Quarterly Highlights

  • Generated Adjusted EBITDA(1) of $69 million and Adjusted Free Cash Flow(1) of $34 million
  • Delivered strong operational results, with a nearly 7% increase in production over first quarter 2023
  • Repurchased more than 1.4 million shares of common stock at an average price of $7.04 per share
  • Declared total dividends of $0.14 per share
  • Signed agreement to acquire Kern County producer Macpherson Energy Corporation for $70 million funded partially through capital reallocation

__________
(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 second quarter we successfully executed on our strategy to deliver meaningful returns,” said Fernando Araujo, Berry’s CEO. “Our operational and financial performance was strong. We delivered a nearly 7% increase, or more than 1,600 boe per day, in production volumes quarter over quarter with less capital than planned. Additionally, we reduced lease operating expenses, net of hedges, by 23% compared to the first quarter, driven by lower fuel prices and a reduction in lease maintenance costs. As a result, we will pay total dividends this quarter of $0.14 per share, fixed plus variable. We also opportunistically repurchased 1.4 million shares in the open market at an average price of $7.04 per share.

“We are excited about our pending acquisition of Macpherson Energy Corporation, achieving our important strategic objective to acquire accretive, producing bolt-on assets. This transaction provides additional production and improved capital efficiency and will be funded partially through a reallocation of $35 million of capital in 2023. The Macpherson assets are high-quality, low decline oil producing properties, and are a natural fit with our existing rural Kern County portfolio. In addition to the attractive base production, we see upside for near-term production enhancement and development opportunities,” Araujo said.

Second Quarter 2023 Results

Net income was $26 million in the second quarter 2023 compared to a net loss of $6 million in the first quarter 2023 while Adjusted EBITDA was $69 million and $59 million, respectively. The 17% increase in Adjusted EBITDA was largely driven by increased production, coupled with lower fuel prices and lease maintenance costs, slightly offset by lower oil prices.

The Company’s average daily production increased in the second quarter 2023 to 25,900 boe/d compared to 24,300 boe/d in the first quarter 2023. Company-wide oil production in the second quarter 2023 was 24,000 bbl/d, accounting for 93% of total Company production, with California production contributing 20,800 boe/d or 80% of total production. Production was nearly 7% higher quarter-over-quarter due to improved base production from optimized steam injection in California, as well as making up for first quarter weather-related production downtime.

Company-wide realized oil price, including hedging effects, was $69.87 per bbl for the second quarter 2023 compared to $71.04 per bbl in the first quarter 2023. Excluding hedging effects, California’s average realized oil prices were $72.10 per bbl in the second quarter 2023, 93% of Brent, and $76.24 per bbl in the first quarter 2023, 93% of Brent.

Lease operating expenses, which includes fuel gas costs for California steam operations, decreased in the second quarter 2023 from the first quarter 2023 mostly as a result of lower natural gas (fuel) costs for our California steam generation facilities due to a significant price decrease. Lease operating expense excluding fuel decreased $2 million due to lower lease maintenance costs, which were uncharacteristically high in the first quarter 2023 as a consequence of adverse weather conditions.

Taxes, other than income taxes, increased 22%, in the second quarter 2023 compared to the first quarter 2023 due to higher mark-to-market prices for greenhouse gas (“GHG”) allowances in the second quarter.

General and administrative expenses decreased 29% in the second quarter 2023 compared to the first quarter 2023, in large part due to non-recurring executive transition and workforce reduction costs that occurred in the first quarter 2023. Adjusted General and Administrative Expenses(1), which excludes non-cash stock compensation costs and nonrecurring costs, decreased 3% in the second quarter 2023 compared to the first quarter 2023, as a result of the cost savings initiatives that began in early 2023.

The income for the well servicing and abandonment business, C&J Well Services, increased 129% to $5 million in the second quarter 2023 compared to the first quarter 2023, due to increased activity in the second quarter compared to the first quarter which had been impacted by weather-related customer demand.

For the second quarter 2023, capital expenditures were approximately $21 million, excluding acquisitions, asset retirement obligation spending and well servicing and abandonment capital of $1 million. This represented a 5% increase compared to the first quarter 2023 as a result of increased facilities and workover spending. Additionally, the Company spent approximately $6 million for plugging and abandonment activities in the second quarter 2023.

