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Berry Corporation (bry) Reports Second Quarter 2021 Results and Announces Quarterly Dividend Increase

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DALLAS, Aug. 03, 2021 (GLOBE NEWSWIRE) -- Berry Corporation (bry) (NASDAQ: BRY) (“Berry”, “bry” or the “Company”) announced that it will increase its quarterly common stock dividend to $0.06 per share beginning with the dividend declared by the Board of Directors for the third quarter of 2021.

“Berry’s solid second quarter results were consistent with our expectations and annual guidance. Since going public in 2018, Berry has remained committed to its disciplined financial principles and delivering long-term value for stockholders. In recognition of our strong financial position and continued confidence in Berry’s future, the Board has voted to increase the quarterly dividend by 50%. In our three years as a public company, Berry has returned capital amounting to 115% of the IPO proceeds, or $127 million, including $77 million in the form of dividends, highlighting Berry’s commitment to return capital to its shareholders,” said Trem Smith, Berry board Chairman and CEO.

The Company also reported a net loss of $13 million or $0.16 per diluted share and Adjusted Net Loss(1) of $6 million or $0.08 per diluted share for the second quarter of 2021.

Quarterly Highlights

  • Generated Adjusted EBITDA(1) of $41 million

  • Increased sequential total production 1% to 27,300 boe/d

  • Drilled 58 wells, of which 21 will come on production in Q3

  • Increased quarterly dividend 50% to $0.06 per share

  • Reaffirming annual guidance

_______

(1) Please see “Non-GAAP Financial Measures and Reconciliations” later in this press release for a reconciliation and more information on these Non-GAAP measures.

“Our business model is simple, durable and resilient and able to withstand pandemics, market collapses and political headwinds. We have proven it generates positive cash flow in all but the most extreme market environments. We live within Levered Free Cash Flow (1), which we define to include our expenses, the capital needed to keep production flat, interest and dividends. Our confidence in our ability to generate excess Levered Free Cash Flow is once again evident by the dividend increase announced today. We believe the best current use of capital is to keep production flat, enabling us to return capital and increase shareholder returns," continued Smith. “We continue to execute successfully on our two-year plan that was established in early 2020 following the Covid-19 outbreak and oil market disruption. As promised, we increased production in the second quarter and remain in a good position to meet our 2021 production goals to keep production flat year on year. We maintained our non-energy cost levels, despite increasing commodity prices, while maintaining our high safety and environmental standards. As has been the case for the last several years, no California governmental or regulatory constraints have had a meaningful impact on our operations and we are continuing to receive permits and continuing to drill. The demand for oil and gas is strong in California and is expected to remain strong for the foreseeable future. I look forward to what’s ahead for Berry.”

Second Quarter 2021 Results

Adjusted EBITDA(1), on a hedged basis, was $41 million in the second quarter 2021. This compared to $52 million in the first quarter 2021, which had included notably higher sales from acutely higher gas and electricity prices as a result of the natural gas shortage related to Winter Storm Uri. In the second quarter 2021, the impact of higher oil prices and increased production resulted in favorable impacts on revenue. Energy-related operating expenses were higher, as well as taxes, other than income taxes mainly due to higher Greenhouse Gas (GHG) prices. Adjusted general and administrative expense was slightly lower than the first quarter.

The Company grew average daily production 1% to 27,300 boe/d for the second quarter of 2021 compared to the first quarter of 2021, as a result of its continuing 2021 development program, consisting of 58 new wells in the quarter, including eight wells in Utah. The Company held oil production for the second quarter 2021 essentially flat at 24,000 bbl/d. Production in Utah increased 10%, while the Company's California production of 21,700 boe/d for the second quarter of 2021 decreased 1% from the first quarter 2021. California production has been negatively impacted by a loss of our production from one of Berry's locations where lower water withdrawals by an offset operator along with a reduction in our steam injection volumes triggered a drop in production. The issue has reduced production by approximately 600 bbl/d and this will impact all of 2021. However, the steam is expected to recharge and be back to historical production levels by early next year.

