(b) Reflects the conversion of the outstanding shares of Series A Preferred Stock into (1) approximately 39.6 million shares of common stock and (2) the cash payment from the IPO net proceeds of $1.60 on each pre-conversion share of Series A Preferred Stock, or approximately $60 million.
3. Pro Forma Statement of Operations Adjustments
Issuance of 2026 Notes Adjustments
(c) The issuance of the 2026 Notes was assumed to have occurred on January 1, 2017 for pro forma purposes and to have resulted in net proceeds of $391 million. As a result, borrowings under the RBL Facility would not have been necessary during this period.
The Company calculated the pro forma adjustment to increase interest expense as a result of the higher interest rate on the 2026 Notes and reversing the interest expense and other fees associated with the RBL Facility for the six months ended June 30, 2018 as follows:
|
| | | |
| (in thousands) | |
| Reversal of interest expense, unused fee and LOC fee on the RBL Facility | $ | (3,251 | ) |
| Reversal of 2026 Notes interest expense | (10,970 | ) |
| Pro Forma- RBL Facility letter of credit fee ($7.1 million outstanding at 2.625%) | 93 |
|
| Pro Forma-RBL Facility unused availability fee ($393 million availability at 0.5%) | 982 |
|
| Pro Forma 2026 Notes interest expense. | 14,000 |
|
| Pro Forma adjustment to increase interest expense | $ | 854 |
|
The effective tax rate applied to the increased interest expense was 17.3% for the six months ended June 30, 2018.
Series A Preferred Stock Conversion and Common Stock Offering Adjustments
(d) Reflects basic and diluted income per common share giving effect to the issuance of 8,695,653 shares of common stock in the IPO, assuming the IPO occurred January 1, 2017. The number of shares and net proceeds does not include shares purchased from the selling stockholders in the IPO or a number of shares issued by us equal to the number of shares purchased by us from funds affiliated with Benefit Street Partners and Oaktree Capital Management in connection with the IPO.
(e) Reflects the conversion of the outstanding shares of Series A Preferred Stock into approximately37.7 million shares of common stock, assumed to occur on January 1, 2017.
(f) Reflects the effect of reversing the Series A Preferred Stock dividends, assuming the IPO and the Series A Preferred Stock Conversion occurred January 1, 2017.
(g) Share count includes 7 million shares reserved for issuance to the general unsecured creditors resulting from the bankruptcy process.
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with theour interim unaudited consolidated financial statements and related notes presented in this Quarterly Report on formForm 10-Q (the “Quarterly Report”), as well as our audited consolidated financial statements and related notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2017 included in2023 (the “Annual Report”) filed with the prospectus.Securities and Exchange Commission (“SEC”). When we use the terms “we,” “us,” “our,” “Berry,” the “Company” or similar words unless the context otherwise requires, on or prior to the Effective Date (see below),in this report, we are referring to, as the context may require, Berry Corp., together with its subsidiaries, Berry LLC, our predecessor companyC&J Management, and following February 28, 2017, the effective date ("Effective Date") of the Amended Joint Chapter 11 Plan of Linn Acquisition Company, LLC ("Linn Acquisition") and us (the "Plan"), we are referring to Berry Corp. and its subsidiary, Berry LLC, together, the successor company, as applicable.C&J.
Our Company
We are a California-basedvalue-driven western United States independent upstream energy company engaged primarilywith a focus on onshore, low geologic risk, long-lived oil and gas reserves. We operate in two business segments: (i) exploration and production (“E&P”) and (ii) well servicing and abandonment. Our E&P assets are located in California and Utah, are characterized by high oil content and are predominantly located in rural areas with low population. Our California assets are in the development and production of conventional oil reserves located onshoreSan Joaquin basin (100% oil), while our Utah assets are in the western United States. Our long-lived, predictableUinta basin (60% oil and high margin asset base40% gas).
With respect to our E&P business in California, we focus on conventional, shallow oil reservoirs. The drilling and completion of such wells are relatively low-cost in contrast to unconventional resource plays. The California oil market is uniquely positionedprimarily tied to supportBrent-influenced pricing which has typically realized premium pricing relative to West Texas Intermediate (“WTI”). All of our objectives of generating top-tier corporate-level returns and positive free cash flow through commodity price cycles. We believe that executing our strategy across our low-declining production base and extensive inventory of identified drilling locations will resultCalifornia assets are located in long-term, capital efficient production growth as well as the ability to return excess free cash flow to stockholders.
We target onshore, low-cost, low-risk, oil-rich reservoirs in the San Joaquin basin, of California and the Uinta basin of Utah, and, to a lesser extent, the low geologic risk natural gas resource play in the Piceance basin in Colorado. In the aggregate, the Company’s assets are characterized by:
• high oil content, which makes up more than 80% of our production;
• favorable Brent-influenced crude oil pricing dynamics;
• long-lived reserves with low and predictable production decline rates;
• stable and predictable development and production cost structures;
• a large inventory of low-risk identified development drilling opportunities with attractive full-cycle
economics; and
• potential in-basin organic and strategic opportunities to expand our existing inventory with new
locations of substantially similar geology and economics.
California is and has been one of the most productive oil and natural gas regions in the world. Our asset base is concentrated in the oil-rich San Joaquin basin in California, which has more than 100150 years of production history and substantial oil remaining oil in place. As a result of these attributes, we have a strong understanding of many ofthe data generated over the basin’s geologic andlong history of production, its reservoir characteristics leading to predictable, repeatable, low-risk development opportunities.and low geological risk opportunities are generally well understood.
In California, we focus on conventional, shallow reservoirs, the drilling and completion of which are relatively low-costWe also have upstream assets in contrast to modern unconventional resource plays. Our decades-old proven completion techniques in these reservoirs include steamflood and low-volume fracture stimulation.
We own additional assetsUtah, located in the Uinta basin, in Utah, a stacked, multi-bench, light-oil-prone play with significant undeveloped resources where wewhich produce oil and natural gas at depths ranging from 4,000 feet to 8,000 feet.We have high operational control of our existing acreage (99,000 net acres), which provides significant upside for additional development and additional behind pipe potential,recompletions.
In our well servicing and abandonment segment, we operate one of the largest upstream well servicing and abandonment businesses in California, which operates as C&J. C&J provides wellsite services in California to oil and natural gas production companies, including well asservicing and water logistics. Additionally, C&J performs plugging and abandonment services on wells at the end of their productive life, which we believe creates a strategic growth opportunity for Berry based on the significant market of idle wells within California.