At June 30, 2023, the Company had liquidity of $186 million, consisting of $9 million cash and $177 million available for borrowings under its revolving credit facilities.

“We increased Adjusted EBITDA for the second quarter by 17% over the first quarter and generated solid Adjusted Free Cash Flow of $34 million. Executing on our commitment to return meaningful cash to shareholders, we purchased $10 million of Berry shares in the quarter for an average price of $7.04, and will continue to evaluate opportunities to generate and deliver returns consistent with our shareholder return model,” stated Mike Helm, Berry’s CFO. “Berry is hitting its targets and is well positioned for continued success in maximizing shareholder returns.”

2023 Outlook

We currently anticipate that our full-year results will be in line with previous guidance, before consideration of the Macpherson transaction, except with respect to capital expenditures. We expect 2023 capital expenditures for both Berry and C&J Well Services to be approximately $35 million lower than the $103 million to $113 million initial guidance as a result of the reallocation of capital to fund a portion of the Macpherson purchase price. We will fully update guidance in connection with the transaction close, expected late in the third quarter 2023.

Quarterly Dividends

The Company’s Board of Directors declared dividends totaling $0.14 per share on the Company’s outstanding common stock. The variable portion of $0.02 per share was based on the cumulative Adjusted Free Cash Flow results for the six months ended June 30, 2023 in accordance with the Company’s Shareholder Return Model. The fixed portion of $0.12 per share was also declared, and both dividends are payable on August 25, 2023 to shareholders of record at the close of business on August 15, 2023.

Earnings Conference Call

The Company will host a conference call to discuss these results:

 

Call Date:
Call Time:
Wednesday, August 2, 2023
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/yrmp93rj
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/BI1dce5edf8c144895becc0633be60f1dc
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/yrmp93rj 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, 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; consummation of the acquisition and the timing thereof; projected accretion to financial and production results; projected synergies related to the 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 execute and close the acquisition and to 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
June 30, 2023 March 31, 2023 June 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 $ 157,703 $ 166,357 $ 240,071
Service revenue 47,674 44,623 46,178
Electricity sales 3,078 5,445 7,419
Gains (losses) on oil and gas sales derivatives 20,871 38,499 (40,658 )
Other revenues 36 45 120
Total revenues and other 229,362 254,969 253,130
Expenses and other:
Lease operating expenses 54,707 134,835 72,455
Cost of services 37,083 36,099 36,709
Electricity generation expenses 1,273 2,500 6,122
Transportation expenses 1,096 1,041 1,108
Acquisition costs 972
General and administrative expenses 22,488 31,669 23,183
Depreciation, depletion and amortization 39,755 40,121 38,055
Taxes, other than income taxes 13,707 10,460 11,214
Losses (gains) on natural gas purchase derivatives 14,024 (610 ) 10,661
Other operating (income) expenses (1,033 ) (286 ) 353
Total expenses and other 184,072 255,829 199,860
Other (expenses) income:
Interest expense (8,794 ) (7,837 ) (7,729 )
Other, net (110 ) (75 ) (42 )
Total other (expenses) income (8,904 ) (7,912 ) (7,771 )
Income (loss) before income taxes 36,386 (8,772 ) 45,499
Income tax expense (benefit) 10,616 (2,913 ) 2,145
Net income (loss) $ 25,770 $ (5,859 ) $ 43,354
Net income (loss) per share:
Basic $ 0.34 $ (0.08 ) $ 0.54
Diluted $ 0.33 $ (0.08 ) $ 0.52
Weighted-average shares of common stock outstanding – basic 76,721 76,112 79,596
Weighted-average shares of common stock outstanding – diluted 79,285 76,112 83,015
Adjusted Net Income(1) $ 11,666 $ 5,307 $ 53,591
Weighted-average shares of common stock outstanding – diluted 79,285 79,210 83,015
Diluted earnings per share on Adjusted Net Income(1) $ 0.15 $ 0.07 $ 0.65
Three Months Ended
June 30, 2023 March 31, 2023 June 30, 2022
(unaudited)
($ and shares in thousands, except per share amounts)
Adjusted EBITDA(1) $ 69,055 $ 59,337 $ 109,747
Adjusted Free Cash Flow(1) $ 33,774 $ (26,681 ) $ 74,382
Adjusted General and Administrative Expenses(1) $ 19,109 $ 19,737 $ 18,920
Effective Tax Rate 29 % 33 % 5 %
Cash Flow Data:
Net cash provided by operating activities $ 62,538 $ 1,781 $ 111,242
Net cash used in investing activities $ (27,961 ) $ (30,460 ) $ (38,863 )
Net cash used in financing activities $ (40,128 ) $ (3,454 ) $ (37,844 )

