BRY

Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) announced first quarter 2022 results, including a net loss of $57 million or $0.71 per diluted share, Adjusted Net Income(1) of $43 million or $0.51 per diluted share, and Adjusted EBITDA(1) of $96 million. The Board of Directors declared dividends on common stock totaling $0.19 per share.

Quarterly Highlights

• Reported Adjusted EBITDA(1) of $96 million, up 58% from Q4 2021
• Produced 26,700 boe/d, which was 91% oil
• Generated Discretionary Free Cash Flow(1) of $17 million including working capital use of $37 million
• Board declared total dividends of $0.19 per share, a record quarterly dividend for Berry
• FY 2022 cash returns expected at $1.60 - $1.90 per share, based on current plan and commodity strip prices
• Board increased share repurchase authorization to an aggregate $150 million

_______

(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.

“Our first quarter performance positions us for a very good year for our shareholders. We are excited to report that we are on track to deliver top tier returns just as we promised when we announced our new Shareholder Return Model which went into effect for the first quarter of 2022. Based on the current commodity strip prices and current plan, we expect to deliver cash returns that would represent a cash yield in the mid-to-high teens for 2022,” said Trem Smith, Berry Board Chair and CEO.

"We are making good progress on our ESG-focused projects for 2022 and beyond, and continue to actively explore new opportunities to lower our carbon footprint. We are uniquely positioned to capture a portion of the recently announced state and federal funds to plug and abandon California’s thousands of orphan wells with our new C&J Well Services business. Our most recent ESG report (updated periodically) can be found on the ‘Sustainability’ page of our website. We will continue to drive ESG progress and demonstrate our commitment to being a good corporate citizen while providing equitable and affordable energy for all Californians,” continued Smith.

First Quarter 2022 Results

Adjusted EBITDA(1), on a hedged basis, was $96 million in the first quarter 2022. This represented a 58% increase compared to $60 million in the fourth quarter 2021. The increase was largely the result of higher oil prices and lower greenhouse gas costs, partially offset by higher hedged fuel costs and lower production due to property divestitures.

The Company reported daily production of 26,700 boe/d for the first quarter 2022. When adjusted for divestitures and acquisitions, this was essentially flat compared to the fourth quarter 2021. The Company's oil production for the first quarter 2022 was 24,400 bbl/d, or 91% of total production, up from 89% in the prior quarter with California production contributing 22,200 boe/d.

The Company-wide hedged realized oil price for the first quarter 2022 was $76.87 per bbl, a 41% increase from the prior quarter due to higher prices and substantially improved hedge positions. The California average oil price before hedges for the first quarter 2022 was $93.16 per bbl, reflecting approximately 95% of Brent, which was 23% higher than the $75.90 per bbl in the fourth quarter 2021, also approximately 95% of Brent.

Operating expenses, or OpEx, consists of lease operating expenses (“LOE”), third-party expenses and revenues from electricity generation, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases. On a hedged basis, operating expenses increased by 14% or $3.18 per boe to $25.64 for the first quarter 2022, compared to $22.46 for the fourth quarter 2021. During the first quarter 2022, energy operating expenses increased due to higher hedged purchased gas costs as our previous below market hedge book closed in the fourth quarter of 2021 and new hedged prices were more closely aligned to current market. Following the end of the first quarter 2022, the Company entered into new gas purchase hedges that reduce the cost exposure from June to December 2022. As expected, non-energy operating expenses increased slightly on a per boe basis due to increased labor costs, compared to the fourth quarter 2021.

Total general and administrative expenses increased by almost $1 million, or 3%, to approximately $23 million for the first quarter 2022, compared to the fourth quarter 2021, largely due to legal and other professional service expenses related to acquisition and divestment activity. Adjusted General and Administrative Expenses(1), which exclude non-cash stock compensation costs and nonrecurring costs, were approximately 13% higher at $19 million for the first quarter of 2022, due to higher legal and expected inflation of employee costs.

Taxes, other than income taxes were $2.74 per boe for the first quarter compared to $4.65 per boe in the fourth quarter 2021 largely due to decreased greenhouse gas prices.

For the first quarter 2022, capital expenditures were approximately $28 million on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement obligation spending. Approximately 53% of this capital was directed to California oil operations, and 35% to Utah operations. Additionally, the Company spent approximately $5 million for plugging and abandonment activities in the first quarter 2022. The execution of the Company's 2022 development program included drilling 26 new wells in the first quarter 2022, 22 of which were in California and four of which were in Utah, along with 76 well workovers.