The core of our strategy is to create value by generating significant free cash flow in excess of our operating costs, while optimizing capital efficiency. In doing so, we seek to maximize enterprise value through overall returns. Since our initial public offering in July 2018 (“IPO”), we have demonstrated our commitment to maximizing enterprise value and returning free cash flow to shareholders through dividends and share repurchases. We have also made acquisitions that are accretive to cash flows.
Our shareholder return model is simple and demonstrates our commitment to optimize free cash flow allocation and long-term returns to our shareholders, including deleveraging through enhanced cash flows and debt reduction. As part of our strategy, we opportunistically consider bolt-on acquisitions, which contribute to our goal to maintain our existing production volumes (particularly in the Piceance basincurrent regulatory environment, when there are restrictions on the ability to obtain permits for new well drilling), and could even moderately grow production. Depending on size, bolt-on acquisitions may be funded in Colorado,whole or in part from reallocation of capital expenditures, as a prolific low geologic risk naturalway of increasing Adjusted Free Cash Flow, a non-GAAP measure, and may utilize the 80% portion of Adjusted Free Cash
Flow specified in the shareholder return model.
We review the allocations under our shareholder return model from time to time based on industry conditions, operational results and other factors. In 2024, we updated the definition of Adjusted Free Cash Flow, a non-GAAP measure, as cash flow from operations less regular fixed dividends and capital expenditures. This update better aligns with the full capital expenditure requirements of the Company. For 2023, Adjusted Free Cash Flow was defined as cash flow from operations less regular fixed dividends and maintenance capital. Maintenance capital represented the capital expenditures needed to maintain substantially the same volume of annual oil and gas play where we produce from a conventional, tight sandstone reservoir using proven slick water fracture stimulation techniquesproduction and was defined as capital expenditures, excluding, when applicable, (i) E&P capital expenditures related to strategic business expansion, such as acquisitions and divestitures of oil and gas properties and any exploration and development activities to increase recoveries.
Using SEC Pricing asproduction beyond the prior year’s annual production volumes, (ii) capital expenditures in our well servicing and abandonment segment, (iii) corporate expenditures that are related to ancillary sustainability initiatives and/or (iv) other expenditures that are discretionary and unrelated to maintenance of December 31, 2017, we had estimated total proved reserves of 141,384 MBoe. For the three months ended June 30, 2018, we had average production of approximately 26.5 MBoe/d, of which approximately 80% was oil. In California, our average productioncore business. Adjusted Free Cash Flow for prior periods has not been retroactively adjusted for the three months ended June 30, 2018 was 18.8 MBoe/d,updated definition. Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of which approximately 100% was oil.
Chapter 11 BankruptcyAdjusted Free Cash Flow is available for variable dividends, debt or share repurchases, bolt-on acquisitions or other growth opportunities, or other discretionary expenditures, since we have non-discretionary expenditures that are not deducted from this measure. Adjusted Free Cash Flow is a non-GAAP financial measure. See “Non-GAAP Financial Measures” for a reconciliation of cash provided by operating activities, our most directly comparable financial measure calculated and Our Emergence
In 2013, the Linn Entities acquired our predecessor company in exchange for LinnCo shares and the assumption of debt with an aggregate value of $4.6 billion. A severe industry downturn, coupled with high leverage and significant fixed charges, led the Linn Entities and, consequently, our predecessor company to initiate the Chapter 11 Proceedings on May 11, 2016.
On February 28, 2017, Berry LLC emerged from bankruptcy as a stand-alone company and wholly-owned subsidiary of Berry Corp. with new management, a new board of directors and new ownership. Through the Chapter 11 Proceedings, the Company significantly improved its financial position from that of Berry LLC while it was owned by the Linn Entities. These improvements included:
• the elimination of approximately $1.3 billion of debt and more than $76 million of annualized interest expense;
• the termination of, or renegotiation of more favorable terms for, several firm transportation and oil sales contracts;
• the anticipated reduction in recurring general and administrative costs as a stand-alone company by following a lean operating model.
On the Effective Date, Berry LLC consummated the following reorganization transactionspresented in accordance with GAAP, to the Plan:non-GAAP financial measure of Adjusted Free Cash Flow.
• Linn Acquisition Company, LLC transferred 100%We believe that the successful execution of our strategy across our low-declining, oil-weighted production base coupled with extensive inventory of identified drilling, sidetrack and workover locations with attractive full-cycle economics will support our objectives to generate free cash flow, which funds our operations, optimizes capital efficiency and maximizes enterprise value. We also strive to maintain an appropriate liquidity position and manageable leverage profile that will enable us to explore attractive organic and strategic growth through commodity price cycles and acquisitions. In addition to operating and developing our existing assets efficiently and strategically, we seek to acquire accretive, producing bolt-on properties that complement our existing operations, enhance our cash flows and allow us to further our strategy of keeping production essentially flat year-over-year., subject to delays in the issuance of necessary permits and approvals. For more information, see Part I, Items 1 and 2. “Business and Properties—Regulatory Matters—Regulation of the outstanding membership interestsOil and Gas Industry” in Berry LLCour Annual Report. Our strategy includes proactively engaging the many forces driving our industry and impacting our operations, whether positive or negative, to Berry Corp. pursuantmaximize the utility of our assets, create value for shareholders, and support environmental goals that align with safer, more efficient and lower emission operations.
Recent Developments
In April 2024, we purchased a 21% interest in four, two-to-three mile lateral wellbores that have been drilled and completed and are expected to the Assignment Agreement. Under the Assignment Agreement, Berry LLC became a wholly-owned operating subsidiary of Berry Corp.
• The holders of claims under the Pre-Emergence Credit Facility, received (i) their pro rata share of a cash paydown and (ii) pro rata participationbe put on production in the Emergence Credit Facility. As a result, all outstanding obligations under the Pre-Emergence Credit Facility were canceledsecond quarter of 2024. These are adjacent to our existing operations in Utah, and the agreements governingresults from these obligations were terminated.wells will be used to evaluate opportunities on our own acreage. The total purchase price was approximately $10 million, subject to customary purchase price adjustments.
• Berry LLC, as borrower, entered into the Emergence Credit Facility with the holders of claims under the Pre-Emergence Credit Facility, as lenders, and Wells Fargo Bank, N.A., as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments.
• The holders of Berry LLC’s Unsecured Notes received a right to their pro rata share of either (i) 32,920,000 shares of common stock in Berry Corp. or, for those non-accredited investors that irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool and (ii) specified rights to participate the Berry Rights Offerings. As a result, all outstanding obligations under the Unsecured Notes were canceled and the indentures and related agreements governing these obligations were terminated.
• The holders of the Unsecured Claims received a right to their pro rata share of either (i) 7,080,000 shares of common stock in Berry Corp. or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Cash Distribution Pool. The obligations arising from the Unsecured Claims were extinguished.