The Company-wide hedged realized oil price for the second quarter 2021 was $46.39 per bbl, a 4% increase from the first quarter. The California average oil price before hedges for the second quarter was $65.37 per bbl, 95% of Brent, which was 14% higher than the $57.34 per bbl in the first quarter 2021, which was 94% of Brent.

OpEx consists of lease operating expenses (“LOE”), third-party revenues and expenses from electricity generation, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases, and excludes taxes other than income taxes.

On a hedged basis, operating expenses increased by 20% or $2.91 per boe to $17.31 for the second quarter 2021, compared to $14.40 for the first quarter 2021, entirely due to the impact of energy related expenses on a hedged basis in the second quarter 2021 and the acutely higher electricity sales prices in the first quarter. During the second quarter the Company maintained its cost savings efforts with non-energy operating expenses down slightly on a per boe basis, compared to the first quarter of 2021, despite higher commodity prices.

General and administrative expenses decreased by $1 million, or 6%, to approximately $16 million for the second quarter 2021, compared to the first quarter 2021, largely due to lower non-cash stock compensation expenses. Adjusted General and Administrative Expenses(1), which exclude non-cash stock compensation costs and nonrecurring costs, decreased 1% to $13 million and 3% to $5.35 per boe for the second quarter 2021.

Taxes, other than income taxes were $4.67 per boe for the second quarter compared to $3.93 per boe in the first quarter 2021. GHG costs were higher in the second quarter of 2021 due to higher mark-to-market valuations.

For the second quarter 2021, capital expenditures were approximately $43 million on an accrual basis excluding acquisitions and asset retirement obligation spending. Berry drilled 58 wells in the second quarter, of which 21 will come on production in the third quarter 2021. Capital for the second quarter was higher as more wells were drilled, including eight wells drilled in Utah, which require more capital than typical California wells, as well as increased California workover, equipping and facilities work. Approximately 72% of this capital was directed to California oil operations, and 21% to Utah operations. Additionally, Berry also spent approximately $3 million for plugging and abandonment activities in the second quarter 2021.

At June 30, 2021, the Company had liquidity of $268 million consisting of $75 million cash in the bank and $193 million available for borrowings under its RBL Facility which had no borrowings and $7 million of letters of credit outstanding. The RBL Facility has a $200 million borrowing base with an elected commitment of $200 million.

“We continued to deliver on our plan and we are seeing better-than-expected results from our capital spending. However, this capital efficiency is being masked by the temporary production loss in one of our fields resulting from a reduction in steam intensity late last year,” stated Cary Baetz, chief financial officer, EVP and director. “We will continue to see a healthy spend in the third quarter that decreases in the fourth quarter, which aligns with our annual guidance. Our oil hedge position will improve in the second half of this year and into next year. While our need for natural gas hedging is being reduced, we are now starting to gain some access to the Kern County pipeline which will allow us to use some of our Rockies gas production in our steam operations. Lastly, we continue to focus on the return of capital and are happy to announce an increase in our quarterly dividend to $0.06 per share.”

Quarterly Dividend

The Company’s Board of Directors declared a regular dividend for the third quarter of 2021 at a rate of $0.06 per share on the Company’s outstanding common stock, payable on October 15, 2021 to shareholders of record at the close of business on September 15, 2021.

Subject to approval by the Board and depending on a variety of factors, including the Company’s financial condition and results of operations, the Company intends to pay a similar dividend in future quarters.
_______

(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 August 4, 2021, to discuss these results:

Live Call Date:

Wednesday, August 4, 2021

Live Call Time:

9:00 a.m. Eastern Time (6 a.m. Pacific Time)

Live Call Dial-in:

877-491-5169 from the U.S.

720-405-2254 from international locations

Live Call Passcode:

5973754

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, August 18, 2021

Replay Dial-in:

855-859-2056 from the U.S.

404-537-3406 from international locations

Replay Passcode:

5973754

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

About Berry Corporation (bry)

Bry is a publicly traded (NASDAQ: BRY) western United States independent upstream energy company with a focus on the conventional, long-lived oil reserves in the San Joaquin basin of 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 financial position; liquidity; cash flows; anticipated financial and operating, results; capital program and development and production plans; operations and business strategy; potential acquisition opportunities; reserves; hedging activities; capital expenditures, return of capital; payment, 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.