__________
(1) See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”.

 

June 30, 2023 December 31, 2022
(unaudited)
($ and shares in thousands)
Balance Sheet Data:
Total current assets $ 134,431 $ 218,055
Total property, plant and equipment, net $ 1,335,572 $ 1,359,813
Total current liabilities $ 148,127 $ 234,207
Long-term debt $ 421,347 $ 395,735
Total stockholders’ equity $ 760,575 $ 800,485
Outstanding common stock shares as of 75,661 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 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 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 June 30, 2022
E&P Well Servicing and Abandonment Corporate/
Eliminations
Consolidated Company
(unaudited)
(in thousands)
Revenues(1) $ 247,610 $ 46,178 $ $ 293,788
Net income (loss) before income taxes $ 68,885 $ 3,307 $ (26,693 ) $ 45,499
Adjusted EBITDA(2) $ 116,942 $ 6,200 $ (13,395 ) $ 109,747
Capital expenditures $ 32,134 $ 1,066 $ 886 $ 34,086
Total assets $ 1,456,164 $ 71,543 $ 2,678 $ 1,530,385

__________
(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
June 30, 2023 March 31, 2023 June 30, 2022
Weighted Average Realized Prices
Oil without hedge ($/bbl) $ 70.68 $ 74.69 $ 105.70
Effects of scheduled derivative settlements ($/bbl) $ (0.81 ) $ (3.65 ) $ (21.92 )
Oil with hedge ($/bbl) $ 69.87 $ 71.04 $ 83.78
Natural gas ($/mcf) $ 2.87 $ 17.39 $ 7.35
NGLs ($/bbl) $ 22.16 $ 34.10 $ 56.47
Index Prices
Brent oil ($/bbl) $ 77.73 $ 82.16 $ 111.98
WTI oil ($/bbl) $ 73.73 $ 76.15 $ 108.71
Natural gas ($/mmbtu) – SoCal Gas city-gate(1) $ 5.66 $ 24.81 $ 7.53
Natural gas ($/mmbtu) – Northwest, Rocky Mountains(2) $ 2.85 $ 22.36 $ 6.69
Henry Hub natural gas ($/mmbtu)(2) $ 2.16 $ 2.64 $ 7.50

__________
(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 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. 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 Q2 2023, 3,000 mmbtu/d in Q1 2023 and 13,000 mmbtu/d in Q2 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.

GLJ

CURRENT HEDGING SUMMARY

As of July 31, 2023, we had the following crude oil production and gas purchases hedges.

 

Q3 2023 Q4 2023 FY 2024 FY 2025 FY 2026
Brent – Crude Oil production
Swaps
Hedged volume (bbls) 1,272,717 1,288,000 4,146,817 752,125 487,268
Weighted-average price ($/bbl) $ 76.54 $ 76.60 $ 76.13 $ 70.89 $ 68.71
Sold Calls(1)
Hedged volume (bbls) 368,000 368,000 732,000 2,486,127 472,500
Weighted-average price ($/bbl) $ 106.00 $ 106.00 $ 105.00 $ 91.11 $ 82.21
Purchased Puts (net)(2)
Hedged volume (bbls) 552,000 552,000 1,281,000 2,486,127 472,500
Weighted-average price ($/bbl) $ 50.00 $ 50.00 $ 50.00 $ 58.53 $ 60.00
Sold Puts (net)(2)
Hedged volume (bbls) 184,000 154,116 183,000
Weighted-average price ($/bbl) $ 40.00 $ 40.00 $ 40.00 $ $
Henry Hub – Natural Gas purchases
NWPL – Natural Gas purchases
Swaps
Hedged volume (mmbtu) 3,680,000 3,680,000 10,980,000 6,080,000
Weighted-average price ($/mmbtu) $ 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) 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
June 30, 2023 March 31, 2023 June 30, 2022
(unaudited)
($ in per boe amounts)
Expenses from field operations
Lease operating expenses $ 23.17 $ 61.65 $ 30.37
Electricity generation expenses 0.54 1.14 2.57
Transportation expenses 0.46 0.48 0.46
Total $ 24.17 $ 63.27 $ 33.40
Cash settlements paid (received) for gas purchase hedges $ 4.56 $ (25.11 ) $ (4.27 )
E&P non-production revenues
Electricity sales $ 1.30 $ 2.49 $ 3.11
Transportation sales 0.02 0.02 0.05
Total $ 1.32 $ 2.51 $ 3.16

