Berry Corporation Reports First Quarter 2024 Financial and Operating Results, Declares Dividend

DALLAS, May 01, 2024 (GLOBE NEWSWIRE) -- Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) announced first quarter 2024 results and declared a fixed dividend. The details for today’s earnings call and webcast are listed below.

Quarterly Highlights & Recent Announcements

• Produced 25,400 boe/d, above the midpoint of 2024 annual guidance of 25,200 boe/d
• Declared first quarter fixed dividends of $0.12 per share
• Acquired all necessary 2024 California Greenhouse Gas allowances at a 7% discount to the projected cost
• Signed agreement to farm into four horizontal wells immediately offsetting our Uinta Basin, UT acreage; wells expected to be on production by June 2024
• Follow-on working interest acquisition of ~100 boe/d in Kern County, CA in process
• Reported zero recordable incidents, zero lost-time incidents, and no reportable spills for the second consecutive quarter
• Issued 2023 Sustainable Business Report; includes setting an 80% reduction goal for methane emissions associated with our existing operations by the end of 2025

“In the first quarter, we delivered solid financial and operational results. The results are in line with projections, and we expect to deliver full-year results consistent with the production, capital and cost guidance we provided in March. Our teams have shown a remarkable ability to deploy their ingenuity and demonstrate resiliency in the face of a dynamic California regulatory environment. We continue to see strong base production, especially from our thermal diatomite reservoirs. By June 2024, we are also expecting first production from four horizontal well farm-in in Utah; an upside potential that could change our development outlook for the basin in future years. I want to emphasize that our 2024 development activity and production plan does not depend on the issuance of new drill permits, and so is not impacted by the ongoing Kern County EIR litigation which essentially has restricted the issuance of new drill permits,” said Fernando Araujo, Berry’s Chief Executive Officer.

He continued, “We are focused on maximizing enterprise value by generating sustainable free cash flow through operational excellence. Operational excellence includes keeping production flat, acquiring accretive, producing bolt-on assets, efficiently allocating capital, managing our cost structure, and prioritizing safety and compliance. We are confident we can continue to rise to the challenge to sustain production and maintain our enterprise value for the long-term.”

Selected Comparative Results

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
	(unaudited) (in millions, except per share amounts)
Oil, natural gas & NGL revenues(1)	$	166			$	172			$	166
Net (loss) income	$	(40	)		$	63			$	(6	)
Adjusted Net Income	$	11			$	10			$	5
Cash flow from operations	$	27			$	79			$	2
Adjusted EBITDA(2)	$	69			$	70			$	59
Earnings (loss) per diluted share	$	(0.53	)		$	0.81			$	(0.08	)
Adjusted earnings per diluted share(2)	$	0.14			$	0.13			$	0.07
Adjusted free cash flow(2)	$	1			$	55			$	(27	)
Capital expenditures	$	17			$	17			$	21
Production boe/d		25.4				25.9				24.3

__________
^{(1)   Revenues do not include hedge settlements.
(2)   Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for reconciliation and more information on these Non-GAAP measures.}

“We finished the first quarter with Adjusted EBITDA of $69 million despite slightly lower oil prices and production than the fourth quarter of 2023. We demonstrated resilience through strategic cost management, resulting in a 10% reduction in lease operating expenses. Our proactive approach has also led to significant savings of 7% in greenhouse gas credit purchases compared to projected costs, underscoring our commitment to both fiscal responsibility and environmental stewardship. With capital expenditures anticipated to increase in the second and third quarters of 2024 and an expected uptick in our well services business, we expect our results for the year to be in-line with our previously reported guidance. We will also maintain focus on debt reduction and look to opportunistically refinance our notes, which mature in early 2026,” stated Mike Helm, Berry’s CFO.

