Berry Corporation Reports Third Quarter 2023 Results
DALLAS, Nov. 01, 2023 (GLOBE NEWSWIRE) -- Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) announced third quarter 2023 results, including net loss of $45 million or $0.60 per diluted share, Adjusted Net Income(1) of $12 million or $0.15 per diluted share, cash flow from operating activities of $55 million and Adjusted EBITDA(1) of $70 million.
Quarterly Highlights
- Produced 25,300 boe/d, higher than first half 2023, ~30% lower than planned annual capital expenditures
- Generated Adjusted EBITDA (1) of $70 million and Adjusted Free Cash Flow (1) of $35 million, both higher than second quarter 2023
- Declared total fixed and variable dividends of $0.21 per share, a 50% increase over second quarter 2023
- Reduced G&A and Adjusted G&A(1) by 7% and 12%, respectively, compared to second quarter 2023
- Closed on accretive, oil producing acquisition (Macpherson) at end of quarter, integrating assets and people
_______
| (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. |
“In the third quarter, we generated meaningful free cash flow and returned it to our shareholders through dividends and closing an acquisition that we expect will enhance our financial results going forward,” said Fernando Araujo, Berry’s CEO. “We have successfully integrated the Macpherson business and have identified and already started implementing cost reduction initiatives which we expect will enhance our free cash flows even more than originally indicated. Moreover, we are aggressively pursuing scale through accretive M&A, especially outside of California, in all cases to enhance our ability to generate sustainable free cash flow.”
Third Quarter 2023 Results
Net loss was $45 million in the third quarter 2023 compared to net income of $26 million in the second quarter 2023, each including mark-to-market changes in derivative values. Adjusted Net Income was flat at $12 million in both quarters.
The Company's average daily production in the third quarter 2023 was 25,300 boe/d compared to 25,900 boe/d in the second quarter 2023 and 25,100 boe/d in the first half of 2023. Company-wide oil production in the third quarter 2023 was 23,200 bbl/d, accounting for 92% of total Company production, with California production contributing 20,500 boe/d or 81% of total production. Production decreased 2% quarter-over-quarter principally due to lower drilling and workover activities and accumulated inventory from first quarter production sold in the second quarter due to weather issues.
Company-wide realized oil price, including hedging effects, was $73.13 per bbl for the third quarter 2023 compared to $69.87 per bbl in the second quarter 2023. Excluding hedging effects, California's average realized oil prices were $79.98 per bbl in the third quarter 2023 and $72.10 per bbl in the second quarter 2023, each 93% of Brent.
Lease operating expenses, which includes fuel gas costs for California steam operations, increased in the third quarter 2023 from the second quarter 2023 mostly as a result of higher natural gas (fuel) costs for the California steam generation facilities due to an increase in fuel prices. Lease operating expenses and fuel costs were lower in the third quarter compared to the first half of 2023.
Lease operating expenses excluding fuel increased $1 million due to higher power costs from the higher seasonal summer rates in the third quarter 2023.
Taxes, other than income taxes, increased 31%, in the third quarter 2023 compared to the second quarter 2023 due to higher non-cash mark-to-market prices for greenhouse gas (“GHG”) allowances in the third quarter compared to the second quarter.
General and administrative expenses (“G&A”) decreased 7% in the third quarter 2023 compared to the second quarter 2023. Adjusted General and Administrative Expenses(1), which excludes non-cash stock compensation costs and non-recurring costs, decreased 12% in the third quarter 2023 compared to the second quarter 2023, largely as a result of lower shareholder litigation expenses.
The income for the well servicing and abandonment business, C&J Well Services, was $3 million in the third quarter 2023, slightly lower than the second quarter 2023 as a result of a change in mix and volume of services.
For the third quarter 2023, capital expenditures were approximately $12 million, excluding acquisitions, asset retirement obligation spending and well servicing and abandonment capital of $2 million. This represented a 43% decrease in capital expenditures compared to the second quarter 2023, mainly due to a decrease in workover and drilling costs. This decreased development activity was generally due to capital expenditure reductions made in connection with the Macpherson Acquisition in September 2023. The Company expects to reallocate approximately $30 to $35 million of its initial 2023 capital expenditure budget to fund a portion of the acquisition purchase price, of which approximately $53 million was paid at closing. Additionally, the Company spent approximately $4 million for plugging and abandonment activities in the third quarter 2023.
At September 30, 2023, the Company had liquidity of $163 million, consisting of $17 million cash and $146 million available for borrowings under its revolving credit facilities.
“We delivered another quarter of strong financial and operational results and declared $0.21 per share in variable and fixed dividends combined for the quarter,” stated Mike Helm, Berry’s CFO. “We generated Adjusted EBITDA totaling $70 million and Adjusted Free Cash Flow of $35 million, each a slight increase quarter-over-quarter. With the enhanced cash flows from the Macpherson assets, we expect to concentrate on improving our leverage, including through debt reduction. It is important to recognize that our Shareholder Return Model is dynamic, and we are continually looking at ways to optimize it with the right balance of debt reduction, competitive dividends, share repurchases, and the ability to capitalize on accretive acquisitions.”
Quarterly Dividends
The Company’s Board of Directors declared dividends totaling $0.21 per share on the Company’s outstanding common stock. The variable dividend of $0.09 per share was based on the cumulative Adjusted Free Cash Flow results for the three months ended September 30, 2023 in accordance with the Company's Shareholder Return Model. The fixed dividend of $0.12 per share was also declared, and both dividends are payable on November 29, 2023 to shareholders of record at the close of business on November 15, 2023.