Bry 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 bry’s control. These risks include, but are not limited to, commodity price volatility; legislative and regulatory processes and actions that may prevent, delay or otherwise restrict our ability to drill and develop our assets, including regulatory approval and permitting requirements; legislative and regulatory initiatives in California or our other areas of operation addressing climate change or other environmental concerns; drilling, production and other operating risks; investment in and development of competing or alternative energy sources; 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; 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, 2020.

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

June 30, 2021

March 31, 2021

June 30, 2020

($ and shares in thousands, except per share amounts)

Statement of Operations Data:

Revenues and other:

Oil, natural gas and natural gas liquids sales

$

147,775

$

135,265

$

70,515

Electricity sales

6,888

10,069

4,884

Losses on oil and gas sales derivatives

(55,653

)

(53,504

)

(42,267

)

Marketing revenues

121

2,234

292

Other revenues

118

137

29

Total revenues and other

99,249

94,201

33,453

Expenses and other:

Lease operating expenses

45,543

62,284

40,733

Electricity generation expenses

4,712

7,648

3,022

Transportation expenses

1,757

1,576

1,789

Marketing expenses

44

2,227

280

General and administrative expenses

16,065

17,070

18,777

Depreciation, depletion and amortization

35,850

33,840

37,512

Taxes, other than income taxes

11,603

9,557

10,449

(Gains) losses on natural gas purchase derivatives

(11,639

)

(27,730

)

925

Other operating expenses (income)

42

799

(1,192

)

Total expenses and other

103,977

107,271

112,295

Other (expenses) income:

Interest expense

(8,217

)

(8,485

)

(8,676

)

Other, net

(8

)

(143

)

(6

)

Total other (expenses) income

(8,225

)

(8,628

)

(8,682

)

Loss before income taxes

(12,953

)

(21,698

)

(87,524

)

Income tax benefit

(72

)

(376

)

(22,623

)

Net loss

$

(12,881

)

$

(21,322

)

$

(64,901

)

Net loss per share:

Basic

$

(0.16

)

$

(0.27

)

$

(0.81

)

Diluted

$

(0.16

)

$

(0.27

)

$

(0.81

)

Weighted-average shares of common stock outstanding - basic

80,471

80,115

79,795

Weighted-average shares of common stock outstanding - diluted

80,471

80,115

79,795

Adjusted Net (Loss) Income(1)

$

(6,293

)

$

5,627

$

4,609

Weighted-average shares of common stock outstanding - diluted

80,471

82,276

80,640

Diluted earnings per share on Adjusted Net (Loss) Income

$

(0.08

)

$

0.07

$

0.06

Three Months Ended

June 30, 2021

March 31, 2021

June 30, 2020

($ and shares in thousands, except per share amounts)

Adjusted EBITDA(1)

$

40,599

$

51,829

$

57,433

Adjusted EBITDA Unhedged(1)

$

78,030

$

50,979

$

5,559

Levered Free Cash Flow(1)

$

(14,298

)

$

16,301

$

32,057

Levered Free Cash Flow Unhedged(1)

$

23,133

$

15,451

$

(19,817

)

Adjusted General and Administrative Expenses(1)

$

13,302

$

13,401

$

14,081

Effective Tax Rate, including discrete items

1

%

2

%

26

%

Cash Flow Data:

Net cash provided by operating activities

$

21,429

$

38,430

$

41,939

Net cash used in investing activities

$

(40,575

)

$

(19,937

)

$

(22,480

)

Net cash used in financing activities

$

(3,298

)

$

(1,688

)

$

(19,460

)

__________

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

June 30, 2021

December 31, 2020

($ and shares in thousands)

Balance Sheet Data:

Total current assets

$

177,063

$

154,491

Total property, plant and equipment, net

$

1,262,417

$

1,258,084

Total current liabilities

$

222,062

$

175,306

Long-term debt

$

394,009

$

393,480

Total stockholders' equity

$

678,658

$

714,036

Outstanding common stock shares as of

80,471

79,929

SUMMARY BY AREA

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

California
(San Joaquin and Ventura basins)

