Berry Corporation (bry) Reports Second Quarter 2022 Results

DALLAS, Aug. 03, 2022 (GLOBE NEWSWIRE) — Berry Corporation (bry) (NASDAQ: BRY) (“Berry” or the “Company”) announced second quarter 2022 results, including net income of $43 million or $0.52 per diluted share, Adjusted Net Income(1) of $53 million or $0.64 per diluted share, Adjusted EBITDA(1) of $110 million and cash flows from operating activities of $111 million. The Board of Directors declared dividends on common stock totaling $0.62 per share.

Quarterly Highlights

  • Reported Adjusted EBITDA(1) of $110 million, up 15% from Q1 2022
  • Generated Discretionary Free Cash Flow(1) of $74 million
  • Repurchased 2 million shares of common stock
  • Declared total quarterly dividends of $0.62 per share: $0.56 variable and $0.06 fixed
  • Reaffirmed FY 2022 cash dividends expected at $1.60 – $1.90 per share, based on current plan and commodity strip prices

_______

(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.

“As demonstrated by our second quarter results, Berry continues to deliver impressive cash flows. For the quarter, our combined dividend will be $0.62 and in the same period we successfully repurchased two million shares of Berry stock for $23 million. Since our 2018 IPO, we will have returned over $225 million to shareholders in the form of dividends and share repurchases, which is more than two times the $110 million of net IPO proceeds. In fact, we have repurchased more than 7.5 million shares or nearly 10% of Berry’s outstanding shares over the last few years,” said Trem Smith, Berry Board Chair and CEO.

For the remainder of the year, we currently see our production holding relatively steady and our discretionary free cash flow remaining strong. We are focused on proactively managing our business and adapting to the dynamic macro environment while continuing to uphold our capital return commitments. I’m pleased to announce an exciting development potentially allowing new Thermal Diatomite production. We have encouraging initial results from early testing of two new horizontal wells using a new development concept that takes advantage of existing reservoir energy, and therefore does not require high pressure cyclic steam injection. While the results are still preliminary and additional testing needs to be performed, if ultimately successful this application offers a potentially significant opportunity. We also continue our early stage CCS efforts through signed Letters of Intent to capture and sequester the majority of our direct operational Scope 1 carbon dioxide emissions in California; although these CCS projects remain subject to regulatory approval, we look forward to working with the counter-parties on a solution that benefits all of our stakeholders,” continued Smith.

Second Quarter 2022 Results

Adjusted EBITDA(1), on a hedged basis, was $110 million in the second quarter 2022. This represented a 15% increase compared to $96 million in the first quarter 2022. This increase is largely the result of higher hedged oil prices and improved margins from the well servicing and abandonment segment, partially offset by lower oil and gas volumes and higher GHG prices as that market returned to more normal levels compared to the first quarter.

The Company reported daily production of 26,200 boe/d for the second quarter 2022, compared to 26,700 boe/d for the first quarter of 2022. The sequential decrease was primarily attributed to the divestment of our Colorado asset in the first quarter and shut in production during planned drilling, workover and abandonment activities in California during the second quarter. Production in Utah increased largely as a result of the drilling program during the first half of the year. The Company’s oil production for the second quarter 2022 was 24,000 bbl/d, or 92% of total production, with California production contributing 21,000 boe/d or 80% of total production.

The Company-wide hedged realized oil price for the second quarter 2022 was $83.78 per bbl, a 9% increase from the prior quarter. The California average oil price before hedges for the second quarter 2022 was $107.31 per bbl, reflecting approximately 96% of Brent, which was 15% higher than the $93.16 per bbl in the first quarter 2022, 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 slightly by $0.33 per boe or 1% to $25.97 for the second quarter 2022, compared to $25.64 for the first quarter 2022. During the second quarter, non-energy operating expenses increased due to higher workover and field monitoring activity associated with our field optimization program, and well and facility maintenance expenses. A portion of these higher costs was driven by inflation. Energy operating expenses decreased in the second quarter due to lower hedged fuel prices and higher electricity sales, compared to the first quarter 2022.

Total general and administrative expenses were comparable at $23 million for each of the second and first quarters of 2022. Adjusted General and Administrative Expenses(1), which exclude non-cash stock compensation costs and nonrecurring costs, were also comparable at $19 million for the second and first quarters of 2022.