Earnings Conference Call
The Company will host a conference call to discuss these results:
| Call Date: | Wednesday, November 1, 2023 |
| Call Time: | 11:00 a.m. Eastern Time / 10:00 a.m. Central Time / 8:00 a.m. Pacific Time |
| Join the live listen-only audio webcast at https://edge.media-server.com/mmc/p/e7iafteg or at https://bry.com/category/events | |
If you would like to ask a question on the live call, please preregister at any time using the following link:
https://register.vevent.com/register/BI4e95eac7749d425ea5e733a40961037f
Once registered, you will receive the dial-in numbers and a unique PIN number. You may then dial-in or have a call back. When you dial in, you will input your PIN and be placed into the call. If you register and forget your PIN or lose your registration confirmation email, you may simply re-register and receive a new PIN.
A web based audio replay will be available shortly after the broadcast and will be archived at
https://ir.bry.com/reports-resources or visit https://edge.media-server.com/mmc/p/e7iafteg or
https://bry.com/category/events
About Berry Corporation (bry)
Berry is a publicly traded (NASDAQ: BRY) western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived oil and gas reserves. We operate in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment. Our E&P assets are located in California and the Rockies, characterized by high oil content and predominantly located in rural areas with low population. Our California assets are in the San Joaquin basin (100% oil), while our Rockies assets are in the Uinta basin of Utah (60% oil and 40% gas). We operate our well servicing and abandonment segment in California. More information can be found at the Company’s website at bry.com.
Forward-Looking Statements
The information in this press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address plans, activities, events, objectives, goals, strategies, or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding our financial position; liquidity; cash flows (including, but not limited to, Adjusted Free Cash Flow); financial and operating results; capital program and development and production plans; operations and business strategy; potential acquisition and other strategic opportunities; reserves; hedging activities; capital expenditures; return of capital; our shareholder return model and the payment of future dividends; future repurchases of stock or debt; capital investments; recovery factors; projected accretion to financial and production results; projected synergies related to the Macpherson Acquisition; anticipated increases to free cash flow and shareholder returns; our capital expenditures and leverage profile; and other guidance are forward-looking statements. The forward-looking statements in this press release are based upon various assumptions, many of which are based, in turn, upon further assumptions. Although we believe that these assumptions were reasonable when made, these assumptions are inherently subject to significant uncertainties and contingencies which are difficult or impossible to predict and are beyond our control. Therefore, such forward-looking statements involve significant risks and uncertainties that could materially affect our expected financial position, financial and operating results, liquidity, cash flows (including, but not limited to, Adjusted Free Cash Flow) and business prospects.
Berry cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to acquisition transactions and the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond Berry’s control. These risks include, but are not limited to, commodity price volatility; legislative and regulatory actions that may prevent, delay or otherwise restrict our ability to drill and develop our assets, including with respect to existing and/or new requirements in the regulatory approval and permitting process; legislative and regulatory initiatives in California or our other areas of operation addressing climate change or other environmental concerns; investment in and development of competing or alternative energy sources; drilling, production and other operating risks; effects of competition; uncertainties inherent in estimating natural gas and oil reserves and in projecting future rates of production; our ability to replace our reserves through exploration and development activities or strategic transactions; cash flow and access to capital; the timing and funding of development expenditures; environmental, health and safety risks; effects of hedging arrangements; potential shut-ins of production due to lack of downstream demand or storage capacity; disruptions to, capacity constraints in, or other limitations on the third-party transportation and market takeaway infrastructure (including pipeline systems) that deliver our oil and natural gas and other processing and transportation considerations; the ability to effectively deploy our ESG strategy and risks associated with initiating new projects or business in connection therewith; our ability to successfully integrate the Macpherson assets into our operations; we fail to identify risks or liabilities related to Macpherson, its operations or assets; our inability to achieve anticipated synergies; our ability to successfully execute other strategic bolt-on acquisitions; overall domestic and global political and economic conditions; inflation levels, including increased interest rates and volatility in financial markets and banking; changes in tax laws and the other risks described under the heading “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 and subsequent filings with the SEC.
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.
Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no responsibility to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise except as required by applicable law. Investors are urged to consider carefully the disclosure in our filings with the Securities and Exchange Commission, available from us at via our website or via the Investor Relations contact below, or from the SEC’s website at www.sec.gov.
Tables Following
The financial information and certain other information presented have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables. In addition, certain percentages presented here reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding.