The first quarter 2022 operations results for C&J Well Services, Berry's well servicing and abandonment segment acquired in the fourth quarter 2021, included services revenues of $40 million, costs of services of $33 million, and general and administrative expenses of $3 million. These results were negatively impacted by higher than planned labor and fuel costs.

At March 31, 2022, the Company had liquidity of $213 million consisting of $20 million cash on hand and $193 million available for borrowings under its RBL Facility.

“We are excited to announce our first variable dividend under our Shareholder Return Model based on Discretionary Free Cash Flow(1) generated in the first quarter 2022, which will be paid June 15. We currently expect our variable dividend for the second quarter to be substantially better as the first quarter is historically our largest working capital consuming quarter, which affects our Discretionary Free Cash Flow(1). Based on our current oil hedges, the oil market outlook, and our previously disclosed 2022 guidance, we are well positioned to drive strong and sustainable shareholder returns for the next few years,” stated Cary Baetz, Executive Vice President and Chief Financial Officer. “On the energy cost side, we have recently enhanced our natural gas purchases hedge position for 2022 and now have roughly two-thirds of our daily consumption hedged at $4 per mmbtu from June through December 2022. We also gained the remainder of our additional volume allotment on the Kern River gas line on May 1, 2022. The access allows us to be more opportunistic with pricing and provides certainty around volumes during tight supply times.”

Quarterly Dividends

The Company’s Board of Directors declared dividends totaling $0.19 per share on the Company’s outstanding common stock. The variable portion of $0.13 per share was based on first quarter 2022 Discretionary Free Cash Flow(1) in accordance with the Company's Shareholder Return Model, and is payable on June 15, 2022 to shareholders of record at the close of business on May 16, 2022. The fixed dividend for the second quarter of 2022 of $0.06 per share was also declared, and is payable on July 15, 2022 to shareholders of record at the close of business on June 15, 2022.

Subject to approval by the Board on a quarterly basis and depending on a variety of factors, including the Company’s financial condition and results of operations, the Company intends to declare a fixed and variable dividend each quarter.

Increased Share Repurchase Authorization

The Company’s Board of Directors approved an increase of $102 million to the Company’s share repurchase authorization bringing the Company’s total share repurchase authority to $150 million. The Board’s authorization permits the Company to make purchases of its common stock from time to time in the open market and in privately negotiated transactions, subject to market conditions and other factors, up to the aggregate amount authorized by the Board. The Board’s authorization has no expiration date.______

(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.

Earnings Conference Call

The Company will host a conference call May 4, 2022, to discuss these results:

Live Call Date:	Wednesday, May 4, 2022
Live Call Time:	11:00 a.m. Eastern Time (8 a.m. Pacific Time)
Live Call Dial-in:	877-491-5169 from the U.S.
	720-405-2254 from international locations
Live Call Passcode:	5757614

A live audio webcast will be available at bry.com/category/events.

An audio replay will be available shortly after the broadcast:

Replay Dates:	Through Wednesday, May 18, 2022
Replay Dial-in:	855-859-2056 from the U.S.
	404-537-3406 from international locations
Replay Passcode:	5757614

A replay of the audio webcast will also be archived at ir.bry.com/reports-resources.