• Berry LLC settled all intercompany claims against LINN Energy and its affiliates pursuant to a settlement agreement approved as part of the Plan and the Confirmation Order. The settlement agreement provided Berry LLC with a $25 million general unsecured claim against LINN Energy which Berry LLC has fully reserved.
How We Plan and Evaluate Operations
Our management team usesWe use the following metrics to manage and assess the performance of our operations: (a) Adjusted EBITDA; (b) operating expenses;Adjusted Free Cash Flow (c) environmental, health & safety (“EH&S”)production from our E&P business (d) E&P field operations measures; (e) HSE results; (d) taxes, other than income taxes; (e)(f) general and administrative expenses; (f) production; and (g) levered free cash flow.
the performance of our well servicing and abandonment operations based on activity levels, pricing and relative performance for each service provided.
Adjusted EBITDA
Adjusted EBITDA is the primary financial and operating measurement that our management uses to analyze and monitor the operating performance of both our business.E&P business and CJWS. We definealso use Adjusted EBITDA in
planning our capital expenditure allocation to sustain production levels and determining our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility (defined below in “—Liquidity and Capital Resources”). Adjusted EBITDA is a non-GAAP financial measure that we define as earnings before interest expense; income taxes; depreciation, depletion, and amortization and accretion; exploration expense;(“DD&A”); derivative gains or losses net of cash received or paid
for scheduled derivative settlements; impairments; stock compensation expense; and other unusual out-of-period and infrequent items, including restructuringitems. See “Management’s Discussion and reorganization costs.
Operating expenses
We defineAnalysis—Non-GAAP Financial Measures” for a reconciliation of net income (loss) and net cash provided (used) by operating expenses as lease operating expenses, electricity expenses, transportation expenses,activities, our most directly comparable financial measures calculated and marketing expenses, offset bypresented in accordance with GAAP, to the third-party revenues generated by electricity, transportation and marketing activities. The electricity, transportation and marketing activity related revenues are viewed and treated internally as a reduction to operating costs when tracking and analyzing the economicsnon-GAAP financial measure of development projects and the efficiency of our hydrocarbon recovery. Overall, operating expenseAdjusted EBITDA. This supplemental non-GAAP financial measure is used by management as a measure of the efficiency with which operations are performing.
Environmental, health & safety
We are committed to good corporate citizenship in our communities, operating safely and protecting the environment and our employees. We monitor our EH&S performance through various measures, holding our employees and contractors to high standards. Meeting corporate EH&S metrics is a partexternal users of our incentive programs for all employees.financial statements, such as industry analysts, investors, lenders and rating agencies.
Adjusted Free Cash Flow
Taxes, other than income taxes
Taxes, other than income taxes includes severance taxes, ad valoremWe utilize our shareholder return model to determine the allocation of our Adjusted Free Cash Flow.This shareholder return model is simple and property taxes, greenhouse gas (GHG) allowances,demonstrates our commitment to optimize free cash flow allocation and long-term returns to our shareholders, including deleveraging through enhanced cash flows and debt reduction. The allocations of Adjusted Free Cash Flow, last updated at the beginning of 2023, are intended to be (a) 80% primarily in the form of debt repurchases, stock repurchases, strategic growth, and acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of Directors in light of then existing conditions and circumstances, including our earnings, financial condition, restrictions in financing agreements, business conditions and other taxes. We include these taxes when analyzing the economics of development projects and the efficiency of our hydrocarbon recovery; however, we do not include these taxes in our operating expenses.factors.
General and administrative expenses
We monitor our cash general and administrative expenses as a measure of the efficiency of our overhead activities. Such expenses are a key component of the appropriate level of support our corporate and professional team provides to the development of our assets and our day-to-day operations.
Production
Oil and gas production is a key driver of our operating performance, an important factor to the success of our business, and used in forecasting future development economics. We measure and closely monitor production on a continuous basis, adjusting our property development efforts in accordance with the results. We track production by commodity type and compare it to prior periods and expected results.
Levered free cash flowE&P Field Operations
Levered free cash flow reflectsOverall, management assesses the efficiency of our financial flexibility;E&P field operations by considering core E&P operating expenses together with our cogeneration, marketing and transportation activities. In particular, a core component of our E&P operations in California is steam, which we use to lift heavy oil to the surface. We operate several cogeneration facilities to produce some of the steam needed in our operations. In comparing the cost effectiveness of our cogeneration plants against other sources of steam in our operations, management considers the cost of operating the cogeneration plants, including the cost of the natural gas purchased to operate the facilities, against the value of the steam and electricity used in our E&P field operations and the revenues we receive from sales of excess electricity to the grid. We strive to minimize the variability of our fuel gas costs for our California steam operations with natural gas purchase hedges. Consequently, the efficiency of our E&P field operations are impacted by the cash settlements we receive or pay from these derivatives. We also have contracts for the transportation of fuel gas from the Rockies, which has historically been cheaper than the California markets. With respect to transportation and marketing, management also considers opportunistic sales of incremental capacity in assessing the overall efficiencies of E&P operations.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Electricity generation expenses include the portion of fuel, labor, maintenance, and tools and supplies from two of our cogeneration facilities allocated to electricity generation expense; the remaining cogeneration expenses are included in lease operating expense. Transportation expenses relate to our costs to transport the oil and gas that we produce within our properties or move it to planthe market. Marketing expenses mainly relate to natural gas purchased from third parties that moves through our internal growth capital expenditures. We define levered free cash flow as Adjusted EBITDA less capital expenditures, interest expensegathering and dividends. Levered free cash flowprocessing systems and then sold to third parties. Electricity revenue is from the sale of excess electricity from two of our primary metric usedcogeneration facilities to a California utility company under long-term contracts at market prices. These cogeneration facilities are sized to satisfy the steam needs in planning capital allocationtheir respective fields, but the corresponding electricity produced is more than the electricity that is currently required for maintenancethe operations in those fields. Transportation sales relate to water and internal growth opportunitiesother liquids that we transport on our systems on behalf of third parties and marketing revenues represent sales of natural gas purchased from and sold to third parties.
Health, Safety & Environmental
Like other companies in the oil and gas industry, the operations of both our E&P business and C&J are subject to complex federal, state and local laws and regulations that govern health and safety, the release or discharge of materials, and land use or environmental protection that may restrict the use of our properties and operations, increase our costs or lower demand for or restrict the use of our products and services. Please see “—Regulatory Matters” in this Quarterly Report as well as hedging needsPart I, Items 1 and serves as2. “Business and Properties—Regulatory Matters” and Part I, Item 1A. “Risk Factors” in our Annual Report for a measure for assessingdiscussion of the potential impact that government regulations, including those regarding HSE matters, may have upon our financial performancebusiness, operations, capital expenditures, earnings and measuringcompetitive position.