| SUMMARY OF RESULTS | |||||||||||
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| (unaudited) ($ and shares in thousands, except per share amounts) | |||||||||||
| Consolidated Statement of Operations Data: | |||||||||||
| Revenues and other: | |||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 172,611 | $ | 157,703 | $ | 203,585 | |||||
| Service revenue | 45,511 | 47,674 | 48,594 | ||||||||
| Electricity sales | 3,849 | 3,078 | 9,711 | ||||||||
| (Losses) gains on oil and gas sales derivatives | (103,282 | ) | 20,871 | 114,279 | |||||||
| Other revenues | 113 | 36 | 277 | ||||||||
| Total revenues and other | 118,802 | 229,362 | 376,446 | ||||||||
| Expenses and other: | |||||||||||
| Lease operating expenses | 59,842 | 54,707 | 79,141 | ||||||||
| Cost of services | 35,806 | 37,083 | 37,628 | ||||||||
| Electricity generation expenses | 1,479 | 1,273 | 6,055 | ||||||||
| Transportation expenses | 1,089 | 1,096 | 1,277 | ||||||||
| Acquisition costs | 2,082 | 972 | — | ||||||||
| General and administrative expenses | 20,987 | 22,488 | 23,388 | ||||||||
| Depreciation, depletion and amortization | 39,729 | 39,755 | 39,506 | ||||||||
| Taxes, other than income taxes | 17,980 | 13,707 | 7,335 | ||||||||
| (Gains) losses on natural gas purchase derivatives | (8,425 | ) | 14,024 | (28,942 | ) | ||||||
| Other operating (income) expenses | (505 | ) | (1,033 | ) | 623 | ||||||
| Total expenses and other | 170,064 | 184,072 | 166,011 | ||||||||
| Other (expenses) income: | |||||||||||
| Interest expense | (9,101 | ) | (8,794 | ) | (7,867 | ) | |||||
| Other, net | (42 | ) | (110 | ) | (24 | ) | |||||
| Total other expenses | (9,143 | ) | (8,904 | ) | (7,891 | ) | |||||
| (Loss) income before income taxes | (60,405 | ) | 36,386 | 202,544 | |||||||
| Income tax (benefit) expense | (15,343 | ) | 10,616 | 10,884 | |||||||
| Net (loss) income | $ | (45,062 | ) | $ | 25,770 | $ | 191,660 | ||||
| Net (loss) income per share: | |||||||||||
| Basic | $ | (0.60 | ) | $ | 0.34 | $ | 2.46 | ||||
| Diluted | $ | (0.60 | ) | $ | 0.33 | $ | 2.34 | ||||
| Weighted-average shares of common stock outstanding - basic | 75,662 | 76,721 | 78,044 | ||||||||
| Weighted-average shares of common stock outstanding - diluted | 75,662 | 79,285 | 82,045 | ||||||||
| Adjusted Net Income(1) | $ | 11,831 | $ | 11,666 | $ | 76,977 | |||||
| Weighted-average shares of common stock outstanding - diluted | 77,606 | 79,285 | 82,045 | ||||||||
| Diluted earnings per share on Adjusted Net Income(1) | $ | 0.15 | $ | 0.15 | $ | 0.94 | |||||
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| (unaudited) ($ and shares in thousands, except per share amounts) | |||||||||||
| Adjusted EBITDA(1) | $ | 69,829 | $ | 69,055 | $ | 96,981 | |||||
| Adjusted Free Cash Flow(1) | $ | 35,407 | $ | 33,774 | $ | 52,724 | |||||
| Adjusted General and Administrative Expenses(1) | $ | 16,763 | $ | 19,109 | $ | 19,107 | |||||
| Effective Tax Rate | 25 | % | 29 | % | 5 | % | |||||
| Cash Flow Data: | |||||||||||
| Net cash provided by operating activities | $ | 55,320 | $ | 62,538 | $ | 95,762 | |||||
| Net cash used in investing activities | $ | (68,029 | ) | $ | (27,961 | ) | $ | (34,241 | ) | ||
| Net cash provided by (used in) financing activities | $ | 21,343 | $ | (40,128 | ) | $ | (72,543 | ) | |||
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| (1) | See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”. |
| September 30, 2023 | December 31, 2022 | ||||||
| (unaudited) ($ and shares in thousands) | |||||||
| Balance Sheet Data: | |||||||
| Total current assets | $ | 157,691 | $ | 218,055 | |||
| Total property, plant and equipment, net | $ | 1,390,543 | $ | 1,359,813 | |||
| Total current liabilities | $ | 220,062 | $ | 234,207 | |||
| Long-term debt | $ | 453,667 | $ | 395,735 | |||
| Total stockholders' equity | $ | 708,119 | $ | 800,485 | |||
| Outstanding common stock shares as of | 75,667 | 75,768 | |||||
The following table represents selected financial information for the periods presented regarding the Company's business segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis. As of September 15, 2023, E&P also includes Macpherson.