Taxes, other than income taxes were $4.70 per boe for the second quarter compared to $2.74 per boe in the first quarter 2022 with the increase largely due to the GHG prices returning to the higher, more normal levels compared to the first quarter.

For the second quarter 2022, capital expenditures were approximately $34 million on an accrual basis including capitalized overhead and interest and excluding acquisitions and asset retirement obligation spending. Approximately 55% of this capital was directed to California oil operations, and 34% to Utah operations. Additionally, the Company spent approximately $6 million for plugging and abandonment activities in the second quarter 2022. Aggregate capital expenditures in the first half of 2022 were $62 million and the Company expects full year capital will be at the lower end of its guidance range due to a shift in its development plans to reuse existing wellbores.

The operating results for C&J Well Services improved in the second quarter 2022 compared to the first quarter 2022. For this segment in the second and first quarters 2022, respectively, services revenues were $46 million and $40 million, costs of services were $37 million and $33 million, and general and administrative expenses were $3 million each quarter.

At June 30, 2022, the Company had liquidity of $251 million consisting of $58 million cash on hand and $193 million available for borrowings under its RBL Facility.

“It was a strong discretionary free cash flow quarter and, at current commodity prices, we expect to continue to deliver top tier returns,” stated Cary Baetz, Berry’s Executive Vice President and Chief Financial Officer. “Our 2022 guidance ranges remain in place; however, operating expenses are tracking on the higher side of guidance due to an increase in workovers expensed as we optimized our base production as well as incurred some additional costs associated with our new surveillance program. We also expect a slightly lower capital expenditure due primarily to the increase in workovers expensed and lower overall new drill well count for the year.”

Quarterly Dividends

The Company’s Board of Directors declared dividends totaling $0.62 per share on the Company’s outstanding common stock. The variable portion of $0.56 per share was based on second quarter 2022 Discretionary Free Cash Flow(1) in accordance with the Company’s Shareholder Return Model. The fixed portion of $0.06 per share was also declared, and both dividends are payable on August 25, 2022 to shareholders of record at the close of business on August 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.

Full-Year 2022 Guidance

Berry reiterates its previously issued full-year 2022 guidance as follows.

Full-Year 2022 Guidance Low   High
Average Daily Production (boe/d)(1)  25,500    27,500
Non-Energy Operating Expenses ($/boe) $13.75   $14.25
Operating Expenses ($/boe) $20.00   $22.00
Taxes, Other than Income Taxes ($/boe) $4.50   $5.50
Adjusted General & Administrative (G&A) expenses ($/boe)(2)      
Development and Production Segment & Corp $5.75   $6.25
Well Servicing and Abandonment Segment   ~$1.45  
Capital Expenditures ($ millions)      
Development and Production Segment & Corp $125   $135
Well Servicing and Abandonment Segment   ~$8  
Well Servicing & Abandonment Segment Adjusted EBITDA ($mm)   ~$27  

______

(1)   Oil production is expected to be approximately 92% of total.

(2)   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 to discuss these results:

If you would like to ask a question on the live call, please preregister at any time using the following link:
https://register.vevent.com/register/BI057ced2ba12c4a29bd9c527438fcde56

Once registered, you will receive the dial-in numbers and a unique PIN number. You may then dial-in or have a call back. When you dial in, you will input your PIN and be placed into the call. If you register and forget your PIN or lose your registration confirmation email, you may simply re-register and receive a new PIN.

A web based audio replay will be available shortly after the broadcast and will be archived at https://ir.bry.com/reports-resources or visit https://edge.media-server.com/mmc/p/yaxee5u6

About Berry Corporation (bry)

Berry is a publicly traded (NASDAQ: BRY) western United States independent upstream energy company with a focus on onshore, low geologic risk, long-lived, conventional oil reserves located primarily in the San Joaquin basin of California, as well as the Uinta basin of Utah. We also have well servicing and abandonment capabilities in California. More information can be found at the Company’s website at bry.com.