Three Months Ended

June 30, 2021

March 31, 2021

June 30, 2020

($ in thousands, except prices)

Oil, natural gas and natural gas liquids sales

$

129,128

$

113,177

$

62,943

Operating income(1)

$

11,413

$

18,965

$

32,469

Depreciation, depletion, and amortization (DD&A)

$

35,174

$

32,896

$

36,518

Average daily production (mboe/d)

21.7

21.9

23.4

Production (oil % of total)

100

%

100

%

100

%

Realized sales prices:

Oil (per bbl)

$

65.37

$

57.34

$

29.53

NGLs (per bbl)

$

$

$

Gas (per mcf)

$

$

$

Capital expenditures(2)

$

31,303

$

22,760

$

16,446


Utah
(Uinta basin)

Colorado
(Piceance basin)

Three Months Ended

Three Months Ended

June 30,
2021

March 31,
2021

June 30,
2020

June 30,
2021

March 31,
2021

June 30,
2020

($ in thousands, except prices)

Oil, natural gas and natural gas liquids sales

$

16,199

$

15,889

$

6,439

$

2,438

$

6,194

$

1,132

Operating income (loss)(1)

$

6,736

$

7,433

$

(584

)

$

1,121

$

5,039

$

6

Depreciation, depletion, and amortization (DD&A)

$

630

$

554

$

905

$

38

$

38

$

43

Average daily production (mboe/d)

4.4

4.0

4.4

1.2

1.2

1.3

Production (oil % of total)

52

%

49

%

49

%

2

%

2

%

2

%

Realized sales prices:

Oil (per bbl)

$

58.55

$

52.08

$

23.11

$

56.05

$

25.80

$

20.67

NGLs (per bbl)

$

29.61

$

26.81

$

5.82

$

$

$

Gas (per mcf)

$

3.30

$

6.65

$

1.68

$

3.53

$

9.83

$

1.53

Capital expenditures(2)

$

9,162

$

392

$

81

$

$

1

$

145

__________

(1) Operating income (loss) includes oil, natural gas and NGL sales, 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.

COMMODITY PRICING

Three Months Ended

June 30, 2021

March 31, 2021

June 30, 2020

Weighted-average realized sales prices:

Oil without hedges ($/bbl)

$

64.72

$

56.89

$

28.98

Effects of scheduled derivative settlements ($/bbl)

$

(18.33

)

$

(12.08

)

$

25.42

Oil with hedges ($/bbl)

$

46.39

$

44.81

$

54.40

Natural gas ($/mcf)

$

3.39

$

7.96

$

1.62

NGLs ($/bbl)

$

29.61

$

26.81

$

5.82

Average Benchmark prices:

Oil (bbl) – Brent

$

69.08

$

61.32

$

33.39

Oil (bbl) – WTI

$

66.03

$

57.82

$

28.42

Natural gas (mmbtu) – Kern, Delivered(1)

$

3.23

$

7.99

$

1.45

Natural gas (mmbtu) – Henry Hub(2)

$

2.95

$

3.50

$

1.70

__________

(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 June 30, 2021, we had the following crude oil production and gas purchases hedges.

Q3 2021

Q4 2021

FY 2022

Fixed Price Oil Swaps (Brent):

Hedged volume (mbbls)

1,318

1,318

1,095

Weighted-average price ($/bbl)

$

48.66

$

48.66

$

60.00

Fixed Price Gas Purchase Swaps (Kern, Delivered):

Hedged volume (mmbtu)

4,830,000

2,085,000

Weighted-average price ($/mmbtu)

$

2.83

$

2.95

$

We recently entered into new pipeline capacity agreements for the shipment of natural gas from the Rockies to our assets in California that will reduce our exposure to fuel gas purchase price fluctuations. These capacity agreements are for approximately 10,000 mmbtu/d beginning October 2021 through October 2036 and approximately 5,500 mmbtu/d beginning November 2021 through December 2024 for a total commitment of $32 million.

