Berry Corporation (Bry) Reports Improved Third Quarter 2021 Results and Announces Shareholder Return Model With Potential To Generate More Than 20% Returns Annually
DALLAS, Nov. 02, 2021 (GLOBE NEWSWIRE) -- Berry Corporation (bry) (NASDAQ: BRY) (“Berry”, “bry” or the “Company”) announced improved third quarter results, including net income of $10 million or $0.12 per diluted share, Adjusted Net Income(1) of $12 million or $0.14 per diluted share, and Adjusted EBITDA(1) of $59.3 million, a 46% increase sequentially. The Board of Directors approved a quarterly common stock dividend of $0.06 per share for the fourth quarter of 2021, and a new total shareholder return model expected to be implemented in 2022.
Quarterly Highlights
- Increased sequential quarterly Adjusted EBITDA(1) by 46% to $59.3 million totaling $152 million YTD
- Completed accretive acquisition of CA well services business, now operating as C&J Well Services, further aligning bry with the State of California's goal to reduce fugitive emissions
- Completed sale of Placerita Field operations in Los Angeles County, consolidating all California assets into rural Kern County
- Completed new $500 million RBL credit facility; maintaining $200 million borrowing base and elected commitment
- Updated guidance to reflect drilling and A&D activity
- Board approved fourth quarter 2021 dividend of $0.06/share
- Announced plan to implement new shareholder return model starting in 2022
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(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.
“The most recent upturn in oil prices, the continued global under-investment in oil and gas, and the on-going growth in global demand presents an exceptional opportunity for bry. We believe this cycle is different than prior cycles. Our current view is that it will likely be longer in duration, possibly the next couple of decades, and therefore represents a potentially fundamental change for the industry.” said Trem Smith, bry board chairman and CEO.
“The Board has approved the following model that will continue to position Berry as a top tier returner of capital back to our shareholders. It will consist of a mix of returns through variable cash dividends, in addition to our current dividend, share repurchases and debt retirement, while keeping a portion available for organic growth and bolt-on acquisitions. At our stock price and the current oil strip, we believe the shareholder returns could be more than 20% per share annually. Berry has all the critical elements in place with a proven, simple business model which includes a low corporate decline rate, a predictable cost structure, an abundance of inventory, Brent pricing and a simple, clean balance sheet. Based on current industry fundamentals, we should generate considerable levered free cash flow for many years to come. We look forward to unveiling the full details of the model later this quarter and implementing it beginning in 2022,” continued Smith.
Third Quarter 2021 Results
Adjusted EBITDA(1), on a hedged basis, was $59.3 million in the third quarter 2021. This represented a 46% increase compared to $40.6 million in the second quarter 2021. The increase was largely the result of higher oil and natural gas prices, as well as improved hedge positions and increased oil and gas production.
The Company realized a slight increase in average daily production by 100 boe/d to 27,400 boe/d for the third quarter of 2021 compared to the second quarter of 2021, as a result of its continuing 2021 development program, consisting of 56 new wells in the quarter. The Company's oil production for the third quarter 2021 was 24,100 bbl/d, while California production was 21,800 boe/d, each of which was a slight increase from the second quarter 2021. Production for the third quarter was impacted as we managed the onboarding of a new drilling operator and an industry-wide shortage of truck drivers. Most of these issues were mitigated by the end of the third quarter.
The Company-wide hedged realized oil price for the third quarter 2021 was $54.35 per bbl, a 17% increase from the second quarter. The California average oil price before hedges for the third quarter was $69.92 per bbl, 95% of Brent, which was 7% higher than the $65.37 per bbl in the second quarter 2021, also 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 decreased by 1% or $0.13 per boe to $17.18 for the third quarter 2021, compared to $17.31 for the second quarter 2021. During the third quarter the Company's non-energy operating expenses increased slightly on a per boe basis, compared to the second quarter of 2021, due primarily to higher well maintenance activity, higher power prices, and higher outside services and facility costs partially offset by lower steam facility expense. Energy operating expenses improved as increased electricity revenue and gas purchase hedging more than offset higher natural gas prices.