Forward-Looking Statements

The information in this press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address plans, activities, events, objectives, goals, strategies, or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding its business; financial position; liquidity; cash flows (including, but not limited to, Discretionary Free Cash Flow); financial and operating results; capital program; development and production opportunities and plans; operations and business strategy; potential acquisitions and other organic and strategic growth opportunities; reserves; hedging activities; capital expenditures; return of capital; our new shareholder return model; the payment of or improvement of future dividends; future repurchases of stock or debt; capital investments; the ability to execute ESG-related projects, including reduction of our carbon footprint; 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 with respect to existing and/or new requirements in the regulatory approval and permitting process; legislative and regulatory initiatives in California or our other areas of operation addressing climate change or other environmental concerns; investment in and development of competing or alternative energy sources; drilling, production and other operating risks; 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; disruptions to, capacity constraints in, or other limitations on the third-party transportation and market takeaway infrastructure (including pipeline systems) that deliver our oil and natural gas and other processing and transportation considerations; the 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; overall domestic and global political and economic conditions; inflation levels, particularly the recent rise to historically high levels, and government efforts to reduce inflation, including increased interest rates; 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
  June 30, 2022   March 31, 2022   June 30, 2021
  ($ and shares in thousands, except per share amounts)
Statement of Operations Data:          
Revenues and other:          
Oil, natural gas and natural gas liquids sales $ 240,071     $ 210,351     $ 147,775  
Services revenue   46,178       39,836        
Electricity sales   7,419       5,419       6,888  
Losses on oil and gas sales derivatives   (40,658 )     (161,858 )     (55,653 )
Marketing revenues         289       121  
Other revenues   120       45       118  
Total revenues and other   253,130       94,082       99,249  
           
Expenses and other:          
Lease operating expenses   72,455       63,124       45,543  
Costs of services   36,709       33,472        
Electricity generation expenses   6,122       4,463       4,712  
Transportation expenses   1,108       1,158       1,757  
Marketing expenses         299       44  
General and administrative expenses   23,183       22,942       16,065  
Depreciation, depletion and amortization   38,055       39,777       35,850  
Taxes, other than income taxes   11,214       6,605       11,603  
Losses (gains) on natural gas purchase derivatives   10,661       (29,054 )     (11,639 )
Other operating expenses   353       3,769       42  
Total expenses and other   199,860       146,555       103,977  
           
Other (expenses) income:          
Interest expense   (7,729 )     (7,675 )     (8,217 )
Other, net   (42 )     (13 )     (8 )
Total other (expenses) income   (7,771 )     (7,688 )     (8,225 )
Income (loss) before income taxes   45,499       (60,161 )     (12,953 )
Income tax expense (benefit)   2,145       (3,351 )     (72 )
Net income (loss) $ 43,354     $ (56,810 )   $ (12,881 )
           
Net income (loss) per share:          
Basic $ 0.54     $ (0.71 )   $ (0.16 )
Diluted $ 0.52     $ (0.71 )   $ (0.16 )
           
Weighted-average shares of common stock outstanding – basic   79,596       80,298       80,471  
Weighted-average shares of common stock outstanding – diluted   83,015       80,298       80,471  
           
Adjusted Net Income (Loss)(1) $ 53,136     $ 42,871     $ (6,293 )
Weighted-average shares of common stock outstanding – diluted   83,015       84,447       80,471  
Diluted earnings per share on Adjusted Net Income (Loss) $ 0.64     $ 0.51     $ (0.08 )
  Three Months Ended
  June 30, 2022   March 31, 2022   June 30, 2021
  ($ and shares in thousands, except per share amounts)
Adjusted EBITDA(1) $ 109,747     $ 95,712     $ 40,599  
Adjusted EBITDA Unhedged(1) $ 147,375     $ 127,864     $ 78,030  
Adjusted General and Administrative Expenses(1) $ 18,920     $ 19,038     $ 13,302  
Effective Tax Rate, including discrete items   5 %     5 %     1 %
           
Cash Flow Data:          
Net cash provided by operating activities $ 111,242     $ 48,530     $ 21,429  
Net cash used in investing activities $ (38,863 )   $ (36,560 )   $ (40,575 )
Net cash used in financing activities $ (37,844 )   $ (9,293 )   $ (3,298 )