As part of our abilitycommitment to generate excess cash fromcreating long-term value, we strive to conduct our operations after servicing indebtedness.
Non-GAAP Financial Measures
Adjusted EBITDA, Levered Free Cash Flowin an ethical, safe and Adjusted Net Income (Loss)
Adjusted EBITDAresponsible manner, to protect the environment and Adjusted Net Income (Loss) are not measures of net income (loss) and Levered Free Cash Flow is not a measure of cash flow, in all cases, as determined by GAAP. Adjusted EBITDA and Levered Free Cash Flow are supplemental non-GAAP financial measures used by management and external usersto take care of our financial statements, such as industry analysts, investors, lenders and rating agencies.
Adjusted Net Income (Loss) excludes the impact of unusual, out-of-period and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We define Adjusted Net Income (Loss) as net income (loss) attributable to common stockholders adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, other unusual, out-of-period and infrequent items, including restructuring and reorganization costspeople and the income tax expense or benefitcommunities in which we live and operate. We also seek proactive and transparent engagement with regulatory agencies, the communities in which we operate and our other stakeholders in order to realize the full potential of these adjustments using our effective tax rate.
We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, amortization and accretion; exploration expense; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring and reorganization costs. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.
Our management believes Adjusted EBITDA provides useful informationresources in assessing our financial condition, results of operations and cash flows and is widely used by the industrya timely fashion that safeguards people and the investment community. The measure also allowsenvironment and complies with existing laws and regulations. We monitor our managementHSE performance through various measures, and we hold our employees and contractors to more effectively evaluatehigh standards. Meeting corporate HSE metrics, including with respect to HSE incidents and spill prevention, is a part of 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 allocationshort-term incentive program for maintenance and 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.all employees.
While Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered 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. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Net Income (Loss) and Levered Free Cash Flow should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
Adjusted General and Administrative Expenses
Adjusted General and Administrative Expenses is a supplemental non-GAAP financial measure that is used by management. We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-recurring restructuring and other costs and non-cash stock compensation expense. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively comparemonitor 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. Adjusted General and Administrative Expenses should not be considered as an alternative to, or more meaningful than,cash general and administrative expenses as determined in accordance with GAAP. Our computations of Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures of other companies.
The following tables present reconciliationsa measure of the non-GAAP financial measure Adjusted EBITDAefficiency of our overhead activities. Such expenses are a key component of the appropriate level of support our corporate and Levered Free Cash Flowprofessional team provides to the GAAP financial measures of net income (loss) and net cash provided or used by operating activities for each of the periods indicated. |
| | | | | | | | | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) |
| | Three Months Ended | Three Months Ended | Three Months Ended | | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 | | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| | (in thousands) |
| Adjusted EBITDA reconciliation to net income (loss): | | | | | | | |
| Net income (loss) | $ | (28,061 | ) | $ | 6,410 |
| $ | 12,120 |
| | $ | (21,651 | ) | $ | 23,497 |
| $ | (502,964 | ) |
| Add (Subtract): | | | | | | | |
| Depreciation, depletion, amortization and accretion | 21,859 |
| 18,429 |
| 20,549 |
| | 40,288 |
| 27,571 |
| 28,149 |
|
| Interest expense | 9,155 |
| 7,796 |
| 4,885 |
| | 16,951 |
| 6,600 |
| 8,245 |
|
| Income tax expense (benefit) | (5,476 | ) | 939 |
| 7,961 |
| | (4,537 | ) | 15,435 |
| 230 |
|
| Derivative (gain) loss | 78,143 |
| 34,644 |
| (23,962 | ) | | 112,787 |
| (48,085 | ) | (12,886 | ) |
| Net cash received (paid) for scheduled derivative settlements | (28,261 | ) | (17,849 | ) | 4,725 |
| | (46,110 | ) | 5,856 |
| 534 |
|
| (Gain) loss on sale of assets and other | 123 |
| — |
| 5 |
| | 123 |
| 5 |
| (183 | ) |
| Stock compensation expense | 1,278 |
| 1,042 |
| — |
| | 2,320 |
| — |
| — |
|
| Non-recurring restructuring and other costs | 1,714 |
| 2,047 |
| 16,846 |
| | 3,761 |
| 24,442 |
| — |
|
| Reorganization items, net | (456 | ) | (8,955 | ) | (713 | ) | | (9,411 | ) | 593 |
| 507,720 |
|
| Adjusted EBITDA | 50,018 |
| 44,503 |
| 42,416 |
| | 94,521 |
| 55,914 |
| 28,845 |
|
| Net cash (received) paid for scheduled derivative settlements | 28,261 |
| 17,849 |
| (4,725 | ) | | 46,110 |
| (5,856 | ) | (534 | ) |
| Adjusted EBITDA unhedged | $ | 78,279 |
| $ | 62,352 |
| $ | 37,691 |
| | $ | 140,631 |
| $ | 50,058 |
| $ | 28,311 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) |
| | Three Months Ended | Three Months Ended | Three Months Ended | | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 | | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| | (in thousands) |
| Adjusted EBITDA and Levered Free Cash Flow reconciliation to net cash provided (used) by operating activities: | | | | | | | |
| Net cash provided (used) by operating activities | $ | (77,394 | ) | $ | 27,846 |
| $ | 20,703 |
| | $ | (49,548 | ) | $ | 44,937 |
| $ | 22,431 |
|
| Add (Subtract): | | | | | | | |
| Cash interest payments | 644 |
| 2,654 |
| 4,860 |
| | 3,298 |
| 5,261 |
| 8,057 |
|
| Cash income tax payments | — |
| — |
| 1,168 |
| | — |
| 1,168 |
| — |
|
| Cash reorganization item (receipts) payments | 1,047 |
| 305 |
| (1,384 | ) | | 1,352 |
| (792 | ) | 11,838 |
|
| Non-recurring restructuring and other costs | 1,714 |
| 2,047 |
| 16,846 |
| | 3,761 |
| 24,442 |
| — |
|
| Derivative early termination payment | 126,949 |
| — |
| — |
| | 126,949 |
| — |
| — |
|
| Other changes in operating assets and liabilities | (2,942 | ) | 11,651 |
| 223 |
| | 8,709 |
| (19,102 | ) | (13,323 | ) |
| Other, net | — |
| — |
| — |
| | — |
| — |
| (158 | ) |
| Adjusted EBITDA | 50,018 |
| 44,503 |
| 42,416 |
| | 94,521 |
| 55,914 |
| 28,845 |
|
| Subtract: | | | | | | | |
| Capital expenditures | (39,196 | ) | (15,732 | ) | (24,697 | ) | | (54,928 | ) | (34,050 | ) | (5,407 | ) |
| Interest expense | (9,155 | ) | (7,796 | ) | (4,885 | ) | | (16,951 | ) | (6,600 | ) | (8,245 | ) |
| Dividends | (5,650 | ) | (5,650 | ) | (5,404 | ) | | (11,301 | ) | (7,196 | ) | — |
|
| Levered Free Cash Flow | (3,983 | ) | 15,325 |
| 7,430 |
| | 11,341 |
| 8,068 |
| 15,193 |
|
| Net cash (received) paid for scheduled derivative settlements | 28,261 |
| 17,849 |
| (4,725 | ) | | 46,110 |
| (5,856 | ) | (534 | ) |
| Levered Free Cash Flow unhedged | $ | 24,278 |
| $ | 33,174 |
| $ | 2,705 |
| | $ | 57,451 |
| $ | 2,212 |
| $ | 14,659 |
|
The following table presents a reconciliation of the non-GAAP financial measure Adjusted Net Income (Loss) to the GAAP financial measure of Net income (loss) attributable to common stockholders.