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. 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 its financial position; liquidity; cash flows (including, but not limited to, Discretionary 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 new shareholder return model and the payment of or improvement of future dividends; future repurchases of stock or debt; capital investments, 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 results of operations, liquidity, cash flows 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 the implementation of additional requirements for 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; uncertainties inherent in estimating natural gas and oil reserves and in projecting future rates of production; 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; the impact and duration of the ongoing COVID-19 pandemic on demand and pricing levels; the ability to effectively deploy our ESG strategy and risks associated with initiating new projects or business in connection therewith; 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, 2021 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 obligation 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
	March 31, 2022				December 31, 2021				March 31, 2021
	($ and shares in thousands, except per share amounts)
Statement of Operations Data:
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	210,351			$	181,377			$	135,265
Services revenue		39,836				35,840				—
Electricity sales		5,419				6,308				10,069
Losses on oil and gas sales derivatives		(161,858	)			(16,378	)			(53,504	)
Marketing revenues		289				834				2,234
Other revenues		45				105				137
Total revenues and other		94,082				208,086				94,201
Expenses and other:
Lease operating expenses		63,124				67,292				62,284
Costs of services		33,472				28,339				—
Electricity generation expenses		4,463				3,660				7,648
Transportation expenses		1,158				1,758				1,576
Marketing expenses		299				825				2,227
General and administrative expenses		22,942				22,357				17,070
Depreciation, depletion and amortization		39,777				38,903				33,840
Taxes, other than income taxes		6,605				11,920				9,557
(Gains) losses on natural gas purchase derivatives		(29,054	)			15,772				(27,730	)
Other operating expenses (income)		3,769				(1,726	)			799
Total expenses and other		146,555				189,100				107,271
Other (expenses) income:
Interest expense		(7,675	)			(7,451	)			(8,485	)
Other, net		(13	)			(91	)			(143	)
Total other (expenses) income		(7,688	)			(7,542	)			(8,628	)
(Loss) income before income taxes		(60,161	)			11,444				(21,698	)
Income tax (benefit) expense		(3,351	)			2,619				(376	)
Net (loss) income	$	(56,810	)		$	8,825			$	(21,322	)
Net (loss) income per share:
Basic	$	(0.71	)		$	0.11			$	(0.27	)
Diluted	$	(0.71	)		$	0.11			$	(0.27	)
Weighted-average shares of common stock outstanding - basic		80,298				80,007				80,115
Weighted-average shares of common stock outstanding - diluted		80,298				84,011				80,115
Adjusted Net Income (Loss)(1)	$	42,871			$	10,204			$	5,627
Weighted-average shares of common stock outstanding - diluted		84,447				84,011				82,276
Diluted earnings per share on Adjusted Net Income (Loss)	$	0.51			$	0.12			$	0.07
	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
	($ and shares in thousands, except per share amounts)
Adjusted EBITDA(1)	$	95,712			$	60,395			$	51,829
Adjusted EBITDA Unhedged(1)	$	127,864			$	93,816			$	50,979
Levered Free Cash Flow(1)	$	55,181			$	20,473			$	16,301
Levered Free Cash Flow Unhedged(1)	$	87,333			$	53,894			$	15,451
Adjusted General and Administrative Expenses(1)	$	19,038			$	16,870			$	13,401
Effective Tax Rate, including discrete items		5	%			23	%			2	%
Cash Flow Data:
Net cash provided by operating activities	$	48,530			$	40,230			$	38,430
Net cash used in investing activities	$	(36,560	)		$	(58,251	)		$	(19,937	)
Net cash used in financing activities	$	(9,293	)		$	(4,857	)		$	(1,688	)

__________

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

	March 31, 2022			December 31, 2021
	($ and shares in thousands)
Balance Sheet Data:
Total current assets	$	166,488		$	147,498
Total property, plant and equipment, net	$	1,323,028		$	1,301,349
Total current liabilities	$	246,556		$	187,149
Long-term debt	$	394,846		$	394,566
Total stockholders' equity	$	630,426		$	629,648
Outstanding common stock shares as of		80,760			80,007

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. Berry acquired C&J Well Services on October 1, 2021 and the results of their operations were included in Berry's consolidated results beginning the fourth quarter 2021.

	Three Months Ended March 31, 2022
	Development & Production				Well Servicing and Abandonment				Corporate/Eliminations				Consolidated Company
	(in thousands)
Revenues - excluding hedges	$	216,104			$	39,836			$	—			$	255,940
Net loss before income taxes	$	(34,291	)		$	(284	)		$	(25,586	)		$	(60,161	)
Adjusted EBITDA	$	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

	Three Months Ended December 31, 2021
	Development & Production				Well Servicing and Abandonment				Corporate/Eliminations				Consolidated Company
	(in thousands)
Revenues - excluding hedges	$	188,624			$	35,840			$	—			$	224,464
Net income (loss) before income taxes	$	35,292			$	1			$	(23,849	)		$	11,444
Adjusted EBITDA	$	67,317			$	4,310			$	(11,232	)		$	60,395
Capital expenditures	$	25,735			$	1,029			$	909			$	27,673
Total assets	$	1,450,157			$	81,093			$	(74,771	)		$	1,456,479

SUMMARY BY AREA

The following table shows a summary by area of our selected historical information and operating information for our development and production operations for the periods indicated.