OPERATING EXPENSES

Three Months Ended

June 30, 2021

March 31, 2021

June 30, 2020

($ in thousands except per boe amounts)

Lease operating expenses

$

45,543

$

62,284

$

40,733

Electricity generation expenses

4,712

7,648

3,022

Electricity sales(1)

(6,888

)

(10,069

)

(4,884

)

Transportation expenses

1,757

1,576

1,789

Transportation sales(1)

(118

)

(137

)

(29

)

Marketing expenses

44

2,227

280

Marketing revenues(1)

(121

)

(2,234

)

(292

)

Derivative settlements (received) paid for gas purchases(1)

(1,913

)

(26,239

)

7,362

Total operating expenses(1)

$

43,016

$

35,056

$

47,981

Lease operating expenses ($/boe)

$

18.33

$

25.58

$

15.37

Electricity generation expenses ($/boe)

1.90

3.14

1.14

Electricity sales ($/boe)

(2.77

)

(4.13

)

(1.84

)

Transportation expenses ($/boe)

0.70

0.65

0.67

Transportation sales ($/boe)

(0.05

)

(0.06

)

(0.01

)

Marketing expenses ($/boe)

0.02

0.92

0.11

Marketing revenues ($/boe)

(0.05

)

(0.92

)

(0.11

)

Derivative settlements (received) paid for gas purchases ($/boe)

(0.77

)

(10.78

)

2.78

Total operating expenses ($/boe)

$

17.31

$

14.40

$

18.11

Total unhedged operating expenses ($/boe)(2)

$

18.08

$

25.18

$

15.33

Total non-energy operating expenses(3)

$

12.71

$

12.74

$

12.81

Total energy operating expenses(4)

$

4.60

$

1.66

$

5.30

Total mboe

2,485

2,435

2,650

__________

(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

June 30, 2021

March 31, 2021

June 30, 2020

Net Oil, Natural Gas and NGLs Production Per Day(1):

Oil (mbbl/d)

California

21.7

21.9

23.4

Utah

2.3

2.0

2.2

Colorado

Total oil

24.0

23.9

25.6

Natural gas (mmcf/d)

California

Utah

10.3

10.0

11.5

Colorado

7.2

6.9

7.7

Total natural gas

17.5

16.9

19.2

NGLs (mbbl/d)

California

Utah

0.4

0.3

0.3

Colorado

Total NGLs

0.4

0.3

0.3

Total Production (mboe/d)(2)

27.3

27.1

29.1

__________

(1) Production represents volumes sold during the period.

(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, 2021, the average prices of Brent oil and Henry Hub natural gas were $69.08 per bbl and $2.95 per mmbtu respectively.

CAPITAL EXPENDITURES (ACCRUAL BASIS)

Three Months Ended

June 30, 2021

March 31, 2021

June 30, 2020

(in thousands)

Capital expenditures (accrual basis)(1)

$

43,461

$

23,569

$

16,700

__________

(1) Excludes acquisitions and asset retirement spending.

NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS

Adjusted Net Income (Loss) is not a measure of net income (loss), Levered Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either, in all cases, as determined by GAAP. Adjusted Net Income (Loss), Adjusted EBITDA, Levered Free Cash Flow 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 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 other unusual and infrequent items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends. 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 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. 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 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 and Adjusted General and Administrative Expenses 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 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. Our computations of Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged and Adjusted General and Administrative Expenses 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 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 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

June 30, 2021

March 31, 2021

June 30, 2020

($ thousands, except per share amounts)

Net loss

$

(12,881

)

$

(21,322

)

$

(64,901

)

Add (Subtract):

Losses on derivatives

44,014

25,774

43,192

Net cash (paid) received for scheduled derivative settlements

(37,431

)

850

51,874

Other operating expenses (income)

42

799

(1,192

)

Non-recurring costs

316

Total additions, net

6,625

27,423

94,190

Income tax expense of adjustments at effective tax rate

(37

)

(474

)

(24,680

)

Adjusted Net (Loss) Income

$

(6,293

)

