DocumentPRESS RELEASE
For Immediate Release
Berry Corporation (bry) Reports First Quarter 2023 Results
DALLAS, TX - May 3, 2023 (GLOBE NEWSWIRE) – Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) announced first quarter 2023 results, including a net loss of $6 million or $0.08 per diluted share, Adjusted Net Income(1) of $5 million or $0.07 per diluted share, and Adjusted EBITDA(1) of $59 million.
Quarterly Highlights
•Reported Adjusted EBITDA(1) of $59 million
•Declared first quarter fixed dividends of $0.12 per share, double the quarterly rate from prior year
•On track to generate 2023 shareholder returns of about $130 million, including a cash dividend yield in the high single digits
•Executed cost savings measures with expected full year decreases of approximately 10% for Adjusted G&A
•Recovered from early Q1 severe weather production impact with no change in full year guidance
_______
(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.
“Berry’s priority is to deliver significant and sustainable returns to our shareholders,” said Fernando Araujo, Berry CEO. “Our return model is underpinned by our low corporate production decline rates and the tremendous amount of oil in place in our assets, which give us visibility to cash flows. Our first quarter results were generally in line with expectations and our full year operational and financial guidance remains unchanged.
“We executed cost savings measures across the organization, including workforce reductions, with expected expense decreases of approximately 10% for Adjusted G&A, a majority of which is already reflected in our 2023 annual guidance. We are actively assessing our operating cost structure and will continue to identify and execute on other cost reduction opportunities throughout the year. We have also improved drilling efficiency in horizontal sidetrack operations, drilling some wells approximately 30% faster than those we drilled last year. We are also actively pursuing strategic producing bolt-ons to increase our scale and operational synergies while continuing to produce affordable and reliable energy, safely and efficiently,” continued Araujo.
First Quarter 2023 Results
Net loss was $6 million and net income was $72 million and Adjusted EBITDA was $59 million and $78 million in the first quarter 2023 and in the fourth quarter 2022, respectively. The decrease in Adjusted EBITDA was largely driven by lower oil prices and production, coupled with higher fuel costs, partially offset by higher natural gas sales.
The Company's average daily production decreased in the first quarter of 2023 to 24,300 boe/d compared to 25,800 boe/d in the fourth quarter 2022. The Company-wide oil production in the first quarter 2023 was 22,600 bbl/d, or 93% of total Company production, with California production contributing 19,900 boe/d or 82% of total production. Production in California was negatively impacted by severe weather in the first quarter, recovering to expected levels in March. Utah production was also hampered by above-average snowfall, limiting access to wells, which increased well downtimes and the ability to transport produced oil, and also prevented normal workover and well maintenance.
The Company-wide realized oil price, including hedging effects, was $71.04 per bbl for the first quarter 2023 compared to $73.39 per bbl in the fourth quarter 2022. Excluding hedging effects, California's average realized oil prices were $76.24 per bbl in the first quarter, 93% of Brent, and $81.66 per bbl in the fourth quarter, 92% of Brent.
California prices were unfavorably impacted by a temporary market disruption as a key third-party pipeline system was down for repairs, but this had no impact on volumes sold and the pipeline has now been restarted.
Lease operating expenses, which includes fuel gas costs for our California steam operations, increased in the first quarter 2023 from the fourth quarter 2022 mostly due to higher natural gas purchase prices, and to a much lesser extent higher weather-related services and lease maintenance costs. Fuel cost increases were largely offset by the positive results of gas purchase hedges.
Taxes, other than income taxes, decreased 21% in the first quarter compared to the fourth quarter 2022 due to lower greenhouse gas (“GHG”) mark-to-market prices and lower property taxes.
General and administrative expenses increased 18% in the first quarter of 2023 compared to the fourth quarter 2022, almost entirely due to non-recurring executive transition and workforce reduction costs. Adjusted General and Administrative Expenses(1), which excludes non-cash stock compensation costs and nonrecurring costs, remained essentially flat quarter over quarter.
The income for the well servicing and abandonment business, C&J Well Services, declined 68% to $2 million in the first quarter 2023 compared to the fourth quarter 2022, due to weather-related impacts to both revenues and costs.