General and administrative expenses increased by almost $2 million, or 10%, to approximately $18 million for the third quarter 2021, compared to the second quarter 2021, largely due to legal and 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 essentially flat at $13 million and $5.34 per boe for the third quarter 2021.
Taxes, other than income taxes were $5.33 per boe for the third quarter compared to $4.67 per boe in the second quarter 2021 largely due to higher greenhouse gas costs as mark-to-market valuations increased.
For the third quarter 2021, capital expenditures were approximately $38 million on an accrual basis and excluding acquisitions and asset retirement obligation spending. Approximately 78% of this capital was directed to California oil operations, and 15% to Utah operations. Additionally, bry spent approximately $5 million and $12 million for plugging and abandonment activities in the third quarter 2021 and year-to-date, respectively.
At September 30, 2021, the Company had liquidity of $243 million consisting of $43 million cash on hand and $200 million available for borrowings under its RBL Facility.
“We continued to deliver on our 2021 plan, while enhancing our portfolio since the second quarter with the accretive acquisition of our new C&J Well Services business, which was a strategic and value-adding transaction purchased at a competitive price. Last week, we sold our Placerita Field operations in Los Angeles County consolidating all our California operations into Kern County. Also, due primarily to the divestiture of our Placerita asset we have refined our total production range for 2021 to be in the 27,200 to 27,700 range,” stated Cary Baetz, chief financial officer, EVP and director. “Additionally, we completed our new $500 million RBL facility which matures in 2025, maintaining our $200 million borrowing base and elected commitment.”
Quarterly Dividend
The Company’s Board of Directors declared a regular dividend for the fourth quarter of 2021 at a rate of $0.06 per share on the Company’s outstanding common stock, payable on January 17, 2022 to shareholders of record at the close of business on December 15, 2021.
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 pay a similar fixed dividend in future quarters.
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(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 November 3, 2021, to discuss these results:
| Live Call Date: | Wednesday, November 3, 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: | 3586911 |
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, November 17, 2021 | |
| Replay Dial-in: | 855-859-2056 from the U.S. 404-537-3406 from international locations | |
| Replay Passcode: | 3586911 |
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, with well servicing and abandonment capabilities. 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; anticipated financial and operating results; capital program and development and production plans; operations and business strategy; potential acquisition opportunities; reserves; hedging activities; capital expenditures, shareholder returns or return of capital; payment, payment of or improvement of future dividends; future repurchases of stock or debt; capital investments, and 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 and subsequent filings with the SEC, including the Company's Form 10-Q for the quarter ended September 30, 2021.
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 | ||||||||||