$

5,627

$

4,609

Basic EPS on Adjusted Net (Loss) Income

$

(0.08

)

$

0.07

$

0.06

Diluted EPS on Adjusted Net (Loss) Income

$

(0.08

)

$

0.07

$

0.06

Weighted average shares of common stock outstanding - basic

80,471

80,115

79,795

Weighted average shares of common stock outstanding - diluted

80,471

82,276

80,640

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

June 30, 2021

March 31, 2021

June 30, 2020

($ thousands)

Net loss

$

(12,881

)

$

(21,322

)

$

(64,901

)

Add (Subtract):

Interest expense

8,217

8,485

8,676

Income tax benefit

(72

)

(376

)

(22,623

)

Depreciation, depletion and amortization

35,850

33,840

37,512

Losses on derivatives

44,014

25,774

43,192

Net cash (paid) received for scheduled derivative settlements

(37,431

)

850

51,874

Other operating expense (income)

42

799

(1,192

)

Stock compensation expense

2,860

3,779

4,579

Non-recurring costs

316

Adjusted EBITDA

$

40,599

$

51,829

$

57,433

Net cash paid (received) for scheduled derivative settlements

37,431

(850

)

(51,874

)

Adjusted EBITDA Unhedged

$

78,030

$

50,979

$

5,559

Net cash provided by operating activities

$

21,429

$

38,430

$

41,939

Add (Subtract):

Cash interest payments

288

14,637

648

Non-recurring costs

316

Other changes in operating assets and liabilities

18,882

(1,238

)

14,530

Adjusted EBITDA

$

40,599

$

51,829

$

57,433

Net cash paid (received) for scheduled derivative settlements

37,431

(850

)

(51,874

)

Adjusted EBITDA Unhedged

$

78,030

$

50,979

$

5,559

LEVERED FREE CASH FLOW

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

Three Months Ended

June 30, 2021

March 31, 2021

June 30, 2020

($ thousands)

Adjusted EBITDA

$

40,599

$

51,829

$

57,433

Subtract:

Capital expenditures - accrual basis(1)

(43,461

)

(23,569

)

(16,700

)

Interest expense

(8,217

)

(8,485

)

(8,676

)

Cash dividends declared

(3,219

)

(3,474

)

Levered Free Cash Flow

$

(14,298

)

$

16,301

$

32,057

Net cash paid (received) for scheduled derivative settlements

37,431

(850

)

(51,874

)

Levered Free Cash Flow Unhedged

$

23,133

$

15,451

$

(19,817

)

__________

(1) Capital expenditures excludes acquisitions and asset retirement spending.

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 measures of Adjusted General and Administrative Expenses.

Three Months Ended

June 30, 2021

March 31, 2021

June 30, 2020

($ in thousands except per mboe amounts)

General and administrative expenses

$

16,065

$

17,070

$

18,777

Subtract:

Non-cash stock compensation expense (G&A portion)

(2,763

)

(3,669

)

(4,380

)

Non-recurring costs

(316

)

Adjusted General and Administrative Expenses

$

13,302

$

13,401

$

14,081

General and administrative expenses ($/boe)

$

6.46

$

7.01

$

7.09

Subtract:

Non-cash stock compensation expense ($/boe)

(1.11

)

(1.51

)

(1.65

)

Non-recurring costs ($/boe)

(0.12

)

Adjusted General and Administrative Expenses ($/boe)

$

5.35

$

5.50

$

5.31

Total mboe

2,485

2,435

2,650

FULL YEAR 2021 GUIDANCE

Low

High

Average Daily Production (mboe/d)

27.0

29.0

Oil as % of Production

~89%

Operating Expenses ($/boe)

$17.25

$18.55

Taxes, Other than Income Taxes ($/boe)

$3.75

$4.25

Adjusted General & Administrative (G&A) expenses ($/boe)

$5.50

$6.25

Capital Expenditures ($ millions)

$120

$130

New Wells Drilled

170

200

CONTACT: Contact Contact: bry Todd Crabtree - Manager, Investor Relations (661) 616-3811 ir@bry.com