For the first quarter 2023, capital expenditures were approximately $20 million, excluding acquisitions, asset retirement obligation spending and well servicing and abandonment capital of $1 million. This represented a 56% decrease compared to the fourth quarter, reflecting the constraints imposed by the current permitting environment impacting Kern County. The current capital program for 2023 focuses on new wells for which we already had permits in hand or is in areas covered by existing CEQA analysis, and otherwise focuses on workovers and other activities related to existing wellbores. Based on activity to date and expected for the remainder of 2023, the Company currently anticipates its full year capital expenditures will be in-line with its initial budget between $95 and $105 million for the E&P segment and corporate and approximately $8 million for the well servicing and abandonment segment. Additionally, the Company spent approximately $5 million for plugging and abandonment activities in the first quarter 2023.
At March 31, 2023, the Company had liquidity of $179 million consisting of $14 million cash and $165 million available for borrowings under its revolving credit facilities.
“Our first quarter financial results met our expectations and we are on track to generate returns to shareholders totaling about $130 million in 2023. This represents almost 20% of our current market capitalization, with an inclusive 2023 cash dividend yield expected to be in the high single digits from our fixed and variable dividends,” stated Berry CFO Mike Helm. “Our annual cumulative Adjusted Free Cash Flows, which are calculated after our fixed dividend payments, are allocated in accordance with our shareholder return model. This allocates 20% for variable dividends and 80% for opportunistic uses, including share and debt repurchases for which the Company has existing authorization, and also acquisitions of bolt-ons with existing production. Our Adjusted Free Cash Flows are historically the lowest in the first quarter each year and this was the case again this quarter due to working capital uses, which include annual royalty and bonus payments.”
Quarterly Dividends
The Company’s Board of Directors declared dividends totaling $0.12 per share on the Company’s outstanding common stock. This quarterly fixed dividend of $0.12 per share is payable on May 25, 2023 to shareholders of record at the close of business on May 15, 2023.
Earnings Conference Call
The Company will host a conference call to discuss these results:
Call Date: Wednesday, May 3, 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/9mzaqt5m
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/BIca411054b9e34550b2bef30908399a09
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/9mzaqt5m
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, conventional oil reserves located primarily in the San Joaquin basin of California, as well as the Uinta basin of Utah. We also have well servicing and abandonment capabilities 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; projected G&A savings from workforce reductions; 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; our ESG strategy and initiation of new projects or business in connection therewith; recovery factors; 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 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 execute 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.
Contact
Contact: Berry Corporation (bry)
Todd Crabtree - Director, Investor Relations
(661) 616-3811
ir@bry.com
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 |
| March 31, 2023 | | December 31, 2022 | | March 31, 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 | $ | 166,357 | | | $ | 188,442 | | | $ | 210,351 | |