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
June 30, 2023
March 31, 2023
June 30, 2022
Net Oil, Natural Gas and NGLs Production Per Day(1):
Oil (mbbl/d)
California 20.8 19.9 21.0
Utah(3) 3.2 2.7 3.0
Total oil 24.0 22.6 24.0
Natural gas (mmcf/d)
California
Utah(3) 9.2 8.7 11.0
Total natural gas 9.2 8.7 11.0
NGLs (mbbl/d)
California
Utah(3) 0.4 0.2 0.4
Total NGLs 0.4 0.2 0.4
Total Production (mboe/d)(2) 25.9 24.3 26.2

__________
(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) 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 June 30, 2023, the average prices of Brent oil and Henry Hub natural gas were $77.73 per bbl and $2.16 per mmbtu respectively.
(3) Includes production for Antelope Creek area from February 2022, when it was acquired, through June 30, 2023.

CAPITAL EXPENDITURES

 

Three Months Ended
June 30, 2023 March 31, 2023 June 30, 2022
(unaudited)
(in thousands)
Capital expenditures(1)(2) $ 21,895 $ 20,633 $ 34,086

__________
(1) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.
(2) Capital expenditures in the three months ended June 30, 2023, March 31, 2023 and June 30, 2022 each included $1 million, 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, 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 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
June 30, 2023 March 31, 2023 June 30, 2022
(unaudited)
(in thousands)
Adjusted EBITDA reconciliation to net income (loss) and net cash provided by operating activities:
Net income (loss) $ 25,770 $ (5,859 ) $ 43,354
Add (Subtract):
Interest expense 8,794 7,837 7,729
Income tax expense (benefit) 10,616 (2,913 ) 2,145
Depreciation, depletion, and amortization 39,755 40,121 38,055
(Gains) losses on derivatives (6,847 ) (39,109 ) 51,319
Net cash (paid) received for scheduled derivative settlements (12,524 ) 47,467 (37,628 )
Other operating (income) expenses (1,033 ) (286 ) 353
Stock compensation expense 3,552 4,766 4,420
Acquisition costs(1) 972
Non-recurring costs(2) 7,313
Adjusted EBITDA $ 69,055 $ 59,337 $ 109,747
Net cash provided by operating activities $ 62,538 $ 1,781 $ 111,242
Add (Subtract):
Cash interest payments 1,004 14,388 449
Cash income tax payments 670 2,484
Non-recurring costs(2) 7,313
Changes in operating assets and liabilities – working capital(3) 6,065 36,745 (4,058 )
Other operating (income) expenses – cash portion(4) (1,222 ) (890 ) (370 )
Adjusted EBITDA $ 69,055 $ 59,337 $ 109,747

__________
(1) Includes costs related to the acquisition of Macpherson Energy Corporation.
(2) Non-recurring costs included executive transition costs and workforce reduction costs in the first quarter of 2023.
(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
June 30, 2023
E&P Well Servicing and Abandonment Corporate/
Eliminations
Consolidated Company
(unaudited)
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
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) Includes costs related to the acquisition of Macpherson Energy Corporation.