	California (San Joaquin and Ventura basins)(3)
	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	$	186,252			$	158,317			$	113,177
Operating income(1)	$	60,162			$	17,217			$	18,965
Depreciation, depletion, and amortization (DD&A)	$	35,786			$	35,647			$	32,896
Average daily production (mboe/d)		22.2				22.7				21.9
Production (oil % of total)		100	%			100	%			100	%
Realized sales prices:
Oil (per bbl)	$	93.16			$	75.90			$	57.34
NGLs (per bbl)	$	—			$	—			$	—
Gas (per mcf)	$	—			$	—			$	—
Capital expenditures(2)	$	14,622			$	22,596			$	22,760

	Utah(Uinta basin)												Colorado(Piceance basin)(4)
	Three Months Ended												Three Months Ended
	March 31,2022				December 31,2021				March 31,2021				March 31,2022				December 31,2021				March 31,2021
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	$	23,038			$	19,762			$	15,889			$	1,056			$	3,294			$	6,194
Operating income(1)	$	11,173			$	8,713			$	7,433			$	610			$	3,050			$	5,039
Depreciation, depletion, and amortization (DD&A)	$	803			$	597			$	554			$	9			$	38			$	38
Average daily production (mboe/d)		4.1				4.2				4.0				0.4				1.0				1.2
Production (oil % of total)		53	%			51	%			49	%			—	%			1	%			2	%
Realized sales prices:
Oil (per bbl)	$	83.02			$	66.56			$	52.08			$	89.41			$	84.38			$	25.80
NGLs (per bbl)	$	47.03			$	47.45			$	26.81			$	—			$	—			$	—
Gas (per mcf)	$	5.93			$	5.63			$	6.65			$	5.12			$	5.54			$	9.83
Capital expenditures(2)	$	9,752			$	1,007			$	392			$	—			$	—			$	1

__________

(1)     Operating income (loss) includes oil, natural gas and NGL sales, marketing revenues, other revenues, and scheduled oil derivative settlements, offset by operating expenses (as defined elsewhere), general and administrative expenses, DD&A, impairment of oil and gas properties, and taxes, other than income taxes.(2)     Excludes corporate capital expenditures.(3)     Our Placerita properties, in the Ventura basin, were divested in October 2021.(4)     Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.

COMMODITY PRICING

	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
Weighted-average realized sales prices:
Oil without hedges ($/bbl)	$	92.25			$	75.11			$	56.89
Effects of scheduled derivative settlements ($/bbl)	$	(15.38	)		$	(20.50	)		$	(12.08	)
Oil with hedges ($/bbl)	$	76.87			$	54.61			$	44.81
Natural gas ($/mcf)	$	5.77			$	5.60			$	7.96
NGLs ($/bbl)	$	47.03			$	47.45			$	26.81
Average Benchmark prices:
Oil (bbl) – Brent	$	97.90			$	79.66			$	61.32
Oil (bbl) – WTI	$	94.54			$	76.89			$	57.82
Natural gas (mmbtu) – Kern, Delivered(1)	$	4.83			$	5.65			$	7.99
Natural gas (mmbtu) – Henry Hub(2)	$	4.67			$	4.75			$	3.50

__________

(1)        Kern, Delivered Index is the relevant index used for gas purchases in California.(2)        Henry Hub is the relevant index used for gas sales in the Rockies.

CURRENT HEDGING SUMMARY

As of April 28, 2022, we had the following hedges for our crude oil production and gas purchases.

	Q2 2022			Q3 2022			Q4 2022			FY 2023			FY 2024
Brent
Swaps
Hedged volume (bbls)		1,360,500			1,380,000			1,288,000			3,433,528			1,917,000
Weighted-average price ($/bbl)	$	77.10		$	77.73		$	76.07		$	73.06		$	75.52
Put Spreads
Hedged volume (bbls)		364,000			368,000			368,000			2,190,000			1,281,000
Weighted-average price ($/bbl)	$50/$40			$50/$40			$50/$40			$50/$40			$50/$40
Producer Collars
Hedged volume (bbls)		—			—			—			1,460,000			1,098,000
Weighted-average price ($/bbl)	$	—		$	—		$	—		$106/$40			$105/$40
Henry Hub
Consumer Collars
Hedged volume (mmbtu)		3,030,000			3,680,000			3,680,000			5,430,000			—
Weighted-average price ($/mmbtu)	$4.00/$2.75			$4.00/$2.75			$4.00/$2.75			$4.00/$2.75			$	—