| Service revenue | 44,623 | | | 46,792 | | | 39,836 | |
| Electricity sales | 5,445 | | | 8,284 | | | 5,419 | |
| Gains (losses) on oil and gas sales derivatives | 38,499 | | | (48,872) | | | (161,858) | |
| Marketing revenues | — | | | — | | | 289 | |
| Other revenues | 45 | | | 37 | | | 45 | |
| Total revenues and other | 254,969 | | | 194,683 | | | 94,082 | |
| | | | | |
| Expenses and other: | | | | | |
| Lease operating expenses | 134,835 | | | 87,601 | | | 63,124 | |
| Cost of services | 36,099 | | | 35,010 | | | 33,472 | |
| Electricity generation expenses | 2,500 | | | 5,199 | | | 4,463 | |
| Transportation expenses | 1,041 | | | 1,021 | | | 1,158 | |
| Marketing expenses | — | | | — | | | 299 | |
| General and administrative expenses | 31,669 | | | 26,926 | | | 22,942 | |
| Depreciation, depletion and amortization | 40,121 | | | 39,509 | | | 39,777 | |
| | | | | |
| Taxes, other than income taxes | 10,460 | | | 14,341 | | | 6,605 | |
| | | | | |
| Gains on natural gas purchase derivatives | (610) | | | (41,460) | | | (29,054) | |
| Other operating (income) expenses | (286) | | | (1,023) | | | 3,769 | |
| Total expenses and other | 255,829 | | | 167,124 | | | 146,555 | |
| | | | | |
| Other (expenses) income: | | | | | |
| Interest expense | (7,837) | | | (7,646) | | | (7,675) | |
| Other, net | (75) | | | (63) | | | (13) | |
| Total other (expenses) income | (7,912) | | | (7,709) | | | (7,688) | |
| | | | | |
| Income (loss) before income taxes | (8,772) | | | 19,850 | | | (60,161) | |
| Income tax benefit | (2,913) | | | (52,114) | | | (3,351) | |
| Net (loss) income | $ | (5,859) | | | $ | 71,964 | | | $ | (56,810) | |
| | | | | |
| | | | | |
| | | | | |
| Net (loss) earnings per share: | | | | | |
| Basic | $ | (0.08) | | | $ | 0.94 | | | $ | (0.71) | |
| Diluted | $ | (0.08) | | | $ | 0.90 | | | $ | (0.71) | |
| | | | | |
| Weighted-average shares of common stock outstanding - basic | 76,112 | | | 76,181 | | | 80,298 | |
| Weighted-average shares of common stock outstanding - diluted | 76,112 | | | 80,312 | | | 80,298 | |
| | | | | |
Adjusted Net Income(1) | $ | 5,307 | | | $ | 76,449 | | | $ | 19,447 | |
| Weighted-average shares of common stock outstanding - diluted | 79,210 | | | 80,312 | | | 84,447 | |
Diluted earnings per share on Adjusted Net Income(1) | $ | 0.07 | | | $ | 0.95 | | | $ | 0.23 | |
| | | | | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
| (unaudited)
($ and shares in thousands, except per share amounts) |
Adjusted EBITDA(1) | $ | 59,337 | | | $ | 77,508 | | | $ | 95,712 | |
Adjusted Free Cash Flow(1) | $ | (26,681) | | | $ | 55,803 | | | $ | 16,857 | |
| | | | | |
| | | | | |
Adjusted General and Administrative Expenses(1) | $ | 19,737 | | | $ | 19,410 | | | $ | 19,038 | |
| | | | | |
| Effective Tax Rate | 33 | % | | (263) | % | | 5 | % |
| |
| | | | | |
| |
| | | | | |
| Cash Flow Data: | | | | | |
| Net cash provided by operating activities | $ | 1,781 | | | $ | 105,407 | | | $ | 48,530 | |
| Net cash used in investing activities | $ | (30,460) | | | $ | (54,888) | | | $ | (36,560) | |
| Net cash used in financing activities | $ | (3,454) | | | $ | (45,742) | | | $ | (9,293) | |
__________
(1) See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”.
| | | | | | | | | | | |
| March 31, 2023 | | December 31, 2022 |
| (unaudited)
($ and shares in thousands) |
| Balance Sheet Data: | | | |
| Total current assets | $ | 132,612 | | | $ | 218,055 | |
| Total property, plant and equipment, net | $ | 1,346,882 | | | $ | 1,359,813 | |
| Total current liabilities | $ | 161,539 | | | $ | 234,207 | |
| Long-term debt | $ | 437,036 | | | $ | 395,735 | |
| Total stockholders' equity | $ | 752,936 | | | $ | 800,485 | |