| September 30, 2021 | June 30, 2021 | September 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 | $ | 161,058 | $ | 147,775 | $ | 92,239 | |||||
| Electricity sales | 12,371 | 6,888 | 8,744 | ||||||||
| Losses on oil and gas sales derivatives | (30,864 | ) | (55,653 | ) | (11,564 | ) | |||||
| Marketing revenues | 732 | 121 | 330 | ||||||||
| Other revenues | 117 | 118 | — | ||||||||
| Total revenues and other | 143,414 | 99,249 | 89,749 | ||||||||
| Expenses and other: | |||||||||||
| Lease operating expenses | 60,930 | 45,543 | 45,243 | ||||||||
| Electricity generation expenses | 7,128 | 4,712 | 4,217 | ||||||||
| Transportation expenses | 1,806 | 1,757 | 1,768 | ||||||||
| Marketing expenses | 715 | 44 | 326 | ||||||||
| General and administrative expenses | 17,614 | 16,065 | 19,173 | ||||||||
| Depreciation, depletion and amortization | 35,902 | 35,850 | 35,905 | ||||||||
| Taxes, other than income taxes | 13,420 | 11,603 | 9,913 | ||||||||
| Gains on natural gas purchase derivatives | (14,980 | ) | (11,639 | ) | (15,784 | ) | |||||
| Other operating expenses | 3,986 | 42 | 1,648 | ||||||||
| Total expenses and other | 126,521 | 103,977 | 102,409 | ||||||||
| Other (expenses) income: | |||||||||||
| Interest expense | (7,810 | ) | (8,217 | ) | (8,391 | ) | |||||
| Other, net | (5 | ) | (8 | ) | (3 | ) | |||||
| Total other (expenses) income | (7,815 | ) | (8,225 | ) | (8,394 | ) | |||||
| Income (loss) before income taxes | 9,078 | (12,953 | ) | (21,054 | ) | ||||||
| Income tax benefit | (758 | ) | (72 | ) | (2,190 | ) | |||||
| Net income (loss) | $ | 9,836 | $ | (12,881 | ) | $ | (18,864 | ) | |||
| Net income (loss) per share: | |||||||||||
| Basic | $ | 0.12 | $ | (0.16 | ) | $ | (0.24 | ) | |||
| Diluted | $ | 0.12 | $ | (0.16 | ) | $ | (0.24 | ) | |||
| Weighted-average shares of common stock outstanding - basic | 80,242 | 80,471 | 79,879 | ||||||||
| Weighted-average shares of common stock outstanding - diluted | 82,898 | 80,471 | 79,879 | ||||||||
| Adjusted Net Income (Loss)(1) | $ | 11,536 | $ | (6,293 | ) | $ | 13,452 | ||||
| Weighted-average shares of common stock outstanding - diluted | 82,898 | 80,471 | 80,062 | ||||||||
| Diluted earnings per share on Adjusted Net Income (Loss) | $ | 0.14 | $ | (0.08 | ) | $ | 0.17 | ||||
| Three Months Ended | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| ($ and shares in thousands, except per share amounts) | |||||||||||
| Adjusted EBITDA(1) | $ | 59,324 | $ | 40,599 | $ | 61,515 | |||||
| Adjusted EBITDA Unhedged(1) | $ | 76,946 | $ | 78,030 | $ | 26,039 | |||||
| Levered Free Cash Flow(1) | $ | 8,692 | $ | (14,298 | ) | $ | 47,206 | ||||
| Levered Free Cash Flow Unhedged(1) | $ | 26,314 | $ | 23,133 | $ | 11,730 | |||||
| Adjusted General and Administrative Expenses(1) | $ | 13,442 | $ | 13,302 | $ | 13,888 | |||||
| Effective Tax Rate, including discrete items | (8 | )% | 1 | % | 10 | % | |||||
| Cash Flow Data: | |||||||||||
| Net cash provided by operating activities | $ | 22,399 | $ | 21,429 | $ | 57,997 | |||||
| Net cash used in investing activities | $ | (50,024 | ) | $ | (40,575 | ) | $ | (9,004 | ) | ||
| Net cash used in financing activities | $ | (9,132 | ) | $ | (3,298 | ) | $ | (1,373 | ) | ||
__________
(1) See further discussion and reconciliation in “Non-GAAP Financial Measures and Reconciliations”.
(2) The effective tax rate for the nine months ended September 30, 2021 is 5%.
| September 30, 2021 | December 31, 2020 | ||||||
| ($ and shares in thousands) | |||||||
| Balance Sheet Data: | |||||||