OPERATING EXPENSES

	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
	($ in thousands except per boe amounts)
Lease operating expenses	$	63,124			$	67,292			$	62,284
Electricity generation expenses		4,463				3,660				7,648
Electricity sales(1)		(5,419	)			(6,308	)			(10,069	)
Transportation expenses		1,158				1,758				1,576
Transportation sales(1)		(45	)			(105	)			(137	)
Marketing expenses		299				825				2,227
Marketing revenues(1)		(289	)			(834	)			(2,234	)
Derivative settlements (received) paid for gas purchases(1)		(1,653	)			(8,650	)			(26,239	)
Total operating expenses(1)	$	61,638			$	57,638			$	35,056
Lease operating expenses ($/boe)	$	26.25			$	26.23			$	25.58
Electricity generation expenses ($/boe)		1.86				1.43				3.14
Electricity sales ($/boe)		(2.25	)			(2.46	)			(4.13	)
Transportation expenses ($/boe)		0.48				0.69				0.65
Transportation sales ($/boe)		(0.02	)			(0.05	)			(0.06	)
Marketing expenses ($/boe)		0.13				0.32				0.92
Marketing revenues ($/boe)		(0.12	)			(0.33	)			(0.92	)
Derivative settlements (received) paid for gas purchases ($/boe)		(0.69	)			(3.37	)			(10.78	)
Total operating expenses ($/boe)	$	25.64			$	22.46			$	14.40
Total unhedged operating expenses ($/boe)(2)	$	26.33			$	25.83			$	25.18
Total non-energy operating expenses(3)	$	13.58			$	13.41			$	12.74
Total energy operating expenses(4)	$	12.06			$	9.05			$	1.66
Total mboe		2,406				2,566				2,435

__________

(1)     We report electricity, transportation and marketing sales separately in our financial statements as revenues in accordance with GAAP. However, these revenues are viewed and used internally in calculating operating expenses which is used to track and analyze the economics of development projects and the efficiency of our hydrocarbon recovery. We purchase third-party gas to generate electricity through our cogeneration facilities to be used in our field operations activities and view the added benefit of any excess electricity sold externally as a cost reduction/benefit to generating steam for our thermal recovery operations. Marketing revenues and expenses mainly relate to natural gas purchased from third parties that moves through our gathering and processing systems and then is sold to third parties. Transportation sales relate to water and other liquids that we transport on our systems on behalf of third parties and have not been significant to date. Operating expenses also include the effect of derivative settlements (received or paid) for gas purchases.(2)      Total unhedged operating expenses equals total operating expenses, excluding the derivative settlements paid (received) for gas purchases.(3)      Total non-energy operating expenses equals total operating expenses, excluding fuel, electricity sales and gas purchase derivative settlement (gains) losses.(4)      Total energy operating expenses equals fuel and gas purchase derivative settlement (gains) losses less electricity sales.

PRODUCTION STATISTICS

	Three Months Ended
	March 31, 2022		December 31, 2021		March 31, 2021
Net Oil, Natural Gas and NGLs Production Per Day(1):
Oil (mbbl/d)
California(2)	22.2		22.7		21.9
Utah	2.2		2.1		2.0
Colorado(3)	—		—		—
Total oil	24.4		24.8		23.9
Natural gas (mmcf/d)
California(2)	—		—		—
Utah	9.2		10.0		10.0
Colorado(3)	2.3		6.4		6.9
Total natural gas	11.5		16.4		16.9
NGLs (mbbl/d)
California(2)	—		—		—
Utah	0.4		0.4		0.3
Colorado(3)	—		—		—
Total NGLs	0.4		0.4		0.3
Total Production (mboe/d)(4)	26.7		27.9		27.1

__________

(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)   Our Placerita properties, in the Ventura basin, were divested in October 2021.(3)   Our properties in Colorado were in the Piceance basin, all of which were all divested in January 2022.(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, 2022, the average prices of Brent oil and Henry Hub natural gas were $97.90 per bbl and $4.67 per mmbtu respectively.