First Quarter 2024 Financial and Operating Results

Oil, natural gas and NGL revenues (excluding hedging settlements) for the first quarter of 2024 decreased 3% from the fourth quarter of 2023, driven by lower oil prices and a 1% decrease in oil volumes. The net loss for the first quarter of 2024 included unrealized hedge losses, while the Company recognized savings in lease operating expenses, mostly due to lower fuel gas prices. Adjusted EBITDA and Adjusted Net Income were essentially flat in the first quarter of 2024, compared to the prior quarter. Typical first quarter usage of working capital resulted in decreased cash flows from operations and Adjusted Free Cash Flow compared to the fourth quarter of 2023. Capital expenditures were $17 million in both the first quarter of 2024 and fourth quarter of 2023. At March 31, 2024, the Company had liquidity of $149 million, consisting of $3 million cash and $146 million available for borrowings under its revolving credit facilities.

Compared to the first quarter of the prior year, oil, natural gas and NGL revenues (excluding hedging settlements) were flat as production was higher and natural gas prices were lower in the first quarter of 2024. Adjusted EBITDA for the first quarter of 2024 increased 15% and Adjusted Net Income increased 106% compared to the first quarter of 2023, driven by a 19% decrease in expenses from field operations. Cash flow from operations and Adjusted Free Cash Flow increased in the first quarter of 2024 compared to the first quarter of 2023 due to the higher earnings and improved working capital impacts. Capital expenditures for the first quarter of 2024 were $17 million and decreased 19% compared to the first quarter of 2023. The Company was able to increase year over year production by nearly 5% largely due to the impact of bolt-on acquisitions in late 2023, allowing Berry to meet production targets while reducing drilling, workover and other activities on the legacy Berry assets.

Quarterly Dividends

The Company’s Board of Directors declared dividends totaling $0.12 per share on the Company’s outstanding common stock. There was no variable dividend declared based on the cumulative Adjusted Free Cash Flow results for the three months ended March 31, 2024 in accordance with the Company's Shareholder Return Model. The fixed dividend is payable on May 24, 2024 to shareholders of record at the close of business on May 15, 2024.

Earnings Conference Call

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

Call Date:	Wednesday, May 1, 2024
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/93zafnyz 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/BIa0fc2994657d43219ff18597216ccb2e
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/93zafnyz or
https://bry.com/category/events

About Berry Corporation (bry)

Berry is a publicly traded (NASDAQ: BRY) western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived oil and gas reserves. We operate in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment. Our E&P assets are located in California and Utah, are characterized by high oil content and are predominantly located in rural areas with low population. Our California assets are in the San Joaquin basin (100% oil), while our Utah assets are in the Uinta basin (60% oil and 40% gas). We operate our well servicing and abandonment segment in California. More information can be found at the Company’s website at bry.com.

Forward-Looking Statements

The information in this press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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. All statements, other than statements of historical facts, included in this press release that address plans, activities, events, objectives, goals, strategies, or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding our financial position; liquidity; cash flows (including, but not limited to, Adjusted Free Cash Flow); financial and operating results; capital program and development and production plans; operations and business strategy; potential acquisition and other strategic opportunities; reserves; hedging activities; capital expenditures; return of capital; our shareholder return model and the payment of future dividends; future repurchases of stock or debt; capital investments; our ESG strategy and the initiation of new projects or business in connection therewith, recovery factors; and other guidance are forward-looking statements. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases always vary from actual results, sometimes materially.

Berry cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to acquisition transactions and the exploration for and development, production, gathering and sale of natural gas, NGLs and oil most of which are difficult to predict and many of which are beyond Berry’s control. These risks include, but are not limited to, commodity price volatility; legislative and regulatory actions that may prevent, delay or otherwise restrict our ability to drill and develop our assets, including with respect to existing and/or new requirements in the regulatory approval and permitting process; legislative and regulatory initiatives in California or our other areas of operation addressing climate change or other environmental concerns; investment in and development of competing or alternative energy sources; drilling, production and other operating risks; effects of competition; uncertainties inherent in estimating natural gas and oil reserves and in projecting future rates of production; our ability to replace our reserves through exploration and development activities or strategic transactions; cash flow and access to capital; the timing and funding of development expenditures; environmental, health and safety risks; effects of hedging arrangements; potential shut-ins of production due to lack of downstream demand or storage capacity; disruptions to, capacity constraints in, or other limitations on the third-party transportation and market takeaway infrastructure (including pipeline systems) that deliver our oil and natural gas and other processing and transportation considerations; the ability to effectively deploy our ESG strategy and risks associated with initiating new projects or business in connection therewith; our ability to successfully integrate the Macpherson assets into our operations; we fail to identify risks or liabilities related to Macpherson, its operations or assets; our inability to achieve anticipated synergies; our ability to successfully execute other strategic bolt-on acquisitions; overall domestic and global political and economic conditions; inflation levels, including increased interest rates and volatility in financial markets and banking; changes in tax laws and the other risks described under the heading “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 and subsequent filings with the SEC.