| Three Months Ended September 30, 2023 | |||||||||||||||
| E&P | Well Servicing and Abandonment | Corporate/Eliminations | Consolidated Company | ||||||||||||
| (unaudited) (in thousands) | |||||||||||||||
| Revenues(1) | $ | 176,573 | $ | 47,259 | $ | (1,748 | ) | $ | 222,084 | ||||||
| Net (loss) income before income taxes | $ | (35,485 | ) | $ | 3,295 | $ | (28,215 | ) | $ | (60,405 | ) | ||||
| Adjusted EBITDA(2) | $ | 79,491 | $ | 6,854 | $ | (16,516 | ) | $ | 69,829 | ||||||
| Capital expenditures | $ | 10,833 | $ | 2,104 | $ | 659 | $ | 13,596 | |||||||
| Total assets | $ | 1,604,253 | $ | 71,891 | $ | (62,219 | ) | $ | 1,613,925 | ||||||
| Three Months Ended June 30, 2023 | |||||||||||||||
| E&P | Well Servicing and Abandonment | Corporate/Eliminations | Consolidated Company | ||||||||||||
| (unaudited) (in thousands) | |||||||||||||||
| Revenues(1) | $ | 160,817 | $ | 49,299 | $ | (1,625 | ) | $ | 208,491 | ||||||
| Net income (loss) before income taxes | $ | 62,012 | $ | 4,836 | $ | (30,462 | ) | $ | 36,386 | ||||||
| Adjusted EBITDA(2) | $ | 78,274 | $ | 7,689 | $ | (16,908 | ) | $ | 69,055 | ||||||
| Capital expenditures | $ | 19,625 | $ | 1,334 | $ | 936 | $ | 21,895 | |||||||
| Total assets | $ | 1,457,694 | $ | 72,653 | $ | (8,644 | ) | $ | 1,521,703 | ||||||
| Three Months Ended September 30, 2022 | |||||||||||||||
| E&P | Well Servicing and Abandonment | Corporate/Eliminations | Consolidated Company | ||||||||||||
| (unaudited) (in thousands) | |||||||||||||||
| Revenues(1) | $ | 213,573 | $ | 49,427 | $ | (833 | ) | $ | 262,167 | ||||||
| Net income (loss) before income taxes | $ | 224,094 | $ | 5,168 | $ | (26,718 | ) | $ | 202,544 | ||||||
| Adjusted EBITDA(2) | $ | 102,763 | $ | 7,726 | $ | (13,508 | ) | $ | 96,981 | ||||||
| Capital expenditures | $ | 38,312 | $ | 1,726 | $ | 779 | $ | 40,817 | |||||||
| Total assets | $ | 1,502,135 | $ | 79,696 | $ | (57,479 | ) | $ | 1,524,352 | ||||||
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| (1) | These revenues do not include hedge settlements. |
| (2) | See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”. |
| COMMODITY PRICING | |||||||||||
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| Weighted Average Realized Prices | |||||||||||
| Oil without hedge ($/bbl) | $ | 78.89 | $ | 70.68 | $ | 89.54 | |||||
| Effects of scheduled derivative settlements ($/bbl) | $ | (5.76 | ) | $ | (0.81 | ) | $ | (13.13 | ) | ||
| Oil with hedge ($/bbl) | $ | 73.13 | $ | 69.87 | $ | 76.41 | |||||
| Natural gas ($/mcf) | $ | 3.57 | $ | 2.87 | $ | 7.95 | |||||
| NGLs ($/bbl) | $ | 22.54 | $ | 22.16 | $ | 40.72 | |||||
| Index Prices | |||||||||||
| Brent oil ($/bbl) | $ | 85.92 | $ | 77.73 | $ | 97.70 | |||||
| WTI oil ($/bbl) | $ | 81.99 | $ | 73.73 | $ | 91.96 | |||||
| Natural gas ($/mmbtu) – SoCal Gas city-gate(1) | $ | 7.10 | $ | 5.66 | $ | 9.55 | |||||
| Natural gas ($/mmbtu) - Northwest, Rocky Mountains(2) | $ | 3.40 | $ | 2.85 | $ | 7.79 | |||||
| Henry Hub natural gas ($/mmbtu)(2) | $ | 2.59 | $ | 2.16 | $ | 8.03 | |||||
__________
| (1) | The natural gas we purchase to generate steam and electricity is primarily based on Rockies price indexes, including transportation charges, as we currently purchase a substantial majority of gas needs from the Rockies, with the balance purchased in California. SoCal Gas city-gate Index is the relevant index used only for the portion of gas purchases in California. Now that the Company is purchasing a majority of its fuel gas in the Rockies, most of the purchases made in California utilize the SoCal Gas city-gate index, whereas prior to this shift the predominant index for California purchases was Kern, Delivered. |
| (2) | Northwest, Rocky Mountains and Henry Hub are the relevant indices used for gas purchases and sales, respectively, in the Rockies. |
Natural gas prices and differentials are strongly affected by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. The Company's key exposure to gas prices is in costs. The Company purchases substantially more natural gas for California steamfloods and cogeneration facilities than what is produced and sold in the Rockies. In May 2022, the Company began purchasing most of its gas in the Rockies and transporting it to California operations using the Kern River pipeline capacity. The Company buys approximately 48,000 mmbtu/d in the Rockies, and the remainder comes from California markets. The volume purchased in California fluctuates and averaged 6,000 mmbtu/d in Q3 2023, 6,000 mmbtu/d in Q2 2023 and 10,000 mmbtu/d in Q3 2022. The natural gas purchased in the Rockies is shipped to operations in California to help limit exposure to California fuel gas purchase price fluctuations. The Company strives to further minimize the variability of fuel gas costs for steam operations by hedging a significant portion of gas purchases. Additionally, the negative impact of higher gas prices on California operating expenses is partially offset by higher gas sales for the gas produced and sold in the Rockies. The Kern capacity allows us to purchase and sell natural gas at the same pricing indices.