|
| | | | | | | | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) |
| | Three Months Ended | Three Months Ended | Three Months Ended | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| Adjusted Net Income (Loss) reconciliation to Net income (loss) attributable to common stockholders | (in thousands) |
| Net income (loss) attributable to common stockholders | $ | (33,711 | ) | $ | 760 |
| $ | 6,716 |
| $ | (32,952 | ) | $ | 16,301 |
| $ | (502,964 | ) |
| | | | | | | |
| Add (Subtract): | | | | | | |
| Losses (gains) on oil and natural gas derivatives | 78,143 |
| 34,644 |
| (23,962 | ) | 112,787 |
| (48,085 | ) | (12,886 | ) |
| Net cash received (paid) for scheduled derivative settlements | (28,261 | ) | (17,849 | ) | 4,725 |
| (46,110 | ) | 5,856 |
| 534 |
|
| Losses (gains) on sale of assets and other, net | 123 |
| — |
| 5 |
| 123 |
| 5 |
| (183 | ) |
| Non-recurring restructuring and other costs | 1,714 |
| 2,047 |
| 16,846 |
| 3,761 |
| 24,442 |
| — |
|
| Reorganization items, net | (456 | ) | (8,955 | ) | (713 | ) | (9,411 | ) | 593 |
| 507,720 |
|
| | 51,263 |
| 9,887 |
| (3,099 | ) | 61,150 |
| (17,189 | ) | 495,185 |
|
| Income tax (expense) benefit of adjustments at effective tax rate | (8,370 | ) | (1,263 | ) | 1,229 |
| (10,594 | ) | 6,815 |
| n/a |
|
| Adjusted Net Income (Loss) | $ | 9,182 |
| $ | 9,384 |
| $ | 4,846 |
| $ | 17,604 |
| $ | 5,927 |
| $ | (7,779 | ) |
The following table presents a reconciliation of the non-GAAP financial measure Adjusted General and Administrative Expenses to the GAAP financial measure of general and administrative expenses for each of the periods indicated. |
| | | | | | | | | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) |
| | Three Months Ended | Three Months Ended | Three Months Ended | | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 | | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| | (in thousands) |
| Adjusted General and Administrative Expense reconciliation to general and administrative expenses: | | | | | | | |
| General and administrative expenses | $ | 12,482 |
| $ | 11,985 |
| $ | 22,257 |
| | $ | 24,466 |
| $ | 31,800 |
| $ | 7,964 |
|
| Subtract: | | | | | | | |
| Non-recurring restructuring and other costs | (1,714 | ) | (2,047 | ) | (16,846 | ) | | (3,761 | ) | (24,442 | ) | — |
|
| Non-cash stock compensation expense | (1,260 | ) | (1,019 | ) | — |
| | (2,279 | ) | — |
| — |
|
| Adjusted General and Administrative Expenses | $ | 9,508 |
| $ | 8,919 |
| $ | 5,411 |
| | $ | 18,426 |
| $ | 7,358 |
| $ | 7,964 |
|
| | | | | | | | |
Factors Affecting the Comparability of Our Financial Condition and Results of Operations
Basis of Presentation and Fresh-Start Accounting
Upon Berry LLC’s emergence from bankruptcy, we adopted fresh-start accounting, which, with the recapitalization upon emergence from bankruptcy, resulted in Berry Corp. becoming the financial reporting entity in our corporate group.
Unless otherwise noted or suggested by context, all financial information and data and accompanying financial statements and corresponding notes, as contained in this Quarterly Report on Form 10-Q, on or prior to the Effective Date, reflect the actual historical results of operations and financial conditiondevelopment of our predecessor company for the periods presentedassets and do not give effect to the Plan or any of the transactions contemplated thereby or the adoption of fresh-start accounting. Following the Effective Date, they reflect the actual historical results ofour day-to-day operations.
Well Servicing and Abandonment Operations Performance
We consistently monitor our well servicing and abandonment operations performance with revenue and financial condition of Berry Corp. on a consolidated basiscost by service and give effect to the Plan and any of the transactions contemplated thereby and the adoption of fresh-start accounting. Thus, the financial information presented herein on or prior to the Effective Date is not comparable to Berry Corp.’s performance or financial condition after the Effective Date. As a result, “black-line” financial statements are presented to distinguish between Berry LLC as the predecessor and Berry Corp. as the successor.
Berry Corp.’s financial statements reflect the application of fresh-start accounting under GAAP. GAAP requires that the financial statements, for periods subsequent to the Chapter 11 Proceeding, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on Berry Corp.’scustomer, as well as Berry LLC’s statementsAdjusted EBITDA for this business.
Business Environment, Market Conditions and Outlook
Our operating and financial results, and those of the cash distributions from the Cash Distribution Pooloil and gas industry as “liabilities subjecta whole, are heavily influenced by commodity prices, including differentials, which have and may continue to, compromise.” Prepetition unsecuredfluctuate significantly as a result of numerous market-related variables, including global geopolitical and under-secured obligations that wereeconomic conditions, and local and regional market factors and dislocations. Oil and natural gas prices have been, and may remain, volatile. As a net gas purchaser, our operating costs are generally expected to be more impacted by the bankruptcy reorganization processvolatility of natural gas prices than our gas sales.