Outstanding common stock shares as of | 76,583 | | | 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.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2023 |
| E&P | | Well Servicing and Abandonment | | Corporate/Eliminations | | Consolidated Company |
| (unaudited)
(in thousands) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Revenues(1) | $ | 171,847 | | | $ | 46,363 | | | $ | (1,740) | | | $ | 216,470 | |
| | | | | | | |
| | | | | | | |
| Net income (loss) before income taxes | $ | 24,170 | | | $ | 2,114 | | | $ | (35,056) | | | $ | (8,772) | |
| | | | | | | |
Adjusted EBITDA(2) | $ | 75,797 | | | $ | 5,438 | | | $ | (21,898) | | | $ | 59,337 | |
| Capital expenditures | $ | 19,272 | | | $ | 982 | | | $ | 379 | | | $ | 20,633 | |
| | | | | | | |
| Total assets | $ | 1,471,679 | | | $ | 80,897 | | | $ | (12,335) | | | $ | 1,540,241 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended March 31, 2022 |
| E&P | | Well Servicing and Abandonment | | Corporate/Eliminations | | Consolidated Company |
| (unaudited)
(in thousands) |
Revenues(1) | $ | 216,104 | | | $ | 39,836 | | | $ | — | | | $ | 255,940 | |
| Net loss before income taxes | $ | (34,291) | | | $ | (284) | | | $ | (25,586) | | | $ | (60,161) | |
| | | | | | | |
| | | | | | | |
Adjusted EBITDA(2) | $ | 105,649 | | | $ | 3,300 | | | $ | (13,237) | | | $ | 95,712 | |
| Capital expenditures | $ | 26,437 | | | $ | 628 | | | $ | 555 | | | $ | 27,620 | |
| Total assets | $ | 1,471,358 | | | $ | 73,887 | | | $ | (50,518) | | | $ | 1,494,727 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
__________
(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 |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
| Weighted Average Realized Prices | | | | | |
| Oil without hedge ($/bbl) | $ | 74.69 | | | $ | 80.61 | | | $ | 92.25 | |
| Effects of scheduled derivative settlements ($/bbl) | $ | (3.65) | | | $ | (7.22) | | | $ | (15.38) | |
| Oil with hedge ($/bbl) | $ | 71.04 | | | $ | 73.39 | | | $ | 76.87 | |
| Natural gas ($/mcf) | $ | 17.39 | | | $ | 12.02 | | | $ | 5.77 | |
| NGLs ($/bbl) | $ | 34.10 | | | $ | 29.67 | | | $ | 47.03 | |
| | | | | |
| Index Prices | | | | | |
| Brent oil ($/bbl) | $ | 82.16 | | | $ | 88.63 | | | $ | 97.90 | |
| WTI oil ($/bbl) | $ | 76.15 | | | $ | 82.51 | | | $ | 94.54 | |
Natural gas ($/mmbtu) – SoCal Gas city-gate(1) | $ | 24.81 | | | $ | 9.71 | | | $ | 6.74 | |
Natural gas ($/mmbtu) - Northwest, Rocky Mountains(2) | $ | 22.36 | | | $ | 7.54 | | | $ | 5.76 | |
Henry Hub natural gas ($/mmbtu)(2) | $ | 2.64 | | | $ | 5.55 | | | $ | 4.67 | |
__________
(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 our gas needs from the Rockies, with the balance purchased in California at various California indices. 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. Our key exposure to gas prices is in our costs. We purchase substantially more natural gas for our California steamfloods and cogeneration facilities than we produce and sell in the Rockies. In May 2022, we began purchasing most of our gas in the Rockies and transporting it to our California operations using our Kern River pipeline capacity. We buy approximately 48,000 mmbtu/d in the Rockies, and the remainder comes from California markets. The volume purchased in California fluctuates and averaged 3,000 mmbtu/d in Q1 2023, 12,000 mmbtu/d in Q4 2022 and 16,000 mmbtu/d in Q1 2022. The natural gas we purchase in the Rockies is shipped to our operations in California to help limit our exposure to California fuel gas purchase price fluctuations. We strive to further minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of our gas purchases. Additionally, the negative impact of higher gas prices on our California operating expenses is partially offset by higher gas sales for the gas we produce and sell in the Rockies.