__________

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

  June 30, 2022   December 31, 2021
  ($ and shares in thousands)
Balance Sheet Data:      
Total current assets $ 204,898   $ 147,498
Total property, plant and equipment, net $ 1,313,927   $ 1,301,349
Total current liabilities $ 261,746   $ 187,149
Long-term debt $ 395,135   $ 394,566
Total stockholders’ equity $ 640,769   $ 629,648
Outstanding common stock shares as of   78,760     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 June 30, 2022
  Development & Production   Well Servicing and Abandonment   Corporate/Eliminations   Consolidated Company
  (in thousands)
Revenues – excluding hedges $ 247,610   $ 46,178   $     $ 293,788
Net income (loss) $ 68,885   $ 3,307   $ (28,838 )   $ 43,354
Adjusted EBITDA $ 116,942   $ 6,200   $ (13,395 )   $ 109,747
Capital expenditures $ 32,134   $ 1,066   $ 886     $ 34,086
Total assets $ 1,456,164   $ 71,543   $ 2,678     $ 1,530,385
  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  
                               

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
  June 30, 2022   March 31, 2022   June 30, 2021
($ in thousands, except prices)          
Oil, natural gas and natural gas liquids sales $ 204,706     $ 186,252     $ 129,128  
Operating income(1) $ 63,608     $ 60,162     $ 11,413  
Depreciation, depletion, and amortization (DD&A) $ 34,074     $ 35,786     $ 35,174  
Average daily production (mboe/d)   21.0       22.2       21.7  
Production (oil % of total)   100 %     100 %     100 %
Realized sales prices:          
Oil (per bbl) $ 107.31     $ 93.16     $ 65.37  
NGLs (per bbl) $     $     $  
Gas (per mcf) $     $     $  
Capital expenditures(2) $ 18,672     $ 14,622     $ 31,303  
  Utah
(Uinta basin)
  Colorado
(Piceance basin)(4)
  Three Months Ended   Three Months Ended
  June 30,
2022
  March 31,
2022
  June 30,
2021
  June 30,
2022
  March 31,
2022
  June 30,
2021
($ in thousands, except prices)                      
Oil, natural gas and natural gas liquids sales $ 35,338     $ 23,038     $ 16,199     $     $ 1,056     $ 2,438  
Operating income(1) $ 20,579     $ 11,173     $ 6,736     $     $ 610     $ 1,121  
Depreciation, depletion, and amortization (DD&A) $ 964     $ 803     $ 630     $     $ 9     $ 38  
Average daily production (mboe/d)   5.2       4.1       4.4             0.4       1.2  
Production (oil % of total)   57 %     53 %     52 %     %     %     2 %
Realized sales prices:                      
Oil (per bbl) $ 94.47     $ 83.02     $ 58.55     $     $ 89.41     $ 56.05  
NGLs (per bbl) $ 56.47     $ 47.03     $ 29.61     $     $     $  
Gas (per mcf) $ 7.35     $ 5.93     $ 3.30     $     $ 5.12     $ 3.53  
Capital expenditures(2) $ 11,563     $ 9,752     $ 9,162     $     $     $  

__________

(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 divested in January 2022.

COMMODITY PRICING

  Three Months Ended
  June 30, 2022   March 31, 2022   June 30, 2021
Weighted-average realized sales prices:          
Oil without hedges ($/bbl) $ 105.70     $ 92.25     $ 64.72  
Effects of scheduled derivative settlements ($/bbl) $ (21.92 )   $ (15.38 )   $ (18.33 )
Oil with hedges ($/bbl) $ 83.78     $ 76.87     $ 46.39  
Natural gas ($/mcf) $ 7.35     $ 5.77     $ 3.39  
NGLs ($/bbl) $ 56.47     $ 47.03     $ 29.61  
           
Average Benchmark prices:          
Oil (bbl) – Brent $ 111.98     $ 97.90     $ 69.08  
Oil (bbl) – WTI $ 108.71     $ 94.54     $ 66.03  
Natural gas (mmbtu) – Kern, Delivered(1) $ 7.36     $ 4.83     $ 3.23  
Natural gas (mmbtu) – Henry Hub(2) $ 7.50     $ 4.67     $ 2.95  

__________

(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, 2022, we had the following hedges for our crude oil production and gas purchases.