CAPITAL EXPENDITURES (ACCRUAL BASIS)

	Three Months Ended
	March 31, 2022(2)			December 31, 2021(2)			March 31, 2021
	(in thousands)
Capital expenditures (accrual basis)(1)	$	27,620		$	27,673		$	23,569

__________

(1)   Capital expenditures on an accrual basis include capitalized overhead and interest and excludes acquisitions and asset retirement spending.(2)   Capital expenditures in the quarter ended March 31, 2022 and December 31, 2021 included approximately $1 million each period for C&J Well Services which was acquired on October 1, 2021.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

Adjusted Net Income (Loss) is not a measure of net income (loss), Levered Free Cash Flow, Levered Free Cash Flow Unhedged and Discretionary Free Cash Flow are not measures of cash flow, and Adjusted EBITDA and Adjusted EBITDA Unhedged are not measures of either, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged, Adjusted Net Income (Loss) and Discretionary Free Cash Flow 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 Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual and infrequent items, and the income tax expense or benefit of these adjustments using our effective tax rate. 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. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends. We define Discretionary Free Cash Flow as cash flow from operations less regular fixed dividends and the capital needed to hold production flat.

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. 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. 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. 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. Levered Free Cash Flow is used by management as a primary metric to plan capital allocation to sustain production levels and for internal growth opportunities, as well as hedging needs. It also serves as a measure for assessing our financial performance and our ability to generate excess cash from operations to service debt and pay dividends. Management believes Discretionary Free Cash Flow provides useful information in assessing our financial condition, and is the primary metric to determine the quarterly variable dividend. We expect to allocate 60% of Discretionary Free Cash Flow predominantly in the form of cash variable dividends, as well as opportunistic debt repurchases. The remaining 40% will be used for opportunistic growth, including from our extensive inventory of drilling opportunities, advancing our short- and long-term sustainability initiatives, share repurchases, and/or capital retention. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and infrequent costs.

Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. 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 exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature.

While Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged, Adjusted General and Administrative Expenses and Discretionary Free Cash Flow are non-GAAP measures, the amounts included in the calculations of Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged, Adjusted General and Administrative Expenses and Discretionary Free Cash Flow 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. Our computations of Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged, Adjusted General and Administrative Expenses and Discretionary Free Cash Flow may not be comparable to other similarly titled measures used by other companies. Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged, Adjusted General and Administrative Expenses and Discretionary Free Cash Flow should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

ADJUSTED NET INCOME (LOSS)

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted Net Income (Loss).

	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
	($ thousands, except per share amounts)
Net (loss) income	$	(56,810	)		$	8,825			$	(21,322	)
Add: discrete income tax items		293				581				—
Add (Subtract):
Losses on derivatives		132,804				32,150				25,774
Net cash (paid) received for scheduled derivative settlements		(32,152	)			(33,421	)			850
Other operating expenses (income)		3,769				(1,726	)			799
Non-recurring costs		198				2,030				—
Total additions, net		104,619				(967	)			27,423
Income tax (expense) benefit of adjustments at effective tax rate(1)		(5,231	)			1,765				(474	)
Adjusted Net Income (Loss)	$	42,871			$	10,204			$	5,627
Basic EPS on Adjusted Net Income (Loss)	$	0.53			$	0.13			$	0.07
Diluted EPS on Adjusted Net Income (Loss)	$	0.51			$	0.12			$	0.07
Weighted average shares of common stock outstanding - basic		80,298				80,007				80,115
Weighted average shares of common stock outstanding - diluted		84,447				84,011				82,276

__________

(1)   Excludes discrete income tax items from the total additions (subtractions), net line item and the tax effect the discrete income tax items have on the current rate.

ADJUSTED EBITDA AND ADJUSTED EBITDA UNHEDGED

The following tables present a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA Unhedged.

	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
	($ thousands)
Net (loss) income	$	(56,810	)		$	8,825			$	(21,322	)
Add (Subtract):
Interest expense		7,675				7,451				8,485
Income tax (benefit) expense		(3,351	)			2,619				(376	)
Depreciation, depletion and amortization		39,777				38,903				33,840
Losses on derivatives		132,804				32,150				25,774
Net cash (paid) received for scheduled derivative settlements		(32,152	)			(33,421	)			850
Other operating expense (income)		3,769				(1,726	)			799
Stock compensation expense		3,802				3,564				3,779
Non-recurring costs(1)		198				2,030				—
Adjusted EBITDA	$	95,712			$	60,395			$	51,829
Net cash paid (received) for scheduled derivative settlements		32,152				33,421				(850	)
Adjusted EBITDA Unhedged	$	127,864			$	93,816			$	50,979
Net cash provided by operating activities	$	48,530			$	40,230			$	38,430
Add (Subtract):
Cash interest payments		14,539				97				14,637
Cash income tax payments		—				405				—
Non-recurring costs		198				2,030				—
Other changes in operating assets and liabilities		32,445				17,633				(1,238	)
Adjusted EBITDA	$	95,712			$	60,395			$	51,829
Net cash paid (received) for scheduled derivative settlements		32,152				33,421				(850	)
Adjusted EBITDA Unhedged	$	127,864			$	93,816			$	50,979

__________

(1)   Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity.