CURRENT HEDGING SUMMARY
As of April 30, 2023, we had the following crude oil production and gas purchases hedges.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Q2 2023 | | Q3 2023 | | Q4 2023 | | FY 2024 | | FY 2025 | | FY 2026 |
| Brent - Crude Oil production | | | | | | | | | | |
| Swaps | | | | | | | | | | | |
| Hedged volume (bbls) | 1,387,750 | | | 1,211,717 | | | 1,196,000 | | | 3,412,817 | | | 99,337 | | | 9,518 | |
| Weighted-average price ($/bbl) | $ | 77.01 | | | $ | 76.26 | | | $ | 76.18 | | | $ | 76.07 | | | $ | 71.55 | | | $ | 71.55 | |
| Sold Calls | | | | | | | | | | | |
| Hedged volume (bbls) | 364,000 | | | 368,000 | | | 368,000 | | | 1,098,000 | | | 2,486,127 | | | 472,500 | |
| Weighted-average price ($/bbl) | $ | 106.00 | | | $ | 106.00 | | | $ | 106.00 | | | $ | 105.00 | | | $ | 91.11 | | | $ | 82.21 | |
Purchased Puts (net)(1) | | | | | | | | | | | |
| Hedged volume (bbls) | 546,000 | | | 552,000 | | | 552,000 | | | 1,281,000 | | | 2,486,127 | | | 472,500 | |
| Weighted-average price ($/bbl) | $ | 50.00 | | | $ | 50.00 | | | $ | 50.00 | | | $ | 50.00 | | | $ | 58.53 | | | $ | 60.00 | |
Sold Puts (net)(1) | | | | | | | | | | | |
| Hedged volume (bbls) | 132,668 | | | 184,000 | | | 154,116 | | | 183,000 | | | — | | | — | |
| Weighted-average price ($/bbl) | $ | 40.00 | | | $ | 40.00 | | | $ | 40.00 | | | $ | 40.00 | | | $ | — | | | $ | — | |
| Henry Hub - Natural Gas purchases | | | | | | | | | | |
| Consumer Collars | | | | | | | | | | | |
| Hedged volume (mmbtu) | 1,820,000 | | | — | | | — | | | — | | | — | | | — | |
| Weighted-average price ($/mmbtu) | $4.00/
$2.75 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| NWPL - Natural Gas purchases | | | | | | | | | | |
| Swaps | | | | | | | | | | | |
| Hedged volume (mmbtu) | 3,640,000 | | | 3,680,000 | | | 3,680,000 | | | 10,980,000 | | | 6,080,000 | | | — | |
| Weighted-average price ($/mmbtu) | $ | 5.34 | | | $ | 5.34 | | | $ | 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) Purchase puts and sold puts with the same strike price have been presented on a net basis.
E&P FIELD OPERATIONS
| | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
| (unaudited)
($ in per boe amounts) |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Expenses from field operations | | | | | |
| Lease operating expenses | $ | 61.65 | | | $ | 36.95 | | | $ | 26.25 | |
| Electricity generation expenses | 1.14 | | | 2.19 | | | 1.86 | |
| Transportation expenses | 0.48 | | | 0.43 | | | 0.48 | |
| Marketing expenses | — | | | — | | | 0.13 | |
| Total | $ | 63.27 | | | $ | 39.57 | | | $ | 28.72 | |
| | | | | |
| Cash settlements received for gas purchase hedges | $ | (25.11) | | | $ | (5.28) | | | $ | (0.69) | |
| | | | | |
| E&P non-production revenues | | | | | |
| Electricity sales | $ | 2.49 | | | $ | 3.49 | | | $ | 2.25 | |
| Transportation sales | 0.02 | | | 0.02 | | | 0.02 | |
| Marketing revenue | — | | | — | | | 0.12 | |
| Total | $ | 2.51 | | | $ | 3.51 | | | $ | 2.39 | |
| | | | | |
| | | | | |
Overall, management assesses the efficiency of our E&P field operations by considering core E&P operating expenses together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. We operate several cogeneration facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our cogeneration plants against other sources of steam in our 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 our E&P field operations and the revenues we receive from sales of excess electricity to the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural gas purchase hedges. Consequently, the efficiency of our E&P field operations are impacted by the cash settlements we receive or pay from these derivatives. We also have 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 our cogeneration facilities allocated to electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to our costs to transport the oil and gas that we produce within our properties or move it to the market. 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. Electricity revenue is from the sale of excess electricity from two of our 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 we transport on our 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 |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
Net Oil, Natural Gas and NGLs Production Per Day(1): | | | | | |
| Oil (mbbl/d) | | | | | |
| California | 19.9 | | 21.1 | | 22.2 |
Utah(2) | 2.7 | | 3.0 | | 2.2 |
Colorado(3) | — | | — | | — |
| Total oil | 22.6 | | 24.1 | | 24.4 |
| Natural gas (mmcf/d) | | | | | |
| California | — | | — | | — |
Utah(2) | 8.7 | | 7.8 | | 9.2 |
Colorado(3) | — | | — | | 2.3 |
| Total natural gas | 8.7 | | 7.8 | | 11.5 |
| NGLs (mbbl/d) | | | | | |
| California | — | | — | | — |
Utah(2) | 0.2 | | 0.4 | | 0.4 |
Colorado(3) | — | | — | | — |
| Total NGLs | 0.2 | | 0.4 | | 0.4 |
Total Production (mboe/d)(4) | 24.3 | | 25.8 | | 26.7 |
__________
(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 Antelope Creek area beginning February 2022, when it was acquired.