| CURRENT HEDGING SUMMARY | |||||||||||||||
| As of October 31, 2023, we had the following crude oil production and gas purchases hedges. | |||||||||||||||
| Q4 2023 | FY 2024 | FY 2025 | FY 2026 | ||||||||||||
| Brent - Crude Oil production | |||||||||||||||
| Swaps | |||||||||||||||
| Hedged volume (bbls) | 1,407,600 | 5,426,817 | 1,847,125 | 645,768 | |||||||||||
| Weighted-average price ($/bbl) | $ | 77.61 | $ | 77.82 | $ | 75.21 | $ | 69.43 | |||||||
| Sold Calls(1) | |||||||||||||||
| Hedged volume (bbls) | 368,000 | 732,000 | 2,486,127 | 1,251,500 | |||||||||||
| Weighted-average price ($/bbl) | $ | 106.00 | $ | 105.00 | $ | 91.11 | $ | 85.53 | |||||||
| Purchased Puts (net)(2) | |||||||||||||||
| Hedged volume (bbls) | 552,000 | 1,281,000 | 365,000 | — | |||||||||||
| Weighted-average price ($/bbl) | $ | 50.00 | $ | 50.00 | $ | 50.00 | $ | — | |||||||
| Purchased Puts (net)(2) | |||||||||||||||
| Hedged volume (bbls) | — | — | 2,121,127 | 1,251,500 | |||||||||||
| Weighted-average price ($/bbl) | $ | — | $ | — | $ | 60.00 | $ | 60.00 | |||||||
| Sold Puts (net)(2) | |||||||||||||||
| Hedged volume (bbls) | 154,116 | 183,000 | — | — | |||||||||||
| Weighted-average price ($/bbl) | $ | 40.00 | $ | 40.00 | $ | — | $ | — | |||||||
| Henry Hub - Natural Gas purchases | |||||||||||||||
| NWPL - Natural Gas purchases | |||||||||||||||
| Swaps | |||||||||||||||
| Hedged volume (mmbtu) | 3,680,000 | 10,980,000 | 6,080,000 | — | |||||||||||
| Weighted-average price ($/mmbtu) | $ | 5.34 | $ | 4.21 | $ | 4.27 | $ | — | |||||||
| Gas Basis Differentials | |||||||||||||||
| NWPL/HH - Natural Gas Purchases | |||||||||||||||
| Hedged volume (mmbtu) | 610,000 | — | — | — | |||||||||||
| Weighted-average price ($/mmbtu) | $ | 1.12 | $ | — | $ | — | $ | — | |||||||
__________
| (1) | Purchased calls and sold calls with the same strike price have been presented on a net basis. |
| (2) | Purchased puts and sold puts with the same strike price have been presented on a net basis. |
| E&P FIELD OPERATIONS | |||||||||||
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| (unaudited) ($ in per boe amounts) | |||||||||||
| Expenses from field operations | |||||||||||
| Lease operating expenses | $ | 25.73 | $ | 23.17 | $ | 33.40 | |||||
| Electricity generation expenses | 0.64 | 0.54 | 2.56 | ||||||||
| Transportation expenses | 0.47 | 0.46 | 0.54 | ||||||||
| Total | $ | 26.84 | $ | 24.17 | $ | 36.50 | |||||
| Cash settlements paid (received) for gas purchase hedges | $ | 3.06 | $ | 4.56 | $ | (5.82 | ) | ||||
| E&P non-production revenues | |||||||||||
| Electricity sales | $ | 1.65 | $ | 1.30 | $ | 4.10 | |||||
| Transportation sales | 0.05 | 0.02 | 0.12 | ||||||||
| Total | $ | 1.70 | $ | 1.32 | $ | 4.22 | |||||
Overall, management assesses the efficiency of the Company's E&P field operations by considering core E&P operating expenses together with cogeneration, marketing and transportation activities. In particular, a core component of E&P operations in California is steam, which is used to lift heavy oil to the surface. The Company operates several cogeneration facilities to produce some of the steam needed in operations. In comparing the cost effectiveness of cogeneration plants against other sources of steam in operations, management considers the cost of operating the cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the steam and electricity used in E&P field operations and the revenues received from sales of excess electricity to the grid. The Company strives to minimize the variability of its fuel gas costs for California steam operations with natural gas purchase hedges. Consequently, the efficiency of E&P field operations are impacted by the cash settlements received or paid from these derivatives. The Company also has contracts for the transportation of fuel gas from the Rockies, which has historically been cheaper than the California markets. With respect to transportation and marketing, management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P operations.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools and supplies from two of the Company's cogeneration facilities allocated to electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to costs to transport the oil and gas that is produced within the Company's properties or moved to the market. Marketing expenses mainly relate to natural gas purchased from third parties that moves through gathering and processing systems and then is sold to third parties. Electricity revenue is from the sale of excess electricity from two of the Company's cogeneration facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are sized to satisfy the steam needs in their respective fields, but the corresponding electricity produced is more than the electricity that is currently required for the operations in those fields. Transportation sales relate to water and other liquids that transport on the Company's systems on behalf of third parties and marketing revenues represent sales of natural gas purchased from and sold to third parties.
| PRODUCTION STATISTICS | |||||||||||
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| Net Oil, Natural Gas and NGLs Production Per Day(1): | |||||||||||
| Oil (mbbl/d) | |||||||||||
| California(2) | 20.5 | 20.8 | 20.8 | ||||||||
| Utah | 2.7 | 3.2 | 2.9 | ||||||||
| Total oil | 23.2 | 24.0 | 23.7 | ||||||||
| Natural gas (mmcf/d) | |||||||||||
| California | — | — | — | ||||||||
| Utah | 9.5 | 9.2 | 10.4 | ||||||||
| Total natural gas | 9.5 | 9.2 | 10.4 | ||||||||
| NGLs (mbbl/d) | |||||||||||
| California | — | — | — | ||||||||
| Utah | 0.5 | 0.4 | 0.4 | ||||||||
| Total NGLs | 0.5 | 0.4 | 0.4 | ||||||||
| Total Production (mboe/d)(3) | 25.3 | 25.9 | 25.8 | ||||||||
__________
| (1) | Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas. |
| (2) | Includes production for the Macpherson Acquisition, which closed September 15, 2023. |
| (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 three months ended September 30, 2023, the average prices of Brent oil and Henry Hub natural gas were $85.92 per bbl and $2.59 per mmbtu respectively. |
| CAPITAL EXPENDITURES | |||||||||||
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| (unaudited) (in thousands) | |||||||||||
| Capital expenditures(1)(2) | $ | 13,596 | $ | 21,895 | $ | 40,817 | |||||
__________
| (1) | Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending. |
| (2) | Capital expenditures in the three months ended September 30, 2023, June 30, 2023 and September 30, 2022 included $2 million, $1 million, and $2 million, respectively, for the well servicing and abandonment business. |
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
Adjusted Net Income (Loss) is not a measure of net income (loss), Adjusted Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either net income (loss) or cash flow, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
We define Adjusted EBITDA 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 unusual and infrequent items. Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. We also use Adjusted EBITDA in planning our capital allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility.