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
[phone]
[e-mail]

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, 2024				December 31, 2023				March 31, 2023
	(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	$	166,318			$	172,439			$	166,357
Service revenue		31,683				40,746				44,623
Electricity sales		4,243				2,905				5,445
(Losses) gains on oil and gas sales derivatives		(71,200	)			83,918				38,499
Other revenues		67				319				45
Total revenues and other		131,111				300,327				254,969
Expenses and other:
Lease operating expenses		60,697				67,342				134,835
Cost of services		27,304				32,783				36,099
Electricity generation expenses		1,093				1,827				2,500
Transportation expenses		1,059				1,260				1,041
Acquisition costs		2,617				284				—
General and administrative expenses		20,234				20,729				31,669
Depreciation, depletion and amortization		42,831				40,937				40,121
Taxes, other than income taxes		15,689				15,826				10,460
Losses (gains) on natural gas purchase derivatives		4,481				21,397				(610	)
Other operating (income) expenses		(133	)			36				(286	)
Total expenses and other		175,872				202,421				255,829
Other expenses:
Interest expense		(9,140	)			(9,680	)			(7,837	)
Other, net		(83	)			(10	)			(75	)
Total other expenses		(9,223	)			(9,690	)			(7,912	)
(Loss) income before income taxes		(53,984	)			88,216				(8,772	)
Income tax (benefit) expense		(13,900	)			25,665				(2,913	)
Net (loss) income	$	(40,084	)		$	62,551			$	(5,859	)
Net (loss) income per share:
Basic	$	(0.53	)		$	0.83			$	(0.08	)
Diluted	$	(0.53	)		$	0.81			$	(0.08	)
Weighted-average shares of common stock outstanding - basic		76,254				75,667				76,112
Weighted-average shares of common stock outstanding - diluted		76,254				77,349				76,112
Adjusted Net Income(1)	$	10,910			$	10,426			$	5,307
Weighted-average shares of common stock outstanding - diluted		77,373				77,349				79,210
Diluted earnings per share on Adjusted Net Income(1)	$	0.14			$	0.13			$	0.07
	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
	(unaudited) ($ and shares in thousands, except per share amounts)
Adjusted EBITDA(1)	$	68,534			$	70,036			$	59,337
Adjusted Free Cash Flow(1)	$	1,104			$	54,824			$	(26,681	)
Adjusted General and Administrative Expenses(1)	$	18,943			$	17,886			$	19,737
Effective Tax Rate		26	%			29	%			33	%
Cash Flow Data:
Net cash provided by operating activities	$	27,273			$	79,018			$	1,781
Net cash used in investing activities	$	(18,661	)		$	(48,822	)		$	(30,460	)
Net cash used in financing activities	$	(9,990	)		$	(42,561	)		$	(3,454	)

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

	March 31, 2024				December 31, 2023
	(unaudited) ($ and shares in thousands)
Balance Sheet Data:
Total current assets	$	139,373			$	140,800
Total property, plant and equipment, net	$	1,384,704			$	1,406,612
Total current liabilities	$	230,447			$	223,182
Long-term debt	$	448,121			$	427,993
Total stockholders' equity	$	688,844			$	757,976
Outstanding common stock shares as of		76,939				75,667