(3) In January 2022, we divested all of our natural gas properties in Colorado.
(4) 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 March 31, 2023, the average prices of Brent oil and Henry Hub natural gas were $82.16 per bbl and $2.64 per mmbtu respectively.
CAPITAL EXPENDITURES | | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | March 31, 2022 |
| | | (unaudited)
(in thousands) | | |
Capital expenditures (1)(2) | $ | 20,633 | | | $ | 50,398 | | | $ | 27,620 | |
__________
(1) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.
(2) Capital expenditures in the three months ended March 31, 2023, December 31, 2022 and March 31, 2022 included $1 million, $5 million and $1 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 determine the quarterly variable dividend. In early 2023, we updated our shareholder return model, including to double our quarterly fixed dividend to $0.12 per share. Any dividends actually paid will be determined by our Board of Directors in light of existing conditions, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors. We also modified the allocations of Adjusted Free Cash Flow. Our goal is to continue maximizing shareholder value through overall returns. The allocation beginning in 2023 will be (a) 80% primarily in the form of opportunistic debt or share repurchases, and could also include acquisitions of producing bolt-ons; and (b) 20% in the form of variable cash 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 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 non-GAAP financial measure Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided (or used) by operating activities, as applicable, for each of the periods indicated.
| | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
| (unaudited)
(in thousands) |
| Adjusted EBITDA reconciliation to net income (loss) and net cash provided by operating activities: |
| Net (loss) income | $ | (5,859) | | | $ | 71,964 | | | $ | (56,810) | |
| Add (Subtract): | | | | | |
| Interest expense | 7,837 | | | 7,646 | | | 7,675 | |
| Income tax benefit | (2,913) | | | (52,114) | | | (3,351) | |
| Depreciation, depletion, and amortization | 40,121 | | | 39,509 | | | 39,777 | |
| | | | | |
| | | | | |
| (Gains) losses on derivatives | (39,109) | | | 7,412 | | | 132,804 | |
| Net cash received (paid) for scheduled derivative settlements | 47,467 | | | (3,504) | | | (32,152) | |
| Other operating (income) expenses | (286) | | | (1,023) | | | 3,769 | |
| Stock compensation expense | 4,766 | | | 4,350 | | | 3,802 | |
Non-recurring costs(1) | 7,313 | | | 3,268 | | | 198 | |
| | | | | |
| Adjusted EBITDA | $ | 59,337 | | | $ | 77,508 | | | $ | 95,712 | |
| | | | | |
| | | | | |
| | | | | |
| Net cash provided by operating activities | $ | 1,781 | | | $ | 105,407 | | | $ | 48,530 | |
| Add (Subtract): | | | | | |
| Cash interest payments | 14,388 | | | 311 | | | 14,539 | |
| Cash income tax payments | — | | | 828 | | | — | |
| | | | | |
Non-recurring costs(1) | 7,313 | | | 3,268 | | | 198 | |
| | | | | |
Changes in operating assets and liabilities - working capital(2) | 36,745 | | | (31,003) | | | 27,766 | |
Other operating (income) expenses - cash portion(3) | (890) | | | (1,303) | | | 4,679 | |
| | | | | |
| Adjusted EBITDA | $ | 59,337 | | | $ | 77,508 | | | $ | 95,712 | |
| | | | | |
| | | | | |
__________(1) Non-recurring costs included executive transition costs in both the first quarter of 2023 and the fourth quarter of 2022, and workforce reduction costs in the first quarter of 2023. Non-recurring costs included legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022.
(2) Changes in other assets and liabilities consists of working capital and various immaterial items.