| Total current assets | $ | 178,919 | $ | 154,491 | |||
| Total property, plant and equipment, net | $ | 1,233,223 | $ | 1,258,084 | |||
| Total current liabilities | $ | 194,058 | $ | 175,306 | |||
| Long-term debt | $ | 394,285 | $ | 393,480 | |||
| Total stockholders' equity | $ | 684,896 | $ | 714,036 | |||
| Outstanding common stock shares as of | 80,007 | 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 | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| ($ in thousands, except prices) | |||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 140,160 | $ | 129,128 | $ | 81,592 | |||||
| Operating income(1) | $ | 26,652 | $ | 11,413 | $ | 36,296 | |||||
| Depreciation, depletion, and amortization (DD&A) | $ | 35,252 | $ | 35,174 | $ | 34,779 | |||||
| Average daily production (mboe/d) | 21.8 | 21.7 | 22.2 | ||||||||
| Production (oil % of total) | 100 | % | 100 | % | 100 | % | |||||
| Realized sales prices: | |||||||||||
| Oil (per bbl) | $ | 69.92 | $ | 65.37 | $ | 40.02 | |||||
| NGLs (per bbl) | $ | — | $ | — | $ | — | |||||
| Gas (per mcf) | $ | — | $ | — | $ | — | |||||
| Capital expenditures(2) | $ | 29,806 | $ | 31,303 | $ | 4,467 | |||||
| Utah (Uinta basin) | Colorado (Piceance basin) | ||||||||||||||||||||||
| Three Months Ended | Three Months Ended | ||||||||||||||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | September 30, 2021 | June 30, 2021 | September 30, 2020 | ||||||||||||||||||
| ($ in thousands, except prices) | |||||||||||||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 18,118 | $ | 16,199 | $ | 9,311 | $ | 2,779 | $ | 2,438 | $ | 1,336 | |||||||||||
| Operating income (loss)(1) | $ | 7,246 | $ | 6,736 | $ | 1,093 | $ | 2,360 | $ | 1,121 | $ | (235 | ) | ||||||||||
| Depreciation, depletion, and amortization (DD&A) | $ | 611 | $ | 630 | $ | 915 | $ | 38 | $ | 38 | $ | 165 | |||||||||||
| Average daily production (mboe/d) | 4.4 | 4.4 | 4.1 | 1.2 | 1.2 | 1.3 | |||||||||||||||||
| Production (oil % of total) | 50 | % | 52 | % | 47 | % | 1 | % | 2 | % | 2 | % | |||||||||||
| Realized sales prices: | |||||||||||||||||||||||
| Oil (per bbl) | $ | 60.09 | $ | 58.55 | $ | 38.40 | $ | 66.97 | $ | 56.05 | $ | 33.60 | |||||||||||
| NGLs (per bbl) | $ | 40.88 | $ | 29.61 | $ | 13.25 | $ | — | $ | — | $ | — | |||||||||||
| Gas (per mcf) | $ | 4.31 | $ | 3.30 | $ | 2.05 | $ | 4.24 | $ | 3.53 | $ | 1.80 | |||||||||||
| Capital expenditures(2) | $ | 5,728 | $ | 9,162 | $ | 103 | $ | — | $ | — | $ | 46 | |||||||||||
__________
(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 | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| Weighted-average realized sales prices: | |||||||||||
| Oil without hedges ($/bbl) | $ | 69.01 | $ | 64.72 | $ | 39.88 | |||||
| Effects of scheduled derivative settlements ($/bbl) | $ | (14.66 | ) | $ | (18.33 | ) | $ | 16.28 | |||
| Oil with hedges ($/bbl) | $ | 54.35 | $ | 46.39 | $ | 56.16 | |||||
| Natural gas ($/mcf) | $ | 4.29 | $ | 3.39 | $ | 1.95 | |||||
| NGLs ($/bbl) | $ | 40.88 | $ | 29.61 | $ | 13.25 | |||||
| Average Benchmark prices: | |||||||||||
| Oil (bbl) – Brent | $ | 73.23 | $ | 69.08 | $ | 43.34 | |||||
| Oil (bbl) – WTI | $ | 70.63 | $ | 66.03 | $ | 40.87 | |||||
| Natural gas (mmbtu) – Kern, Delivered(1) | $ | 5.75 | $ | 3.23 | $ | 2.84 | |||||
| Natural gas (mmbtu) – Henry Hub(2) | $ | 4.35 | $ | 2.95 | $ | 2.00 | |||||
__________
(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 September 30, 2021, we had the following crude oil production and gas purchases hedges.