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, 2024
	E&P				Well Servicing and Abandonment				Corporate/ Eliminations				Consolidated Company
	(unaudited) (in thousands)
Revenues(1)	$	170,628			$	35,468			$	(3,785	)		$	202,311
Net (loss) income before income taxes	$	(24,836	)		$	(1,269	)		$	(27,879	)		$	(53,984	)
Capital expenditures	$	15,417			$	1,332			$	187			$	16,936
Total assets	$	1,625,178			$	65,948			$	(115,610	)		$	1,575,516

	Three Months Ended December 31, 2023
	E&P				Well Servicing and Abandonment				Corporate/ Eliminations				Consolidated Company
	(unaudited) (in thousands)
Revenues(1)	$	175,663			$	42,846			$	(2,100	)		$	216,409
Net income (loss) before income taxes	$	113,122			$	3,217			$	(28,123	)		$	88,216
Capital expenditures	$	15,114			$	1,385			$	504			$	17,003
Total assets	$	1,652,979			$	68,670			$	(127,491	)		$	1,594,158

	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	)
Capital expenditures	$	19,272			$	982			$	379			$	20,633
Total assets	$	1,471,679			$	80,897			$	(12,335	)		$	1,540,241

__________
^{(1)   These revenues do not include hedge settlements.}

COMMODITY PRICING

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
Weighted Average Realized Prices
Oil without hedge ($/bbl)	$	75.31			$	76.00			$	74.69
Effects of scheduled derivative settlements ($/bbl)		(2.17	)			(3.35	)			(3.65	)
Oil with hedge ($/bbl)	$	73.14			$	72.65			$	71.04
Natural gas ($/mcf)	$	3.76			$	4.48			$	17.39
NGLs ($/bbl)	$	29.60			$	24.01			$	34.10
Purchased Natural Gas
Purchase price, before the effects of derivative settlements ($/mmbtu)	$	3.99			$	5.29			$	20.74
Effects of derivative settlements ($/mmbtu)		0.92				0.44				(11.86	)
Purchase price, after the effects of derivative settlements ($/mmbtu)	$	4.91			$	5.73			$	8.88
Index Prices
Brent oil ($/bbl)	$	81.76			$	82.85			$	82.16
WTI oil ($/bbl)	$	77.02			$	78.49			$	76.15
Natural gas ($/mmbtu) – SoCal Gas city-gate(1)	$	4.21			$	6.25			$	24.81
Natural gas ($/mmbtu) - Northwest, Rocky Mountains(2)	$	3.41			$	4.53			$	22.36
Henry Hub natural gas ($/mmbtu)(2)	$	2.15			$	2.74			$	2.64

__________
^{(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. SoCal Gas city-gate Index is the relevant index used only for the portion of gas purchases in California. Beginning in the first quarter of 2023, we purchase a majority of our fuel gas in the Rockies. As a result, 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 were Kern, Delivered.
(2)   Most of our gas purchases and gas sales in the Rockies are predicated on the Northwest, Rocky Mountains index, and to a lesser extent based on Henry Hub.}

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. The Company purchases most of its gas in the Rockies and transports it to its 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 5,000 mmbtu/d in the first quarter of 2024, 6,000 mmbtu/d in the fourth quarter of 2023 and 3,000 mmbtu/d in the first quarter of 2023. The natural gas purchased in the Rockies is shipped to operations in California to help limit exposure to California fuel gas purchase price fluctuations. The Company strives to further minimize the variability of fuel gas costs for steam operations by hedging a significant portion of gas purchases. Additionally, the negative impact of higher gas prices on California operating expenses is partially offset by higher gas sales for the gas produced and sold in the Rockies. The Kern capacity allows us to purchase and sell natural gas at the same pricing indices.

CURRENT HEDGING SUMMARY

As of April 30, 2024, we had the following crude oil production and gas purchases hedges.