Our well servicing and abandonment business is dependent on expenditures of oil and gas companies, which can in part reflect the volatility of commodity prices, as well as the impact from changes in the regulatory environment. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells historically have been classified as “liabilities subjectrelatively stable and predictable when production is steady. Additionally, our customers’ requirements to compromise”plug and abandon wells are largely driven by regulatory requirements that are less dependent on our balance sheet.commodity prices.
The main actions we took affecting comparability between periods presented includeIn October 2022, OPEC+ announced initial reductions in production quotas that were extended through December 2023. In June 2023, OPEC+ further reduced production quotas from January 2024 through December 2024, which extended the reorganizationOctober 2022 curtailment. In November 2023, OPEC+ announced additional voluntary cuts, for a combined total of Berry LLC2.2 mmbbls/d, beginning January 2024 through bankruptcy, entryMarch 2024. In March 2024, OPEC+ agreed to extend the 2.2 mmbbls/d cut into the RBL Facility, issuancesecond quarter of 2024.
Sanctions and import bans on Russian oil have been implemented by various countries in response to the ongoing conflict in Ukraine, further altering flows of global oil supply. Oil and natural gas prices could decrease or increase with any changes in demand due to, among other things, the ongoing conflict in Ukraine, the ongoing conflict in the Middle East, international sanctions, speculation as to future actions by OPEC+, higher gas prices, high interest rates, inflation and government efforts to reduce inflation, and possible changes in the overall health of the 2026 Notes, dividends onglobal economy, including increased volatility in financial and conversion of Series A Preferred Stockcredit markets or a prolonged recession. Further, the volatility in oil and completion of the IPO. These actions are described above under "-Chapter 11 Bankruptcy and our Emergence" and below in "Liquidity and Capital Resources."
Capital Expenditures and Capital Budget
For the three and six months ended June 30, 2018, our capital expenditures were approximately $39 million and $54 million respectively, on an accrual basis excluding acquisitions.
Following Berry LLC’s emergence from bankruptcy and separation from the Linn Entities, we increased our pace of development and have continued to do so in 2018. Our 2018 anticipated capital expenditure budget of approximately $140 to $160 million represents an increase of approximately 107% over our 2017 capital expenditures, including the successor and predecessor periods, of approximately $73 million. Based on current commodity prices and a drilling success rate comparable to our historical performance, we believe we will be able to fund our 2018 capital program exclusively with our levered free cash flow. We expect to:
• employ:
• three drilling rigs in California for the remainder of 2018;
• one additional drilling rig assigned to drilling opportunities in Utah in the second half of 2018;
• drill approximately 180 to 190 gross development wells in 2018, of which we expect at least
175 will be in California.
The table below sets forth the expected allocation of our 2018 capital expenditure budget by area as compared to the allocation of our 2017 capital expenditures.
|
| | | | | |
| Capital Expenditure by Area |
| 2018 Budget | 2017 Actual |
| (in millions) |
California | $122-136 |
|
| $71 |
|
Uinta | 12-16 |
| 1 |
|
Piceance | 1-2 |
| 1 |
|
East Texas | — |
| — |
|
Corporate | 5-6 |
| — |
|
Total | $140-160 |
|
| $73 |
|
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas prices could accelerate a transition away from fossil fuels, resulting in reduced demand over the longer term. To what extent these and NGLs, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination ofexternal factors (such as government action with respect to climate change regulation) ultimately impact our development drilling program could result in a reduction of proved reserve volumes and materially affect ourfuture business, liquidity, financial condition, and results of operations.operations is highly uncertain and dependent on numerous factors, including future developments, that are not within our control and cannot be accurately predicted.
Chevron North Midway-Sunset Acquisition
In April 2018, we completed the Chevron North Midway-Sunset Acquisition. We assumed a drilling commitment for the 214 acres of approximately $34.5 million to drill 115 wells, of which none have been drilled, on or before April 1, 2020, which has been extended to April 1, 2022, and would assume an additional 40 well drilling commitment if we exercise our option on the 490 acres. We paid noAdditionally, like other consideration for the acquisition. Our drilling commitment will be tolled for a month for each consecutive 30-day period for which the posted price of WTI is less than $45 per barrel. Our 2018 anticipated capital expenditure budget does not currently include funding for drilling wells against the assumed drilling commitment, but we have designated funds for drilling appraisal wells to determine whether to exercise the option. This transaction is consistent with
our business strategy to investigate areas beyond our known productive areas.
Commodity Derivatives
Recently, we have utilized swaps, puts and calls to hedge a portion of our forecasted production and reduce exposure to fluctuations in oil and natural gas prices. Swap contracts are designed to provide a fixed price. For fixed-price swaps, we make settlement payments for prices above the indicated weighted-average price per barrel of Brent and receive settlement payments for prices below the indicated weighted average price per barrel of Brent. For oil basis swaps, we make settlement payments if the difference between Brent and WTI is greater than the indicated weighted average price per barrel and receive settlement
payments if the difference between Brent and WTI is below the indicated weighted average price per barrel. We earn a premium on our sold oil calls at the time of sale. We make net settlement payments for prices above the indicated weighted-average price per barrel of Brent. If the calls expire unexercised, no payments are received. For our purchased puts, we would receive settlement payments for prices below the indicated weighted-average price per barrel of Brent. Currently, our hedging program mainly consists of swaps and put options.
Our open derivative positions as of June 30, 2018 were as follows:
|
| | | | | | | | | |
| | 2018 | 2019 | 2020 |
| Sold Oil Calls (ICE Brent): | | | |
| Hedged volume (MBbls) | 186 |
| — |
| — |
|
| Weighted average price ($/Bbl) | $ | 81.67 |
| $ | — |
| $ | — |
|
| Purchased put options (ICE Brent) : | | | |
| Hedged volume (MBbls) | — |
| 2,835 |
| 455 |
|
| Weighted average price ($/Bbl) | $ | — |
| $ | 65.00 |
| $ | 65.00 |
|
| Fixed Price Swaps (ICE Brent) | | | |
| Hedged volume (MBbls) | 1,932 |
| 900 |
| — |
|
| Weighted average price ($/Bbl) | $ | 75.13 |
| $ | 75.66 |
| $ | — |
|
| Oil basis differential positions: | | | |
| ICE Brent - NYMEX WTI basis swaps | | | |
| Hedged volume (MBbls) | 184 |
| 182.5 |
| — |
|
| Weighted average price ($/Bbl) | $ | 1.29 |
| $ | 1.29 |
| $ | — |
|
The following table summarizes the historical results of our hedging activities.
|
| | | | | | | | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) |
| | Three Months Ended | Three Months Ended | Three Months Ended | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| Crude Oil (per Bbl): | | | | | | |
| Realized price, before the effects of derivative settlements | $ | 67.93 |
| $ | 62.14 |
| $ | 44.27 |
| $ | 65.06 |
| $ | 44.34 |
| $ | 46.94 |
|
| Effects of derivative settlements | $ | (14.71 | ) | $ | (9.40 | ) | $ | 2.70 |
| $ | (12.08 | ) | $ | 2.50 |
| $ | 0.46 |
|
| | | | | | | |
We expect our operations to generate substantial cash flows at current commodity prices. We have protected a portion of our anticipated cash flows through 2020 as part of our crude oil hedging program. Our low-decline production base, coupled with our stable operating cost environment, affords an ability to hedge a material amount of our future expected production.