| Q4 2021 | FY 2022 | FY 2023 | FY 2024 | ||||||||||||
| Fixed Price Oil Swaps (Brent): | |||||||||||||||
| Hedged volume (mbbls) | 1,318 | 3,387 | 1,596 | 732 | |||||||||||
| Weighted-average price ($/bbl) | $ | 48.61 | $ | 66.63 | $ | 65.26 | $ | 61.78 | |||||||
| Purchased Oil Put Options (Brent): | |||||||||||||||
| Hedged volume (mbbls) | 307 | 1,643 | 2,555 | 1,647 | |||||||||||
| Weighted-average price ($/bbl) | $ | 60.00 | $ | 50.00 | $ | 50.00 | $ | 50.00 | |||||||
| Sold Oil Put Options (Brent): | |||||||||||||||
| Hedged volume (mbbls) | — | 1,643 | 2,555 | 1,647 | |||||||||||
| Weighted-average price ($/bbl) | $ | — | $ | 40.00 | $ | 40.00 | $ | 40.00 | |||||||
| Sold Oil Calls Options (Brent): | |||||||||||||||
| Hedged volume (mbbls) | 307 | — | — | — | |||||||||||
| Weighted-average price ($/bbl) | $ | 75.00 | $ | — | $ | — | $ | — | |||||||
| Purchased Gas Call Options (Henry Hub): | |||||||||||||||
| Hedged volume (mmbtu) | 1,830,000 | 10,950,000 | 10,950,000 | 9,150,000 | |||||||||||
| Weighted-average price ($/mmbtu) | $ | 4.00 | $ | 4.00 | $ | 4.00 | $ | 4.00 | |||||||
| Sold Gas Put Options (Henry Hub): | |||||||||||||||
| Hedged volume (mmbtu) | 1,830,000 | 10,950,000 | 10,950,000 | 9,150,000 | |||||||||||
| Weighted-average price ($/mmbtu) | $ | 2.75 | $ | 2.75 | $ | 2.75 | $ | 2.75 | |||||||
| Fixed Price Gas Purchase Swaps (Kern, Delivered): | |||||||||||||||
| Hedged volume (mmbtu) | 2,085,000 | — | — | — | |||||||||||
| Weighted-average price ($/mmbtu) | $ | 2.95 | $ | — | $ | — | $ | — | |||||||
In October we added purchased gas put options (Henry Hub) of 20,000 mmbtu/d at $2.75 beginning November 2021 through March 2022, which offset the fourth quarter 2021 and first quarter 2022 sold gas put options included in the above table. We added sold oil put options (Brent) of 500 bbl/d at $60.00 beginning November 2021 through December 2021, which offset the fourth quarter 2021 purchased oil put options included in the above table. We also added purchased fixed price oil swaps (Brent) of 1,000 bbl/d at $66.95 beginning January 2022 through December 2022, which partially offset the 2022 fixed price oil swaps included in the table above.
During the second and third quarters of 2021 we entered into 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. During the third quarter of 2021 we entered into a capacity agreement for approximately 32,700 mmbtu/d beginning May 2022 through April 2032 for a total commitment of $62 million. In the second quarter of 2021 we entered into pipeline capacity agreements 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. The average price for all three agreements is approximately $0.52 mmbtu/d.
OPERATING EXPENSES
| Three Months Ended | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| ($ in thousands except per boe amounts) | |||||||||||
| Lease operating expenses | $ | 60,930 | $ | 45,543 | $ | 45,243 | |||||
| Electricity generation expenses | 7,128 | 4,712 | 4,217 | ||||||||
| Electricity sales(1) | (12,371 | ) | (6,888 | ) | (8,744 | ) | |||||
| Transportation expenses | 1,806 | 1,757 | 1,768 | ||||||||
| Transportation sales(1) | (117 | ) | (118 | ) | — | ||||||
| Marketing expenses | 715 | 44 | 326 | ||||||||
| Marketing revenues(1) | (732 | ) | (121 | ) | (330 | ) | |||||
| Derivative settlements (received) paid for gas purchases(1) | (14,095 | ) | (1,913 | ) | 614 | ||||||
| Total operating expenses(1) | $ | 43,264 | $ | 43,016 | $ | 43,094 | |||||
| Lease operating expenses ($/boe) | $ | 24.20 | $ | 18.33 | $ | 17.83 | |||||