	Q2 2024				Q3 2024				Q4 2024				FY 2025				FY 2026				FY 2027
Brent - Crude Oil production
Swaps
Hedged volume (bbls)		1,611,294				1,481,749				1,438,656				4,859,125				2,039,268				540,000
Weighted-average price ($/bbl)	$	78.97			$	76.88			$	76.93			$	76.08			$	71.11			$	71.42
Sold Calls(1)
Hedged volume (bbls)		91,000				92,000				92,000				296,127				1,251,500				—
Weighted-average price ($/bbl)	$	105.00			$	105.00			$	105.00			$	88.69			$	85.53			$	—
Purchased Puts (net)(2)
Hedged volume (bbls)		318,500				322,000				322,000				—				—				—
Weighted-average price ($/bbl)	$	50.00			$	50.00			$	50.00			$	—			$	—			$	—
Purchased Puts (net)(2)
Hedged volume (bbls)		—				—				—				296,127				1,251,500				—
Weighted-average price ($/bbl)	$	—			$	—			$	—			$	60.00			$	60.00			$	—
Sold Puts (net)(2)
Hedged volume (bbls)		45,500				46,000				46,000				—				—				—
Weighted-average price ($/bbl)	$	40.00			$	40.00			$	40.00			$	—			$	—			$	—
NWPL - Natural Gas purchases(3)
Swaps
Hedged volume (mmbtu)		3,640,000				3,680,000				3,680,000				13,380,000				3,040,000				—
Weighted-average price ($/mmbtu)	$	3.96			$	3.96			$	3.96			$	4.27			$	4.26			$	—

__________
^{(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.
(3)   The term “NWPL” is defined as Northwest Rocky Mountain Pipeline.}

(LOSSES) GAINS ON DERIVATIVES

A summary of gains and losses on the derivatives included on the statements of operations is presented below:

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
	(unaudited) (in thousands)
Realized (losses) gains on commodity derivatives:
Realized (losses) on oil sales derivatives	$	(4,682	)		$	(7,405	)		$	(7,438	)
Realized (losses) gains on natural gas purchase derivatives		(4,412	)			(2,211	)			54,905
Total realized (losses) gains on derivatives	$	(9,094	)		$	(9,616	)		$	47,467
Unrealized (losses) gains on commodity derivatives:
Unrealized (losses) gains on oil sales derivatives	$	(66,518	)		$	91,323			$	45,937
Unrealized (losses) on natural gas purchase derivatives		(69	)			(19,186	)			(54,295	)
Total unrealized (losses) gains on derivatives	$	(66,587	)		$	72,137			$	(8,358	)
Total (losses) gains on derivatives	$	(75,681	)		$	62,521			$	39,109

E&P FIELD OPERATIONS

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
	(unaudited) ($ in per boe amounts)
Expenses from field operations
Lease operating expenses	$	26.28			$	28.25			$	61.65
Electricity generation expenses		0.47				0.77				1.14
Transportation expenses		0.46				0.53				0.48
Total	$	27.21			$	29.55			$	63.27
Cash settlements paid (received) for gas purchase hedges	$	1.91			$	0.93			$	(25.11	)
E&P non-production revenues
Electricity sales	$	1.84			$	1.22			$	2.49
Transportation sales		0.03				0.13				0.02
Total	$	1.87			$	1.35			$	2.51

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
	March 31, 2024			December 31, 2023			March 31, 2023
Net Oil, Natural Gas and NGLs Production Per Day(1):
Oil (mbbl/d)
California	21.3			21.5			19.9
Utah	2.5			2.5			2.7
Total oil	23.8			24.0			22.6
Natural gas (mmcf/d)
California	—			—			—
Utah	7.9			7.8			8.7
Total natural gas	7.9			7.8			8.7
NGLs (mbbl/d)
California	—			—			—
Utah	0.3			0.6			0.2
Total NGLs	0.3			0.6			0.2
Total Production (mboe/d)(2)	25.4			25.9			24.3

__________
^{(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 March 31, 2024, the average prices of Brent oil and Henry Hub natural gas were $81.76 per bbl and $2.15 per mmbtu respectively.}