In May 2018, we elected to terminate outstanding commodity derivative contracts for all WTI oil swaps and certain WTI/Brent basis swaps for July 2018 through December 2019 and all WTI oil sold call options for July 2018 through June 2020. Termination costs totaled approximately $127 million and were calculated in accordance with a bilateral agreement on the cost of elective termination included in these derivative contracts; the present value of the contracts using the forward price curve as of the date termination was elected. No penalties were charged as a result of the elective termination. Concurrently, Berry Corp. entered into commodity derivative contracts consisting of Brent oil swaps for July 2018 through March 2019 and Brent oil purchased put options for January 2019 through March 2020. These Brent oil swaps hedge 1.8 MMBbls in 2018 and 0.9 MMBbls in 2019 at a weighted average price of $75.66. These Brent oil purchased put options provide a weighted average price floor of $65.00 for 2.8 MMBbls in 2019 and 0.5 MMBbls in 2020. We effected these transactions to move from a WTI-based position to a Brent-based position as well as bring our hedged pricing more in line with current market pricing.
Income Taxes
Prior to the Effective Date, Berry LLC was a limited liability company treated as a disregarded entity for federal and state income tax purposes, with the exception of the state of Texas. Limited liability companies are subject to Texas margin tax. As such, with the exception of the state of Texas, Berry LLC was not a taxable entity, it did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of Berry LLC. Upon emergence from bankruptcy, Berry Corp. acquired the assets of Berry LLC in a taxable asset acquisition as part of the restructuring. Consequently, we are now taxed as a corporation and have no net operating loss carryforwards for the periods prior to February 28, 2017.
On December 22, 2017, the U.S. the Tax Cuts and Jobs Act (the “Act”) which made significant changes to the Internal Revenue Code of 1986, including lowering the maximum federal corporate rate from 35 percent to 21 percent and imposing limitations on the use of net operating losses arising in taxable years ending after December 31, 2017. This was the key contributor to the decrease in our effective rate from 40% in the 2017 Successor periods to 16% and 17% in the three and six months ended June 30, 2018, respectively. We anticipate earnings for fiscal year 2018, in part due to the termination and resetting of our hedge positions in May 2018. These earnings consequently allow for the release of our valuation allowance, resulting in an effective tax rate less than the maximum federal and applicable state tax rate for the six months ended June 30, 2018.There were no current income taxes during the six months ended June 30, 2018
Our accounting for the U.S. Tax Reform Act is incomplete. As noted at year-end, however, we were able to reasonably estimate certain effects and, therefore, recorded provisional adjustments to income tax expense for the revaluation of deferred tax assets and liabilities from 35 percent to 21 percent associated with the reduction in the U.S. corporate income tax rate, and for a valuation allowance on certain deferred tax assets impacted by the Act. We have not revised any of the 2017 provisional estimates. Any subsequent adjustments to these amounts will be recorded to income tax expense in the quarter the analysis is complete.
Business Environment and Market Conditions
The oil and gas industry, is heavily influenced by commodity prices. Sinceour operations are subject to stringent federal, state and local laws and regulations relating to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the latter halfenvironment, or transportation, marketing and sale of 2014, commodity prices have declinedour products. Federal, state and remained at relatively low levels through the middlelocal agencies may assert overlapping authority to regulate in these areas. See Part I, Items 1 and 2. “Business and Properties—Regulatory Matters—Regulation of 2017 but have generally risen since then.Health, Safety and Environmental Matters” in our Annual Report for a description of laws and regulations that affect our business. For example, the Brent crude oil futures contract prices declined from a high of over $100.16 per Bbl on June 24, 2014more information related to a low of $40.67 per Bbl on January 20, 2016. The Henry Hub spot price for natural gas has also declined since 2014, though reduced gas prices are a net benefitregulatory risks, see Part I, Item 1A. “Risk Factors—Risks Related to Our Operations and Industry” in our results of operations. While oil prices remain lower than the 2014 averages, they have improved since early 2016. Annual Report.
Commodity Pricing and Differentials
Our revenue, costs, profitability, shareholder returns and future growth are highly dependent on the prices we receive for our oil and natural gas production.
The following table presentsproduction, as well as the average Intercontinental Exchange Brent oil ("Brent"), New York Mercantile Exchange ("NYMEX") WTI oil and NYMEX Henry Hubprices we pay for our natural gas prices for the three months ended June 30, 2018, March 31, 2018 and June 30, 2017, the six months ended June 30, 2018, the four months ended June 30, 2017 and the two months ended February 28, 2017:
|
| | | | | | | | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) |
| | Three Months Ended | Three Months Ended | Three Months Ended | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| ICE (Brent) oil ($/Bbl) | $ | 74.87 |
| $ | 67.16 |
| $ | 50.90 |
| $ | 71.01 |
| $ | 51.31 |
| $ | 55.72 |
|
| NYMEX (WTI) oil ($/Bbl) | $ | 67.76 |
| $ | 62.87 |
| $ | 48.28 |
| $ | 65.32 |
| $ | 48.63 |
| $ | 53.04 |
|
| NYMEX Henry Hub natural gas ($MMBtu) | $ | 2.80 |
| $ | 3.00 |
| $ | 3.18 |
| $ | 2.90 |
| $ | 3.05 |
| $ | 3.66 |
|
Oil prices and differentials will continue to bepurchases, which are affected by a variety of factors, including worldwidethose discussed in Part I, Item 1A. “Risk Factors” in our Annual Report.