| Electricity generation expenses ($/boe) | 2.83 | 1.90 | 1.66 | ||||||||
| Electricity sales ($/boe) | (4.91 | ) | (2.77 | ) | (3.45 | ) | |||||
| Transportation expenses ($/boe) | 0.72 | 0.70 | 0.69 | ||||||||
| Transportation sales ($/boe) | (0.05 | ) | (0.05 | ) | — | ||||||
| Marketing expenses ($/boe) | 0.28 | 0.02 | 0.13 | ||||||||
| Marketing revenues ($/boe) | (0.29 | ) | (0.05 | ) | (0.13 | ) | |||||
| Derivative settlements (received) paid for gas purchases ($/boe) | (5.60 | ) | (0.77 | ) | 0.24 | ||||||
| Total operating expenses ($/boe) | $ | 17.18 | $ | 17.31 | $ | 16.97 | |||||
| Total unhedged operating expenses ($/boe)(2) | $ | 22.78 | $ | 18.08 | $ | 16.73 | |||||
| Total non-energy operating expenses(3) | $ | 13.59 | $ | 12.71 | $ | 13.34 | |||||
| Total energy operating expenses(4) | $ | 3.59 | $ | 4.60 | $ | 3.65 | |||||
| Total mboe | 2,519 | 2,485 | 2,537 | ||||||||
__________
(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 | |||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||
| Net Oil, Natural Gas and NGLs Production Per Day(1): | |||||
| Oil (mbbl/d) | |||||
| California | 21.8 | 21.7 | 22.2 | ||
| Utah | 2.3 | 2.3 | 1.9 | ||
| Colorado | — | — | — | ||
| Total oil | 24.1 | 24.0 | 24.1 | ||
| Natural gas (mmcf/d) | |||||
| California | — | — | — | ||
| Utah | 10.7 | 10.3 | 11.0 | ||
| Colorado | 6.9 | 7.2 | 7.7 | ||
| Total natural gas | 17.6 | 17.5 | 18.7 | ||
| NGLs (mbbl/d) | |||||
| California | — | — | — | ||
| Utah | 0.4 | 0.4 | 0.4 | ||
| Colorado | — | — | — | ||
| Total NGLs | 0.4 | 0.4 | 0.4 | ||
| Total Production (mboe/d)(2) | 27.4 | 27.3 | 27.6 | ||
__________
(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 September 30, 2021, the average prices of Brent oil and Henry Hub natural gas were $73.23 per bbl and $4.35 per mmbtu respectively.
CAPITAL EXPENDITURES (ACCRUAL BASIS)
| Three Months Ended | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| (in thousands) | |||||||||||
| Capital expenditures (accrual basis)(1) | $ | 38,016 | $ | 43,461 | $ | 5,918 | |||||
__________
(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 | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| ($ thousands, except per share amounts) | |||||||||||
| Net income (loss) | $ | 9,836 | $ | (12,881 | ) | $ | (18,864 | ) | |||
| Subtract: discrete income tax items | — | — | (2,394 | ) | |||||||
| Add (Subtract): | |||||||||||
| Losses on derivatives | 15,885 | 44,014 | (4,220 | ) | |||||||
| Net cash (paid) received for scheduled derivative settlements | (17,622 | ) | (37,431 | ) | 35,476 | ||||||
| Other operating expenses | 3,986 | 42 | 1,648 | ||||||||
| Non-recurring costs | 705 | — | 1,473 | ||||||||
| Total additions, net | 2,954 | 6,625 | 34,377 | ||||||||
| Income tax (expense) benefit of adjustments at effective tax rate | (1,254 | ) | (37 | ) | 333 | ||||||
| Adjusted Net Income (Loss) | $ | 11,536 | $ | (6,293 | ) | $ | 13,452 | ||||
| Basic EPS on Adjusted Net Income (Loss) | $ | 0.14 | $ | (0.08 | ) | $ | 0.17 | ||||
| Diluted EPS on Adjusted Net Income (Loss) | $ | 0.14 | $ | (0.08 | ) | $ | 0.17 | ||||
| Weighted average shares of common stock outstanding - basic | 80,242 | 80,471 | 79,879 | ||||||||
| Weighted average shares of common stock outstanding - diluted | 82,898 | 80,471 | 80,062 | ||||||||
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 | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| ($ thousands) | |||||||||||
| Net income (loss) | $ | 9,836 | $ | (12,881 | ) | $ | (18,864 | ) | |||
| Add (Subtract): | |||||||||||
| Interest expense | 7,810 | 8,217 | 8,391 | ||||||||
