | ) | (34,234 | ) | (35,648 | ) | |||||||||
Cash dividends declared | (9,552 | ) | (9,720 | ) | (9,992 | ) | (39,053 | ) | (28,658 | ) | |||||||||
Levered Free Cash Flow | $ | 27,695 | $ | 2,126 | $ | 9,531 | $ | 17,802 | $ | 45,787 | |||||||||
Net cash (received) paid for scheduled derivative settlements | (15,466 | ) | (15,153 | ) | (8,679 | ) | (42,197 | ) | 38,482 | ||||||||||
Levered Free Cash Flow Unhedged | $ | 12,229 | $ | (13,027 | ) | $ | 852 | $ | (24,395 | ) | $ | 84,269 |
Berry Corporation (bry) | |||||||||||||||||||
Quarter Ended December 31, 2019 | Quarter Ended September 30, 2019 | Quarter Ended December 31, 2018 | Year Ended December 31, 2019 | Year Ended December 31, 2018 | |||||||||||||||
($ in thousands except per MBoe amounts) | |||||||||||||||||||
General and administrative expenses | $ | 15,710 | $ | 16,434 | $ | 16,130 | $ | 62,643 | $ | 54,026 | |||||||||
Subtract: | |||||||||||||||||||
Non-recurring restructuring and other costs | — | (219 | ) | (1,414 | ) | (3,061 | ) | (6,773 | ) | ||||||||||
Non-cash stock compensation expense | (2,289 | ) | (2,275 | ) | (3,183 | ) | (8,356 | ) | (6,585 | ) | |||||||||
Adjusted general and administrative expenses | $ | 13,421 | $ | 13,940 | $ | 11,533 | $ | 51,226 | $ | 40,668 | |||||||||
General and administrative expenses ($/Boe) | $ | 5.46 | $ | 6.04 | $ | 6.27 | $ | 5.91 | $ | 5.48 | |||||||||
Subtract: | |||||||||||||||||||
Non-recurring restructuring and other costs ($/Boe) | — | (0.08 | ) | (0.55 | ) | (0.29 | ) | (0.69 | ) | ||||||||||
Non-cash stock compensation expense ($/Boe) | (0.80 | ) | (0.84 | ) | (1.24 | ) | (0.79 | ) | (0.67 | ) | |||||||||
Adjusted general and administrative expenses ($/Boe) | $ | 4.66 | $ | 5.13 | $ | 4.49 | $ | 4.84 | $ | 4.13 | |||||||||
Total MBoe | 2,877 | 2,719 | 2,571 | 10,594 | 9,855 |
Proved Reserves as of December 31, 2019(1) | |||||||||||||||
California (San Joaquin and Ventura basins) | Utah (Uinta basin) | Colorado (Piceance basin) | Total | ||||||||||||
Proved developed reserves: | |||||||||||||||
Oil (MMBbl) | 68 | 6 | — | 74 | |||||||||||
Natural Gas (Bcf) | — | 30 | 9 | 39 | |||||||||||
NGLs (MMBbl) | — | 1 | — | 1 | |||||||||||
Total (MMBoe)(2)(3) | 68 | 12 | 1 | 82 | |||||||||||
Proved undeveloped reserves: | |||||||||||||||
Oil (MMBbl) | 54 | 2 | — | 56 | |||||||||||
Natural Gas (Bcf) | — | 6 | — | 6 | |||||||||||
NGLs (MMBbl) | — | — | — | — | |||||||||||
Total (MMBoe)(3) | 54 | 3 | — | 57 | |||||||||||
Total proved reserves: | |||||||||||||||
Oil (MMBbl) | 122 | 8 | — | 130 | |||||||||||
Natural Gas (Bcf) | — | 36 | 9 | 45 | |||||||||||
NGLs (MMBbl) | — | 1 | — | 1 | |||||||||||
Total (MMBoe)(3) | 122 | 15 | 1 | 138 | |||||||||||
PV-10 (in billions)(4) | $ | 1.7 | $ | 0.1 | $ | — | $ | 1.8 |
(1) | Our estimated net reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $63.15 per Bbl Brent for oil and NGLs and $2.62 per MMBtu Henry Hub for natural gas at December 31, 2019. The volume-weighted average prices over the lives of the properties were $58.88 per Bbl of oil and condensate, $16.93 per Bbl of NGLs and $2.84 per Mcf. The prices were held constant for the lives of the properties and we took into account pricing differentials reflective of the market environment. Prices were calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules including adjustments by lease for quality, fuel deductions, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. |
(2) | Approximately 18% of proved developed oil reserves, 0% of proved developed NGL reserves, 0% of proved developed natural gas reserves and 16% of total proved developed reserves are non-producing. |
(3) | Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $64.16 per Bbl and $2.56 per Mcf, respectively, resulting in an oil-to-gas ratio of over 4 to 1 on an energy equivalent basis. |
(4) | For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flows, please see “Non-GAAP Financial Measures and Reconciliations—PV-10.” PV-10 does not give effect to derivatives transactions. |
At December 31, 2019 | |||
(in millions) | |||
California PV-10 | $ | 1.7 | |
Utah PV-10 | 0.1 | ||
Colorado PV-10 | — | ||
Total Company PV-10 | 1.8 | ||
Less: present value of future income taxes discounted at 10% | (0.3 | ) | |
Standardized measure of discounted future net cash flows | $ | 1.5 |
Total Company | California | |||||
(in MMBoe, except ratio and cost amounts) | ||||||
Extensions and discoveries (B) | 13.3 | 13.3 | ||||
Revisions of previous estimates(b) | (7.3 | ) | 11.2 | |||
Purchases of minerals | — | — | ||||
Organic changes (C) | 6.0 | 24.5 | ||||
Sales of minerals | — | — | ||||
Total reserves changes | 6.0 | 24.5 | ||||
Production | 10.6 | 8.2 | ||||
Reserve replacement ratio | 57 | % | 299 | % | ||
Costs incurred (development costs)(A) ($ millions) | $ | 280.0 | ||||
Finding & Development costs per Boe | ||||||
All-In (A)/(C) | $ | 46.67 | ||||
Program (A)/(B) | $ | 21.05 | ||||
Adjustments to All-In Finding & Development costs per BOE | ||||||
Costs incurred (development costs)(A) ($ millions) | $ | 280.0 | ||||
Asset Retirement Obligations ($ millions) | (68.0 | ) | ||||
Adjusted Costs Incurred ($ millions) (D) | $ | 212.0 | ||||
Total reserves changes | 6.0 | |||||
Impairments (MMBoe) | 13.5 | |||||
Adjusted organic changes (MMBoe) (E) | 19.5 | |||||
Adjusted All-In Finding & Developing costs per BOE (D)/(E) | $ | 10.87 |
(a) | All costs incurred in 2019 were development costs. |
(b) | Total Company revisions includes the removal of 16 MMBoe of proved undeveloped reserves (negative revision) in our Colorado Piceance natural gas properties, and the associated impairment. |
Total Company | ||
Proved Undeveloped (PUD) drilling locations at Dec. 31, 2018 | 1,071 | |
PUD locations drilled and revisions of previous inventory | (368 | ) |
PUD drilling location additions | 586 | |
PUD drilling locations at Dec. 31, 2019 | 1,289 | |
PUD replacement ratio | 159 | % |