 

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
June 30, 2022
E&P Well Servicing and Abandonment Corporate/
Eliminations
Consolidated Company
(unaudited)
(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss) $ 68,885 $ 3,307 $ (28,838 ) $ 43,354
Add (Subtract):
Interest expense 7,729 7,729
Income tax expense 2,145 2,145
Depreciation, depletion, and amortization 33,956 3,017 1,082 38,055
Losses on derivatives 51,319 51,319
Net cash paid for scheduled derivative settlements (37,628 ) (37,628 )
Other operating expenses (income) 30 (210 ) 533 353
Stock compensation expense 380 86 3,954 4,420
Adjusted EBITDA $ 116,942 $ 6,200 $ (13,395 ) $ 109,747

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. The Company uses Adjusted Free Cash Flow for its shareholder return model, which began in 2022.

 

Three Months Ended
June 30, 2023 March 31, 2023 June 30, 2022
(unaudited)
(in thousands)
Adjusted Free Cash Flow:
Net cash provided by operating activities(1) $ 62,538 $ 1,781 $ 111,242
Subtract:
Maintenance capital(2) (19,625 ) (19,272 ) (32,134 )
Fixed dividends(3) (9,139 ) (9,190 ) (4,726 )
Adjusted Free Cash Flow $ 33,774 $ (26,681 ) $ 74,382

__________
(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
June 30, 2023 March 31, 2023 June 30, 2022
(unaudited)
(in thousands)
Consolidated capital expenditures(a) $ (21,895 ) $ (20,633 ) $ (34,086 )
 Excluded items(b) 2,270 1,361 1,952
Maintenance capital $ (19,625 ) $ (19,272 ) $ (32,134 )

__________
(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 June 30, 2023, March 31, 2023, and June 30, 2022, the Company excluded approximately $1.3 million, $1 million, and $1 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 June 30, 2023, March 31, 2023, and June 30, 2022, the Company excluded approximately $0.9 million, $0.4 million, and $0.9 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 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
June 30, 2023 March 31, 2023 June 30, 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 income (loss) $ 25,770 $ 0.33 $ (5,859 ) $ (0.07 ) $ 43,354 $ 0.52
Add (Subtract):
(Gains) losses on derivatives (6,847 ) (0.09 ) (39,109 ) (0.49 ) 51,319 0.62
Net cash (paid) received for scheduled derivative settlements (12,524 ) (0.16 ) 47,467 0.60 (37,628 ) (0.45 )
Other operating (income) expenses (1,033 ) (0.01 ) (286 ) (0.01 ) 353 0.01
Acquisition costs(1) 972 0.01
Non-recurring costs(2) 7,313 0.09
Total additions (subtractions), net (19,432 ) (0.25 ) 15,385 0.19 14,044 0.18
Income tax expense (benefit) of adjustments(3) 5,328 0.07 (4,219 ) (0.05 ) (3,807 ) (0.05 )
Adjusted Net Income $ 11,666 $ 0.15 $ 5,307 $ 0.07 $ 53,591 $ 0.65
Basic EPS on Adjusted Net Income $ 0.15 $ 0.07 $ 0.67
Diluted EPS on Adjusted Net Income $ 0.15 $ 0.07 $ 0.65
Weighted average shares of common stock outstanding – basic 76,721 76,112 79,596
Weighted average shares of common stock outstanding – diluted 79,285 79,210 83,015

__________
(1) Includes costs related to the acquisition of Macpherson Energy Corporation.
(2) Non-recurring costs included executive transition costs and workforce reduction costs in the first quarter of 2023.
(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 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
June 30, 2023 March 31, 2023 June 30, 2022
(unaudited)
($ in thousands)
Adjusted General and Administrative Expense reconciliation to general and administrative expenses:
General and administrative expenses $ 22,488 $ 31,669 $ 23,183
Subtract:
Non-cash stock compensation expense (G&A portion) (3,379 ) (4,619 ) (4,263 )
Non-recurring costs(1) (7,313 )
Adjusted General and Administrative Expenses $ 19,109 $ 19,737 $ 18,920
Well servicing and abandonment segment $ 2,958 $ 3,126 $ 3,285
E&P segment, and corporate $ 16,151 $ 16,611 $ 15,635
E&P segment, and corporate ($/boe) $ 6.84 $ 7.60 $ 6.55
 Total mboe 2,361 2,187 2,386

__________
(1) Non-recurring costs included executive transition costs and workforce reduction costs in the first quarter of 2023.