| Income tax benefit | (758 | ) | (72 | ) | (2,190 | ) | |||||
| Depreciation, depletion and amortization | 35,902 | 35,850 | 35,905 | ||||||||
| Losses (gains) on derivatives | 15,885 | 44,014 | (4,220 | ) | |||||||
| Net cash (paid) received for scheduled derivative settlements | (17,622 | ) | (37,431 | ) | 35,476 | ||||||
| Other operating expense(1) | 3,986 | 42 | 1,648 | ||||||||
| Stock compensation expense | 3,580 | 2,860 | 3,896 | ||||||||
| Non-recurring costs(2) | 705 | — | 1,473 | ||||||||
| Adjusted EBITDA | $ | 59,324 | $ | 40,599 | $ | 61,515 | |||||
| Net cash paid (received) for scheduled derivative settlements | 17,622 | 37,431 | (35,476 | ) | |||||||
| Adjusted EBITDA Unhedged | $ | 76,946 | $ | 78,030 | $ | 26,039 | |||||
| Net cash provided by operating activities | $ | 22,399 | $ | 21,429 | $ | 57,997 | |||||
| Add (Subtract): | |||||||||||
| Cash interest payments | 14,189 | 288 | 14,435 | ||||||||
| Cash income tax payments | 294 | — | 221 | ||||||||
| Non-recurring costs | 705 | — | 1,473 | ||||||||
| Other changes in operating assets and liabilities | 21,737 | 18,882 | (12,611 | ) | |||||||
| Adjusted EBITDA | $ | 59,324 | $ | 40,599 | $ | 61,515 | |||||
| Net cash paid (received) for scheduled derivative settlements | 17,622 | 37,431 | (35,476 | ) | |||||||
| Adjusted EBITDA Unhedged | $ | 76,946 | $ | 78,030 | $ | 26,039 | |||||
__________
(1) Other operating expenses mainly consist of unamortized debt issuance costs related to the termination of the 2017 RBL Facility, supplemental property tax assessments and royalty audit charges, excess abandonment costs and oil tank storage fees, as well as income from employee retention credits.
(2) Non-recurring costs include legal and professional service expenses related to acquisition and divestiture activity.
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 | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| ($ thousands) | |||||||||||
| Adjusted EBITDA | $ | 59,324 | $ | 40,599 | $ | 61,515 | |||||
| Subtract: | |||||||||||
| Capital expenditures - accrual basis(1) | (38,016 | ) | (43,461 | ) | (5,918 | ) | |||||
| Interest expense | (7,810 | ) | (8,217 | ) | (8,391 | ) | |||||
| Cash dividends declared | (4,806 | ) | (3,219 | ) | — | ||||||
| Levered Free Cash Flow | $ | 8,692 | $ | (14,298 | ) | $ | 47,206 | ||||
| Net cash paid (received) for scheduled derivative settlements | 17,622 | 37,431 | (35,476 | ) | |||||||
| Levered Free Cash Flow Unhedged | $ | 26,314 | $ | 23,133 | $ | 11,730 | |||||
__________
(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 | |||||||||||
| September 30, 2021 | June 30, 2021 | September 30, 2020 | |||||||||
| ($ in thousands except per mboe amounts) | |||||||||||
| General and administrative expenses | $ | 17,614 | $ | 16,065 | $ | 19,173 | |||||
| Subtract: | |||||||||||
| Non-cash stock compensation expense (G&A portion) | (3,467 | ) | (2,763 | ) | (3,812 | ) | |||||
| Non-recurring costs | (705 | ) | — | (1,473 | ) | ||||||
| Adjusted General and Administrative Expenses | $ | 13,442 | $ | 13,302 | $ | 13,888 | |||||
| General and administrative expenses ($/boe) | $ | 6.99 | $ | 6.46 | $ | 7.56 | |||||
| Subtract: | |||||||||||
| Non-cash stock compensation expense ($/boe) | (1.37 | ) | (1.11 | ) | (1.50 | ) | |||||
| Non-recurring costs ($/boe) | (0.28 | ) | — | (0.58 | ) | ||||||
| Adjusted General and Administrative Expenses ($/boe) | $ | 5.34 | $ | 5.35 | $ | 5.47 | |||||
| Total mboe | 2,519 | 2,485 | 2,537 | ||||||||
Contact Contact: bry Todd Crabtree - Manager, Investor Relations (661) 616-3811 ir@bry.com