(3) Represents the cash portion of other operating expenses (income) from the income 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
March 31, 2023 |
| E&P | | Well Servicing and Abandonment | | Corporate/Eliminations | | Consolidated Company |
| (unaudited)
(in thousands) |
| Adjusted EBITDA reconciliation to net income (loss): | | | | | | |
| Net income (loss) | $ | 24,170 | | | $ | 2,114 | | | $ | (32,143) | | | $ | (5,859) | |
| Add (Subtract): | | | | | | | |
| Interest expense | — | | | 5 | | | 7,832 | | | 7,837 | |
| Income tax benefit | — | | | — | | | (2,913) | | | (2,913) | |
| Depreciation, depletion, and amortization | 33,835 | | | 3,256 | | | 3,030 | | | 40,121 | |
| | | | | | | |
| | | | | | | |
| Gains on derivatives | (39,109) | | | — | | | — | | | (39,109) | |
| Net cash received for scheduled derivative settlements | 47,467 | | | — | | | — | | | 47,467 | |
| Other operating expenses (income) | 1,809 | | | (82) | | | (2,013) | | | (286) | |
| | | | | | | |
| Stock compensation expense | 312 | | | 145 | | | 4,309 | | | 4,766 | |
Non-recurring costs(1) | 7,313 | | | — | | | — | | | 7,313 | |
| | | | | | | |
| Adjusted EBITDA | $ | 75,797 | | | $ | 5,438 | | | $ | (21,898) | | | $ | 59,337 | |
__________
(1) Non-recurring costs included executive transition and workforce reduction costs in the first quarter of 2023.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended
March 31, 2022 |
| E&P | | Well Servicing and Abandonment | | Corporate/Eliminations | | Consolidated Company |
| (unaudited)
(in thousands) |
| Adjusted EBITDA reconciliation to net income (loss): | | | | | | |
| Net loss | $ | (34,291) | | | $ | (284) | | | $ | (22,235) | | | $ | (56,810) | |
| Add (Subtract): | | | | | | | |
| Interest expense | — | | | — | | | 7,675 | | | 7,675 | |
| Income tax benefit | — | | | — | | | (3,351) | | | (3,351) | |
| Depreciation, depletion, and amortization | 35,474 | | | 3,179 | | | 1,124 | | | 39,777 | |
| | | | | | | |
| | | | | | | |
| Losses on derivatives | 132,804 | | | — | | | — | | | 132,804 | |
| Net cash paid for scheduled derivative settlements | (32,152) | | | — | | | — | | | (32,152) | |
| Other operating expenses | 3,495 | | | 174 | | | 100 | | | 3,769 | |
| | | | | | | |
| Stock compensation expense | 319 | | | 33 | | | 3,450 | | | 3,802 | |
Non-recurring costs(1) | — | | | 198 | | | — | | | 198 | |
| | | | | | | |
| Adjusted EBITDA | $ | 105,649 | | | $ | 3,300 | | | $ | (13,237) | | | $ | 95,712 | |
__________
(1) Non-recurring costs included legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022.
ADJUSTED FREE CASH FLOW
The following table presents a reconciliation of the non-GAAP financial measure Adjusted Free Cash Flow to the GAAP financial measure of operating cash flow for each of the periods indicated. We use Adjusted Free Cash Flow for our shareholder return model, which began in 2022.
| | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
| (in thousands) |
| Adjusted Free Cash Flow: | | | | | |
Net cash provided by operating activities(1) | $ | 1,781 | | | $ | 105,407 | | | $ | 48,530 | |
| Subtract: | | | | |
Maintenance capital(2) | (19,272) | | | (45,047) | | | (26,437) | |
Fixed dividends(3) | (9,190) | | | (4,557) | | | (5,236) | |
| Adjusted Free Cash Flow | $ | (26,681) | | | $ | 55,803 | | | $ | 16,857 | |
__________
(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 | |
| | | | March 31, 2023 | | December 31, 2022 | | March 31, 2022 | |
| | | | | | | | | | | |
| | | | | | (unaudited) (in thousands) |
Consolidated capital expenditures(a) | | | | | | $ | (20,633) | | | $ | (50,398) | | | $ | (27,620) | | |
Excluded items(b) | | | | | | 1,361 | | | 5,351 | | | 1,183 | | |
| Maintenance capital | | | | | | $ | (19,272) | | | $ | (45,047) | | | $ | (26,437) | | |
__________
(a) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.
(b) Comprised of the capital expenditures in our 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 our 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 our core business. For the three months ended March 31, 2023, three months ended December 31, 2022, and three months ended March 31, 2022 we excluded approximately $1 million, $5 million, and $0.6 million of capital expenditures related to our well servicing and abandonment segment, which was substantially all used for sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. For three months ended March 31, 2022, the three months ended December 31, 2022, and three months ended March 31, 2022 we excluded approximately $0.4 million, $0.5 million, and $0.6 million of corporate capital expenditures, which we determined was not related to the maintenance of our baseline production.