CAPITAL EXPENDITURES

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
					(unaudited) (in thousands)
Capital expenditures (1)(2)	$	16,936			$	17,003			$	20,633

__________
^{(1)   Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.
(2)   Capital expenditures for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023 included $1 million, for all periods presented, related to 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 expenditure 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 Free Cash Flow, which is a non-GAAP financial measure, as cash flow from operations less regular fixed dividends and capital expenditures. In 2024, we updated the definition of Adjusted Free Cash Flow, a non-GAAP measure, as cash flow from operations less regular fixed dividends and capital expenditures. This update better aligns with the full capital expenditure requirements of the Company. For 2023, Adjusted Free Cash Flow was defined as cash flow from operations less regular fixed dividends and maintenance capital. Management believes Adjusted Free Cash Flow may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base after maintaining the existing production volumes of that asset base to return capital to stockholders, fund further business expansion through acquisitions or investments in our existing asset base to increase production volumes and pay other non-discretionary expenses. Management also uses Adjusted Free Cash Flow as the primary metric to plan for future growth.

Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchases, strategic acquisitions or other growth opportunities, or other discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from this measure.

We define Adjusted 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 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 reconciliations of the GAAP financial measures of net income (loss) and net cash provided (used) by operating activities to the non-GAAP financial measure of Adjusted EBITDA, as applicable, for each of the periods indicated.

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
	(unaudited) (in thousands)
Adjusted EBITDA reconciliation:
Net (loss) income	$	(40,084	)		$	62,551			$	(5,859	)
Add (Subtract):
Interest expense		9,140				9,680				7,837
Income tax (benefit) expense		(13,900	)			25,665				(2,913	)
Depreciation, depletion, and amortization		42,831				40,937				40,121
Losses (gains) on derivatives		75,681				(62,521	)			(39,109	)
Net cash (paid) received for scheduled derivative settlements		(9,094	)			(9,616	)			47,467
Other operating (income) expenses		(133	)			36				(286	)
Stock compensation expense(1)		385				3,020				4,766
Acquisition costs(2)		2,617				284				—
Non-recurring costs(3)		1,091				—				7,313
Adjusted EBITDA	$	68,534			$	70,036			$	59,337
Net cash provided by operating activities	$	27,273			$	79,018			$	1,781
Add (Subtract):
Cash interest payments		15,256				1,794				14,388
Cash income tax payments		—				525				—
Acquisition costs(2)		2,617				284				—
Non-recurring costs(3)		1,091				—				7,313
Changes in operating assets and liabilities - working capital(4)		22,543				(11,070	)			36,745
Other operating (income) expenses - cash portion(5)		(246	)			(515	)			(890	)
Adjusted EBITDA	$	68,534			$	70,036			$	59,337

__________
^{(1)   Decrease in the first quarter of 2024 is the result of stock award forfeitures.
(2)   Includes legal and other professional expenses related to various transactions activities.
(3)   In 2024, non-recurring costs included workforce reduction costs in the first quarter. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter.
(4)   Changes in other assets and liabilities consists of working capital and various immaterial items.
(5)   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 FREE CASH FLOW

The following table presents a reconciliation of the GAAP financial measure of operating cash flow to the non-GAAP financial measure of Adjusted Free Cash Flow for each of the periods indicated. We use Adjusted Free Cash Flow for our shareholder return model.

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
	(unaudited) (in thousands)
Adjusted Free Cash Flow reconciliation:
Net cash provided by operating activities(1)	$	27,273			$	79,018			$	1,781
Subtract:
Capital expenditures(2)		(16,936	)			(15,114	)			(19,272	)
Fixed dividends(3)		(9,233	)			(9,080	)			(9,190	)
Adjusted Free Cash Flow	$	1,104			$	54,824			$	(26,681	)