We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our statutory tax rate. Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We believe Adjusted Net Income (Loss) is useful to investors because it reflects how management evaluates the Company’s ongoing financial and operating performance from period-to-period after removing certain transactions and activities that affect comparability of the metrics and are not reflective of the Company’s core operations. We believe this also makes it easier for investors to compare our period-to-period results with our peers.
We define Adjusted Free Cash Flow, which is a non-GAAP financial measure, as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital represents the capital expenditures needed to maintain substantially the same volume of annual oil and gas production and is defined as capital expenditures, excluding, when applicable, E&P capital expenditures that are related to strategic business expansion, such as acquisitions of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes and capital expenditures in our well servicing and abandonment and corporate segments that are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. Management believes Adjusted Free Cash Flow may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base after maintaining the existing production volumes of that asset base to return capital to stockholders, fund further business expansion through acquisitions or investments in our existing asset base to increase production volumes and pay other non-discretionary expenses. Management also uses Adjusted Free Cash Flow as the primary metric to plan for future growth and expects to use approximately (a) 80% of Adjusted Free Cash Flow for debt repurchases, stock repurchases, strategic growth, and acquisitions of producing bolt-on assets and (b) 20% in the form of variable dividends.
Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchases, strategic acquisitions or other growth opportunities, or other discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from this measure.
We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and infrequent costs. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period. We believe Adjusted General and Administrative Expenses is useful to investors because it reflects how management evaluates the Company’s ongoing general and administrative expenses from period-to-period after removing non-cash stock compensation, as well as unusual or infrequent costs that affect comparability of the metrics and are not reflective of the Company’s administrative costs. We believe this also makes it easier for investors to compare our period-to-period results with our peers.
While Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative to, or more meaningful than income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
ADJUSTED EBITDA
The following tables present a reconciliation of the GAAP financial measures of net income (loss) and net cash provided (used) by operating activities to the non-GAAP financial measure of Adjusted EBITDA, as applicable, for each of the periods indicated.
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| (unaudited) (in thousands) | |||||||||||
| Adjusted EBITDA reconciliation: | |||||||||||
| Net (loss) income | $ | (45,062 | ) | $ | 25,770 | $ | 191,660 | ||||
| Add (Subtract): | |||||||||||
| Interest expense | 9,101 | 8,794 | 7,867 | ||||||||
| Income tax (benefit) expense | (15,343 | ) | 10,616 | 10,884 | |||||||
| Depreciation, depletion, and amortization | 39,729 | 39,755 | 39,506 | ||||||||
| Losses (gains) on derivatives | 94,857 | (6,847 | ) | (143,221 | ) | ||||||
| Net cash paid for scheduled derivative settlements | (19,432 | ) | (12,524 | ) | (14,739 | ) | |||||
| Other operating (income) expenses | (505 | ) | (1,033 | ) | 623 | ||||||
| Stock compensation expense | 3,018 | 3,552 | 4,401 | ||||||||
| Acquisition costs(1) | 2,082 | 972 | — | ||||||||
| Non-recurring costs(2) | 1,384 | — | — | ||||||||
| Adjusted EBITDA | $ | 69,829 | $ | 69,055 | $ | 96,981 | |||||
| Net cash provided by operating activities | $ | 55,320 | $ | 62,538 | $ | 95,762 | |||||
| Add (Subtract): | |||||||||||
| Cash interest payments | 15,065 | 1,004 | 14,493 | ||||||||
| Cash income tax payments | 2,087 | 670 | 321 | ||||||||
| Non-recurring costs(2) | 1,384 | — | — | ||||||||
| Changes in operating assets and liabilities - working capital(3) | (3,032 | ) | 6,065 | (14,151 | ) | ||||||
| Other operating (income) expenses - cash portion(4) | (995 | ) | (1,222 | ) | 556 | ||||||
| Adjusted EBITDA | $ | 69,829 | $ | 69,055 | $ | 96,981 | |||||
__________
| (1) | Consists of costs related to the Macpherson Acquisition. |
| (2) | Consists of costs related to the settlement of shareholder litigation. |
| (3) | Changes in other assets and liabilities consists of working capital and various immaterial items. |
| (4) | Represents the cash portion of other operating (income) expenses from the income statement, net of the non-cash portion in the cash flow statement. |
Adjusted EBITDA is the measure reported to the chief operating decision maker (CODM) for purposes of making decisions about allocating resources to and assessing performance of each segment. EBITDA represents 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 unusual and infrequent items.