  Q3 2022   Q4 2022   FY 2023   FY 2024   FY 2025
Brent                  
Swaps                  
Hedged volume (bbls)   1,380,000     1,288,000     3,433,528     1,917,000    
Weighted-average price ($/bbl) $ 77.73   $ 76.07   $ 73.06   $ 75.52   $
Put Spreads                  
Hedged volume (bbls)   368,000     368,000     2,190,000     1,281,000    
Weighted-average price ($/bbl) $50.00/$40.00   $50.00/$40.00   $50.00/$40.00   $50.00/$40.00   $
Producer Collars                  
Hedged volume (bbls)           1,460,000     1,098,000    
Weighted-average price ($/bbl) $   $   $40.00/$106.00   $40.00/$105.00   $
Henry Hub – Natural Gas purchases                  
Consumer Collars                  
Hedged volume (mmbtu)   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   $   $
NWPL – Natural Gas purchases                  
Swaps                  
Hedged volume (mmbtu)       1,220,000     12,800,000     7,320,000     6,080,000
Weighted-average price ($/mmbtu) $   $ 6.40   $ 5.48   $ 4.27   $ 4.27
                             

OPERATING EXPENSES

  Three Months Ended
  June 30, 2022   March 31, 2022   June 30, 2021
  ($ in thousands except per boe amounts)
Lease operating expenses $ 72,455     $ 63,124     $ 45,543  
Electricity generation expenses   6,122       4,463       4,712  
Electricity sales(1)   (7,419 )     (5,419 )     (6,888 )
Transportation expenses   1,108       1,158       1,757  
Transportation sales(1)   (120 )     (45 )     (118 )
Marketing expenses         299       44  
Marketing revenues(1)         (289 )     (121 )
Derivative settlements (received) paid for gas purchases(1)   (10,188 )     (1,653 )     (1,913 )
Total operating expenses(1) $ 61,958     $ 61,638     $ 43,016  
           
Lease operating expenses ($/boe) $ 30.37     $ 26.25     $ 18.33  
Electricity generation expenses ($/boe)   2.57       1.86       1.90  
Electricity sales ($/boe)   (3.11 )     (2.25 )     (2.77 )
Transportation expenses ($/boe)   0.46       0.48       0.70  
Transportation sales ($/boe)   (0.05 )     (0.02 )     (0.05 )
Marketing expenses ($/boe)         0.13       0.02  
Marketing revenues ($/boe)         (0.12 )             (0.05 )
Derivative settlements (received) paid for gas purchases ($/boe)   (4.27 )             (0.69 )             (0.77 )
Total operating expenses ($/boe) $ 25.97     $ 25.64     $ 17.31  
Total unhedged operating expenses ($/boe)(2) $ 30.24     $ 26.33     $ 18.08  
           
Total non-energy operating expenses(3) $ 16.10     $ 13.58     $ 12.71  
Total energy operating expenses(4) $ 9.87     $ 12.06     $ 4.60  
           
Total mboe   2,386       2,406       2,485  

__________

(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, 2022   March 31, 2022   June 30, 2021
Net Oil, Natural Gas and NGLs Production Per Day(1):          
Oil (mbbl/d)          
California(2) 21.0   22.2   21.7
Utah 3.0   2.2   2.3
Colorado(3)    
Total oil 24.0   24.4   24.0
Natural gas (mmcf/d)          
California(2)    
Utah 11.0   9.2   10.3
Colorado(3)   2.3   7.2
Total natural gas 11.0   11.5   17.5
NGLs (mbbl/d)          
California(2)    
Utah 0.4   0.4   0.4
Colorado(3)    
Total NGLs 0.4   0.4   0.4
Total Production (mboe/d)(4) 26.2   26.7   27.3

__________

(1)   Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.

(2)   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 June 30, 2022, the average prices of Brent oil and Henry Hub natural gas were $111.98 per bbl and $7.50 per mmbtu respectively.