__________
^{(1)   On a consolidated basis.
(2)   In 2024, we updated Adjusted Free Cash Flow to include all capital expenditures in the calculation of Adjusted Free Cash Flow. This update better aligns with the full capital expenditure requirements of the Company. In 2023, the definition of capital expenditures was the required amount to keep annual production essentially flat (maintenance capital), calculated as the capital expenditures for the E&P business for the periods presented. We did not retrospectively adjust 2023.}

	Three Months Ended
	December 31, 2023				March 31, 2023
	(unaudited) (in thousands)
Consolidated capital expenditures(a)	$	(17,003	)		$	(20,633	)
Excluded items(b)		1,889				1,361
Maintenance capital	$	(15,114	)		$	(19,272	)

__________
^{(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 December 31, 2023 and March 31, 2023, we excluded approximately $1 million of capital expenditures related to our well servicing and abandonment segment, for both periods presented, which was substantially all used for sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. For the three months ended December 31, 2023 and March 31, 2023, we excluded approximately $0.5 million and $0.4 million of corporate capital expenditures, respectively, 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 GAAP financial measures of net income (loss) and net income (loss) per share — diluted to the non-GAAP financial measures of Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share — diluted for each of the periods indicated.

	Three Months Ended
	March 31, 2024								December 31, 2023								March 31, 2023
	(in thousands)				per share - diluted				(in thousands)				per share - diluted				(in thousands)				per share - diluted
	(unaudited)
Adjusted Net Income (Loss) reconciliation:
Net (loss) income	$	(40,084	)		$	(0.52	)		$	62,551			$	0.81			$	(5,859	)		$	(0.07	)
Add (Subtract):
Losses (gains) on derivatives		75,681				0.98				(62,521	)			(0.81	)			(39,109	)			(0.49	)
Net cash (paid) received for scheduled derivative settlements		(9,094	)			(0.12	)			(9,616	)			(0.12	)			47,467				0.60
Other operating (income) expenses		(133	)			—				36				—				(286	)			(0.01	)
Acquisition costs(1)		2,617				0.03				284				—				—				—
Non-recurring costs(2)		1,091				0.02				—				—				7,313				0.09
Total additions (subtractions), net		70,162				0.91				(71,817	)			(0.93	)			15,385				0.19
Income tax (benefit) expense of adjustments(3)		(19,168	)			(0.25	)			19,692				0.25				(4,219	)			(0.05	)
Adjusted Net Income	$	10,910			$	0.14			$	10,426			$	0.13			$	5,307			$	0.07
Basic EPS on Adjusted Net Income	$	0.14							$	0.14							$	0.07
Diluted EPS on Adjusted Net Income	$	0.14							$	0.13							$	0.07
Weighted average shares of common stock outstanding - basic		76,254								75,667								76,112
Weighted average shares of common stock outstanding - diluted		77,373								77,349								79,210

__________
^{(1)   Includes legal and other professional expenses related to various transactions activities.
(2)   In 2024, non-recurring costs included workforce reduction costs in the first quarter. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter.
(3)   The federal and state statutory rates were utilized for all periods presented.}

ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES

The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measure of Adjusted General and Administrative Expenses for each of the periods indicated.

	Three Months Ended
	March 31, 2024				December 31, 2023				March 31, 2023
	(unaudited) ($ in thousands)
Adjusted General and Administrative Expense reconciliation:
General and administrative expenses	$	20,234			$	20,729			$	31,669
Subtract:
Non-cash stock compensation expense (G&A portion)(1)		(200	)			(2,843	)			(4,619	)
Non-recurring costs(2)		(1,091	)			—				(7,313	)
Adjusted General and Administrative Expenses	$	18,943			$	17,886			$	19,737
Well servicing and abandonment segment	$	2,929			$	2,177			$	3,126
E&P segment, and corporate	$	16,014			$	15,709			$	16,611
E&P segment, and corporate ($/boe)	$	6.93			$	6.59			$	7.60
Total mboe		2,310				2,384				2,187

__________
^{(1)   Decrease in the first quarter of 2024 is the result of stock award forfeitures.
(2)   In 2024, non-recurring costs included workforce reduction costs in the first quarter. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter.}