| Three Months Ended September 30, 2023 | |||||||||||||||
| E&P | Well Servicing and Abandonment | Corporate/Eliminations | Consolidated Company | ||||||||||||
| (unaudited) (in thousands) | |||||||||||||||
| Adjusted EBITDA reconciliation: | |||||||||||||||
| Net (loss) income | $ | (35,485 | ) | $ | 3,295 | $ | (12,872 | ) | $ | (45,062 | ) | ||||
| Add (Subtract): | |||||||||||||||
| Interest (income) expense | — | (16 | ) | 9,117 | 9,101 | ||||||||||
| Income tax benefit | — | — | (15,343 | ) | (15,343 | ) | |||||||||
| Depreciation, depletion, and amortization | 35,620 | 3,405 | 704 | 39,729 | |||||||||||
| Losses on derivatives | 94,857 | — | — | 94,857 | |||||||||||
| Net cash paid for scheduled derivative settlements | (19,432 | ) | — | — | (19,432 | ) | |||||||||
| Other operating expenses (income) | 357 | (6 | ) | (856 | ) | (505 | ) | ||||||||
| Stock compensation expense | 108 | 176 | 2,734 | 3,018 | |||||||||||
| Acquisition costs(1) | 2,082 | — | — | 2,082 | |||||||||||
| Non-recurring costs(2) | 1,384 | — | — | 1,384 | |||||||||||
| Adjusted EBITDA | $ | 79,491 | $ | 6,854 | $ | (16,516 | ) | $ | 69,829 | ||||||
__________
| (1) | Consists of costs related to the Macpherson Acquisition. |
| (2) | Consists of costs related to the settlement of shareholder litigation. |
| Three Months Ended June 30, 2023 | |||||||||||||||
| E&P | Well Servicing and Abandonment | Corporate/Eliminations | Consolidated Company | ||||||||||||
| (unaudited) (in thousands) | |||||||||||||||
| Adjusted EBITDA reconciliation: | |||||||||||||||
| Net income (loss) | $ | 62,012 | $ | 4,836 | $ | (41,078 | ) | $ | 25,770 | ||||||
| Add (Subtract): | |||||||||||||||
| Interest (income) expense | — | (28 | ) | 8,822 | 8,794 | ||||||||||
| Income tax expense | — | — | 10,616 | 10,616 | |||||||||||
| Depreciation, depletion, and amortization | 35,649 | 3,307 | 799 | 39,755 | |||||||||||
| Gains on derivatives | (6,847 | ) | — | — | (6,847 | ) | |||||||||
| Net cash paid for scheduled derivative settlements | (12,524 | ) | — | — | (12,524 | ) | |||||||||
| Other operating (income) expenses | (1,093 | ) | (610 | ) | 670 | (1,033 | ) | ||||||||
| Stock compensation expense | 105 | 184 | 3,263 | 3,552 | |||||||||||
| Acquisition costs(1) | 972 | — | — | 972 | |||||||||||
| Adjusted EBITDA | $ | 78,274 | $ | 7,689 | $ | (16,908 | ) | $ | 69,055 | ||||||
__________
| (1) | Consists of costs related to the Macpherson Acquisition. |
| Three Months Ended September 30, 2022 | |||||||||||||||
| E&P | Well Servicing and Abandonment | Corporate/Eliminations | Consolidated Company | ||||||||||||
| (unaudited) (in thousands) | |||||||||||||||
| Adjusted EBITDA reconciliation: | |||||||||||||||
| Net income (loss) | $ | 224,094 | $ | 5,168 | $ | (37,602 | ) | $ | 191,660 | ||||||
| Add (Subtract): | |||||||||||||||
| Interest expense | — | 4 | 7,863 | 7,867 | |||||||||||
| Income tax expense | — | — | 10,884 | 10,884 | |||||||||||
| Depreciation, depletion, and amortization | 35,198 | 3,249 | 1,059 | 39,506 | |||||||||||
| Gains on derivatives | (143,221 | ) | — | — | (143,221 | ) | |||||||||
| Net cash paid for scheduled derivative settlements | (14,739 | ) | — | — | (14,739 | ) | |||||||||
| Other operating expenses (income) | 1,077 | (769 | ) | 315 | 623 | ||||||||||
| Stock compensation expense | 354 | 74 | 3,973 | 4,401 | |||||||||||
| Adjusted EBITDA | $ | 102,763 | $ | 7,726 | $ | (13,508 | ) | $ | 96,981 | ||||||
ADJUSTED FREE CASH FLOW
The following table presents a reconciliation of the GAAP financial measure of operating cash flow to the non-GAAP financial measure of Adjusted Free Cash Flow for each of the periods indicated. The Company uses Adjusted Free Cash Flow for its shareholder return model, which began in 2022.