CAPITAL EXPENDITURES (ACCRUAL BASIS)

  Three Months Ended
  June 30, 2022(2)   March 31, 2022(2) June 30, 2021
  (in thousands)
Capital expenditures (accrual basis)(1) $ 34,086   $ 27,620   $ 43,461

__________

(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 June 30, 2022 and March 31, 2022 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) and Discretionary Free Cash Flow is not a measure 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, 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 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. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. We also use Adjusted EBITDA in planning our capital allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility. 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. Our 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.

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, 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, 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. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA 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, 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
  June 30, 2022   March 31, 2022   June 30, 2021
  ($ thousands, except per share amounts)
Net income (loss) $ 43,354     $         (56,810 )   $         (12,881 )
Add (Subtract):          
Losses on derivatives   51,319       132,804       44,014  
Net cash paid for scheduled derivative settlements   (37,628 )     (32,152 )     (37,431 )
Other operating expenses   353       3,769       42  
Non-recurring costs         198        
Total additions, net   14,044       104,619       6,625  
           
Income tax expense of adjustments and discrete income tax items   (4,262 )     (4,938 )     (37 )
Adjusted Net Income (Loss) $ 53,136     $ 42,871     $ (6,293 )
           
Basic EPS on Adjusted Net Income (Loss) $ 0.67     $ 0.53     $ (0.08 )
Diluted EPS on Adjusted Net Income (Loss) $ 0.64     $ 0.51     $ (0.08 )
           
Weighted average shares of common stock outstanding – basic   79,596       80,298       80,471  
Weighted average shares of common stock outstanding – diluted   83,015       84,447       80,471  
                       

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, 2022   March 31, 2022   June 30, 2021
  ($ thousands)
Net income (loss) $ 43,354     $         (56,810 )   $ (12,881 )
Add (Subtract):          
Interest expense   7,729       7,675       8,217  
Income tax expense (benefit)   2,145       (3,351 )     (72 )
Depreciation, depletion and amortization   38,055       39,777       35,850  
Losses on derivatives   51,319       132,804       44,014  
Net cash paid for scheduled derivative settlements   (37,628 )     (32,152 )     (37,431 )
Other operating expense   353       3,769       42  
Stock compensation expense   4,420       3,802       2,860  
Non-recurring costs(1)         198        
Adjusted EBITDA $ 109,747     $ 95,712     $ 40,599  
Net cash paid for scheduled derivative settlements   37,628       32,152       37,431  
Adjusted EBITDA Unhedged $ 147,375     $ 127,864     $ 78,030  
           
Net cash provided by operating activities $ 111,242     $ 48,530     $ 21,429  
Add (Subtract):          
Cash interest payments   449       14,539       288  
Cash income tax payments   2,484              
Non-recurring costs(1)         198        
Other changes in operating assets and liabilities   (4,428 )     32,445       18,882  
Adjusted EBITDA $ 109,747     $ 95,712     $ 40,599  
Net cash paid for scheduled derivative settlements   37,628       32,152       37,431  
Adjusted EBITDA Unhedged $ 147,375     $ 127,864     $ 78,030  

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

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
  June 30, 2022   March 31, 2022   June 30, 2021
  ($ in thousands except per mboe amounts)
General and administrative expenses $ 23,183     $ 22,942     $ 16,065  
Subtract:          
Non-cash stock compensation expense (G&A portion)   (4,263 )     (3,706 )     (2,763 )
Non-recurring costs         (198 )      
Adjusted General and Administrative Expenses $ 18,920     $ 19,038     $ 13,302  
           
Well servicing and abandonment segment $ 3,285     $ 3,070     $  
           
Development and production segment, and corporate $ 15,635     $ 15,968     $ 13,302  
Development and production segment, and corporate ($/boe) $ 6.55     $ 6.64     $ 5.35  
           
Total mboe   2,386       2,406       2,485  
                       

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 Three Months Ended
  June 30. 2022 March 31, 2022
  (in thousands)
Discretionary Free Cash Flow:
Operating cash flow(1) $ 111,242   $ 48,530  
Subtract:    
Maintenance capital(2)(3)   (32,134 )   (26,437 )
Fixed dividends(4)   (4,726 )   (5,236 )
Discretionary Free Cash Flow $ 74,382   $ 16,857  

__________
(1)       On a consolidated basis.

(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 which are included in the “Dividends declared on common stock” line in the the consolidated statement of stockholders’ equity.

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