(3) Represents fixed dividends declared for the periods presented.
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss) to the GAAP financial measure of net income (loss) and Adjusted Net Income (Loss) per share — diluted to net income per share — diluted.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
| (in thousands) | | per share - diluted | | (in thousands) | | per share - diluted | | (in thousands) | | per share - diluted |
| (unaudited) |
| Adjusted Net Income (Loss) reconciliation to net income (loss): | | | |
| Net (loss) income | $ | (5,859) | | | $ | (0.07) | | | $ | 71,964 | | | $ | 0.90 | | | $ | (56,810) | | | $ | (0.67) | |
| | | | | | | | | | | |
| Add (Subtract): | | | | | | | | | | | |
| (Gains) losses on derivatives | (39,109) | | | (0.49) | | | 7,412 | | | 0.09 | | | 132,804 | | | 1.57 | |
| Net cash received (paid) for scheduled derivative settlements | 47,467 | | | 0.60 | | | (3,504) | | | (0.04) | | | (32,152) | | | (0.38) | |
| Other operating (income) expenses | (286) | | | (0.01) | | | (1,023) | | | (0.02) | | | 3,769 | | | 0.05 | |
| | | | | | | | | | | |
Non-recurring costs(1) | 7,313 | | | 0.09 | | | 3,268 | | | 0.04 | | | 198 | | | — | |
| Total additions, net | 15,385 | | | 0.19 | | | 6,153 | | | 0.07 | | | 104,619 | | | 1.24 | |
| | | | | | | | | | | |
Income tax expense of adjustments(2) | (4,219) | | | (0.05) | | | (1,668) | | | (0.02) | | | (28,362) | | | (0.34) | |
| Adjusted Net Income | $ | 5,307 | | | $ | 0.07 | | | $ | 76,449 | | | $ | 0.95 | | | $ | 19,447 | | | $ | 0.23 | |
| | | | | | | | | | | |
| Basic EPS on Adjusted Net Income | $ | 0.07 | | | | | $ | 1.00 | | | | | $ | 0.24 | | | |
| Diluted EPS on Adjusted Net Income | $ | 0.07 | | | | | $ | 0.95 | | | | | $ | 0.23 | | | |
| | | | | | | | | | | |
| Weighted average shares of common stock outstanding - basic | 76,112 | | | | | 76,181 | | | | | 80,298 | | | |
| Weighted average shares of common stock outstanding - diluted | 79,210 | | | | | 80,312 | | | | | 84,447 | | | |
__________(1) Non-recurring costs included executive transition costs in both the first quarter of 2023 and the fourth quarter of 2022 and workforce reduction costs in the first quarter of 2023. Non-recurring costs included legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022.
(2) 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 non-GAAP financial measure Adjusted General and Administrative Expenses to the GAAP financial measure of general and administrative expenses for each of the periods indicated.
| | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2023 | | December 31, 2022 | | March 31, 2022 |
| ($ in thousands except per mboe amounts) |
| Adjusted General and Administrative Expense reconciliation to general and administrative expenses: |
| General and administrative expenses | $ | 31,669 | | | $ | 26,926 | | | $ | 22,942 | |
| Subtract: | | | | | |
| Non-cash stock compensation expense (G&A portion) | (4,619) | | | (4,248) | | | (3,706) | |
Non-recurring costs(1) | (7,313) | | | (3,268) | | | (198) | |
| Adjusted General and Administrative Expenses | $ | 19,737 | | | $ | 19,410 | | | $ | 19,038 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Well servicing and abandonment segment | $ | 3,126 | | | $ | 3,296 | | | $ | 3,070 | |
| | | | | |
| E&P segment, and corporate | $ | 16,611 | | | $ | 16,114 | | | $ | 15,968 | |
| E&P segment, and corporate ($/boe) | $ | 7.60 | | | $ | 6.80 | | | $ | 6.64 | |
| | | | | |
| Total mboe | 2,187 | | | 2,371 | | | 2,406 | |
__________
(1) Non-recurring costs included executive transition costs in both the first quarter of 2023 and the fourth quarter of 2022, and workforce reduction costs in the first quarter of 2023. Non-recurring costs included legal and professional service expenses related to acquisition and divestiture activity for the first quarter of 2022.
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