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, 2022
	Development & Production				Well Servicing and Abandonment				Corporate/Eliminations				Consolidated Company
	(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		—				198				—				198
Adjusted EBITDA	$	105,649			$	3,300			$	(13,237	)		$	95,712

	Three Months Ended December 31, 2021
	Development & Production				Well Servicing and Abandonment			Corporate/Eliminations				Consolidated Company
	(in thousands)
Adjusted EBITDA reconciliation to net income (loss):
Net income (loss)	$	35,290			$	1		$	(26,466	)		$	8,825
Add (Subtract):
Interest expense		—				—			7,451				7,451
Income tax expense		—				—			2,619				2,619
Depreciation, depletion, and amortization		34,774				2,974			1,155				38,903
Losses on derivatives		32,150				—			—				32,150
Net cash paid for scheduled derivative settlements		(33,421	)			—			—				(33,421	)
Other operating income		(1,726	)			—			—				(1,726	)
Stock compensation expense		250				—			3,314				3,564
Non-recurring costs		—				1,335			695				2,030
Adjusted EBITDA	$	67,317			$	4,310		$	(11,232	)		$	60,395

LEVERED FREE CASH FLOW AND LEVERED FREE CASH FLOW UNHEDGED

The following table presents a reconciliation of Adjusted EBITDA to the non–GAAP measures of Levered Free Cash Flow and Levered Free Cash Flow Unhedged. The reconciliation of Adjusted EBITDA is presented above.

	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
	($ thousands)
Adjusted EBITDA	$	95,712			$	60,395			$	51,829
Subtract:
Capital expenditures - accrual basis(1)		(27,620	)			(27,673	)			(23,569	)
Interest expense		(7,675	)			(7,451	)			(8,485	)
Cash dividends declared		(5,236	)			(4,798	)			(3,474	)
Levered Free Cash Flow	$	55,181			$	20,473			$	16,301
Net cash paid (received) for scheduled derivative settlements		32,152				33,421				(850	)
Levered Free Cash Flow Unhedged	$	87,333			$	53,894			$	15,451

__________

(1)   Capital expenditures on an accrual basis includes capitalized overhead and interest and excludes acquisitions. Also excluded is asset retirement spending of $5 million, $7 million, $3 million for the quarters ended March 31, 2022, December 31, 2021 and March 31, 2021, respectively.

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.

	Three Months Ended
	March 31, 2022				December 31, 2021				March 31, 2021
	($ in thousands except per mboe amounts)
General and administrative expenses	$	22,942			$	22,357			$	17,070
Subtract:
Non-cash stock compensation expense (G&A portion)		(3,706	)			(3,457	)			(3,669	)
Non-recurring costs		(198	)			(2,030	)			—
Adjusted General and Administrative Expenses	$	19,038			$	16,870			$	13,401
Well servicing and abandonment segment	$	3,070			$	3,193			$	—
Development and production segment, and corporate	$	15,968			$	13,677			$	13,401
Development and production segment, and corporate ($/boe)	$	6.64			$	5.33			$	5.50
Total mboe		2,406				2,566				2,435

DISCRETIONARY FREE CASH FLOW

The following table presents a reconciliation of the non-GAAP financial measure Discretionary Free Cash Flow to the GAAP financial measure of operating cash flow for each of the periods indicated.

	Three Months Ended
	March 31, 2022
	(in thousands)
Discretionary Free Cash Flow:
Operating cash flow(1)	$	48,530
Subtract:
Maintenance capital(2)(3)		(26,437	)
Fixed dividends(4)		(5,236	)
Discretionary Free Cash Flow	$	16,857

__________(1)        Combined D&P business and well servicing and abandonment.(2)        D&P business only.(3)        Maintenance capital is the capital required to keep annual production flat, calculated as the capital expenditures for the D&P business during the period presented.(4)        Represents fixed dividends declared as noted on the consolidated statement of stockholders’ equity as “Dividends declared on common stock.”

Contact

Contact: Berry Corporation (bry)
Todd Crabtree - Director, Investor Relations
(661) 616-3811
ir@bry.com