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| (unaudited) (in thousands) | |||||||||||
| Adjusted Free Cash Flow reconciliation: | |||||||||||
| Net cash provided by operating activities(1) | $ | 55,320 | $ | 62,538 | $ | 95,762 | |||||
| Subtract: | |||||||||||
| Maintenance capital(2) | (10,833 | ) | (19,625 | ) | (38,312 | ) | |||||
| Fixed dividends(3) | (9,080 | ) | (9,139 | ) | (4,726 | ) | |||||
| Adjusted Free Cash Flow | $ | 35,407 | $ | 33,774 | $ | 52,724 | |||||
__________
| (1) | On a consolidated basis. |
| (2) | Maintenance capital is the capital required to keep annual production substantially flat, and is calculated as follows: |
| Three Months Ended | ||||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | ||||||||||
| (unaudited) (in thousands) | ||||||||||||
| Consolidated capital expenditures(a) | $ | (13,596 | ) | $ | (21,895 | ) | $ | (40,817 | ) | |||
| Excluded items(b) | 2,763 | 2,270 | 2,505 | |||||||||
| Maintenance capital | $ | (10,833 | ) | $ | (19,625 | ) | $ | (38,312 | ) | |||
__________
| (a) | Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending. | |
| (b) | Comprised of the capital expenditures in the Company's E&P segment that are related to strategic business expansion, such as acquisitions of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes and capital expenditures in the Company's well servicing and abandonment segment and corporate expenditures that are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of the Company's core business. For the three months ended September 30, 2023, June 30, 2023, and September 30, 2022, the Company excluded approximately $2.1 million, $1.3 million, and $1.7 million of capital expenditures related to well servicing and abandonment segment, respectively, which was substantially all used for sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of the Company's core business. For the three months ended September 30, 2023, June 30, 2023, and September 30, 2022, the Company excluded approximately $0.7 million, $0.9 million, and $0.8 million of corporate capital expenditures, respectively, which the Company determined was not related to the maintenance of baseline production. |
| (3) | Represents fixed dividends declared for the periods presented. |
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of the GAAP financial measures of net income (loss) and net income (loss) per share — diluted to the non-GAAP financial measures of Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share — diluted for each of the periods indicated.
| Three Months Ended | |||||||||||||||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||||||||||||||
| (in thousands) | per share - diluted | (in thousands) | per share - diluted | (in thousands) | per share - diluted | ||||||||||||||||||
| (unaudited) | |||||||||||||||||||||||
| Adjusted Net Income (Loss) reconciliation: | |||||||||||||||||||||||
| Net (loss) income | $ | (45,062 | ) | $ | (0.58 | ) | $ | 25,770 | $ | 0.33 | $ | 191,660 | $ | 2.34 | |||||||||
| Add (Subtract): | |||||||||||||||||||||||
| Losses (gains) on derivatives | 94,857 | 1.22 | (6,847 | ) | (0.09 | ) | (143,221 | ) | (1.75 | ) | |||||||||||||
| Net cash (paid) received for scheduled derivative settlements | (19,432 | ) | (0.25 | ) | (12,524 | ) | (0.16 | ) | (14,739 | ) | (0.18 | ) | |||||||||||
| Other operating (income) expenses | (505 | ) | (0.01 | ) | (1,033 | ) | (0.01 | ) | 623 | 0.01 | |||||||||||||
| Acquisition costs(1) | 2,082 | 0.03 | 972 | 0.01 | — | — | |||||||||||||||||
| Non-recurring costs(2) | 1,384 | 0.02 | — | — | — | — | |||||||||||||||||
| Total additions (subtractions), net | 78,386 | 1.01 | (19,432 | ) | (0.25 | ) | (157,337 | ) | (1.92 | ) | |||||||||||||
| Income tax (benefit) expense of adjustments(3) | (21,493 | ) | (0.28 | ) | 5,328 | 0.07 | 42,654 | 0.52 | |||||||||||||||
| Adjusted Net Income | $ | 11,831 | $ | 0.15 | $ | 11,666 | $ | 0.15 | $ | 76,977 | $ | 0.94 | |||||||||||
| Basic EPS on Adjusted Net Income | $ | 0.16 | $ | 0.15 | $ | 0.99 | |||||||||||||||||
| Diluted EPS on Adjusted Net Income | $ | 0.15 | $ | 0.15 | $ | 0.94 | |||||||||||||||||
| Weighted average shares of common stock outstanding - basic | 75,662 | 76,721 | 78,044 | ||||||||||||||||||||
| Weighted average shares of common stock outstanding - diluted | 77,606 | 79,285 | 82,045 | ||||||||||||||||||||
__________
| (1) | Consists of costs related to the Macpherson Acquisition. |
| (2) | Consists of costs related to the settlement of shareholder litigation. |
| (3) | The federal and state statutory rates were utilized in both 2023 and 2022. We updated the disclosure in 2022 to reflect the 2022 statutory rate, instead of the effective tax rate previously utilized. |
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES
The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measure of Adjusted General and Administrative Expenses for each of the periods indicated.
| Three Months Ended | |||||||||||
| September 30, 2023 | June 30, 2023 | September 30, 2022 | |||||||||
| (unaudited) ($ in thousands) | |||||||||||
| Adjusted General and Administrative Expense reconciliation: | |||||||||||
| General and administrative expenses | $ | 20,987 | $ | 22,488 | $ | 23,388 | |||||
| Subtract: | |||||||||||
| Non-cash stock compensation expense (G&A portion) | (2,840 | ) | (3,379 | ) | (4,281 | ) | |||||
| Non-recurring costs(1) | (1,384 | ) | — | — | |||||||
| Adjusted General and Administrative Expenses | $ | 16,763 | $ | 19,109 | $ | 19,107 | |||||
| Well servicing and abandonment segment | $ | 2,910 | $ | 2,958 | $ | 3,324 | |||||
| E&P segment, and corporate | $ | 13,853 | $ | 16,151 | $ | 15,783 | |||||
| E&P segment, and corporate ($/boe) | $ | 5.96 | $ | 6.84 | $ | 6.66 | |||||
| Total mboe | 2,326 | 2,361 | 2,369 | ||||||||
__________
| (1) | Consists of costs related to the settlement of shareholder litigation. |
Contact Contact: Berry Corporation (bry) Todd Crabtree - Director, Investor Relations (661) 616-3811 ir@bry.com