Oil and regional economic conditions, transportation costs, imports, political conditions in producing regions, exploration levels, inventory levels, the actionsnatural gas prices and differentials may fluctuate significantly as a result of the Organizationnumerous market-related variables. We use derivatives to hedge a portion of Petroleum Exporting Countries ("OPEC")our forecasted oil and other state-controlled oil companies and significant producers, local pricing, gathering facility and transportation dynamics, exploration, development,gas production and transportation costs,gas purchases to reduce our exposure to fluctuations in oil and natural gas prices. The following table sets forth certain average benchmark prices, average realized prices and price realizations as a percentage of average benchmark prices for our products for the effectsperiods indicated below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2024 | | December 31, 2023 | | March 31, 2023 |
| Average Price | | Realization(1) | | Average Price | | Realization(1) | | Average Price | | Realization(1) |
| Sales of Crude Oil (per bbl): | | | | | | | | | | | |
| Brent | $ | 81.76 | | | | | $ | 82.85 | | | | | $ | 82.16 | | | |
| | | | | | | | | | | |
| Realized price without derivative settlements | $ | 75.31 | | | 92% | | $ | 76.00 | | | 92% | | $ | 74.69 | | | 91% |
| Effects of derivative settlements | (2.17) | | | | | (3.35) | | | | | (3.65) | | | |
| Realized price with derivative settlements | $ | 73.14 | | | 89% | | $ | 72.65 | | | 88% | | $ | 71.04 | | | 86% |
| | | | | | | | | | | |
| WTI | $ | 77.02 | | | | | $ | 78.49 | | | | | $ | 76.15 | | | |
| | | | | | | | | | | |
| Realized price without derivative settlements | $ | 75.31 | | | 98% | | $ | 76.00 | | | 97% | | $ | 74.69 | | | 98% |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Purchased Natural Gas (per mmbtu) | | | | | | | | | | | |
| Average Monthly Settled Price - NWPL | $ | 3.41 | | | | | $ | 4.53 | | | | | $ | 22.36 | | | |
| | | | | | | | | | | |
| Realized price without derivative settlements | $ | 3.99 | | | 117% | | $ | 5.29 | | | 117% | | $ | 20.74 | | | 93% |
| Effects of derivative settlements | 0.92 | | | | | 0.44 | | | | | (11.86) | | | |
| Realized price with derivative settlements | $ | 4.91 | | | 144% | | $ | 5.73 | | | 126% | | $ | 8.88 | | | 40% |
| | | | | | | | | | | |
__________
(1) Represents the percentage of conservation, weather, geophysical and technology, refining and processing disruptions, exchange rates, taxes andour realized prices compared to the indicated index.
regulations and other matters affecting the supply and demand dynamics for oil, technological advances, regional market conditions, transportation capacity and costs in producing areas and the effect of changes in these variables on market perceptions.Oil Prices
California oil prices are Brent-influenced as California refiners import more than 50%approximately 75% of the state’s demand from foreignOPEC+ countries and other waterborne sources. There is a closer correlation of prices in California to Brent pricing than to WTI. Without the higher costs associated with importing crude via rail or supertanker, weWe believe our in-state production and low-cost transportation of crude, coupled withthat receiving Brent-influenced pricing will allow uscontributes to our ability to continue to realizerealizing strong cash margins in California.
Prices and differentials for NGLs Though the California market generally receives Brent-influenced pricing, California oil prices are related to thealso determined by local supply and demand dynamics, including third-party transportation and infrastructure capacity. In the fourth quarter of 2023, oil prices decreased relative to the third quarter of 2023. Prices were relatively flat in the first quarter in 2024 relative to the fourth quarter of 2023.
Utah oil prices have historically traded at a discount to WTI as the local refineries are designed for Utah’s unique oil characteristics and the remoteness of the assets makes access to other markets logistically challenging. However, we have high operational control of our existing acreage, which provides significant upside for additional vertical and/or horizontal development wells and recompletions. For the three months ended March 31, 2024, December 31, 2023, and March 31, 2023, Utah had an average realized oil price of $65.79, $67.20, and $63.27, respectively, compared to an average Brent oil price of $81.76, $82.85, and $82.16 for the products making up these liquids. Somesame periods
Gas Prices
For our California steam operations, the price we pay for fuel gas purchases is generally based on the Northwest, Rocky Mountains index for the purchases made in the Rockies and the SoCal Gas city-gate index for the purchases made in California. We currently buy most of oil while othersour gas in the Rockies. Now that we are affected bypurchasing a majority of our fuel gas in the Rockies, most of the purchases made in California use the SoCal Gas city-gate index, whereas prior to this shift the predominant index for California purchases was Kern, Delivered. The price from the Northwest, Rocky Mountain index was as high as $4.88 per mmbtu and as low as $1.78 per mmbtu in the first quarter of 2024. The price from the SoCal Gas city-gate index was as high as $5.37 per mmbtu and as low as $3.10 per mmbtu in the first quarter of 2024. Overall, on an unhedged basis, we paid an average of $3.99 per mmbtu in the first quarter of 2024 for our gas purchases. When including the hedging effects in our gas purchases, we paid $4.91, $5.73, and $8.88 per mmbtu in the first quarter of 2024, the fourth quarter of 2023, and the first quarter of 2023, respectively.
The price of our fuel gas sales is generally based on the Northwest, Rocky Mountains index, as selling at the same index as fuel gas purchases provides a natural hedge for gas prices as well aspurchases. In the demand for certain chemical products forfirst quarter of 2024, our Utah operations had an average realized gas price of $3.76, compared to an average Northwest, Rocky Mountains gas price of $3.41, which they are used as feedstock.was a 110% realization. In addition, infrastructure constraints magnify pricing volatility.the three months ended December 31, 2023 and March 31, 2023, Utah had an average realized gas price of $4.48, and $17.39, compared to an average Northwest, Rocky Mountains gas price of $4.53, or 99% realization, and $22.36, or 78% realization, respectively.
Natural gas prices and differentials are strongly affected by local market fundamentals, as well as availability of transportation capacity from producing areas. Higher naturalareas and seasonal impacts. Our key exposure to gas prices have a net negative effect onis in our operating results.costs. We usepurchase substantially more natural gas for our California steamfloods and power generation,cogeneration facilities than we produce and sell.sell in the Rockies. We purchase most of our gas in the Rockies and transport it to our California operations using our Kern River pipeline capacity. We buy approximately 48,000 mmbtu/d in the Rockies, and the remainder comes from California markets. The volume purchased in California fluctuates and averaged 5,000 mbbtu/d in the first quarter of 2024, 6,000 mmbtu/d in the fourth quarter of 2023, and 3,000 mmbtu/d in the first quarter of 2023. The natural gas we purchase in the Rockies is shipped to our operations in California to help limit our exposure to California fuel gas purchase price fluctuations. We strive to further minimize the variability of our fuel gas costs for our steam operations by hedging a significant portion of our gas purchases. Additionally, the negative impact of higher gas prices on our California operating costsexpenses is however, partially offset by higher gas sales for the gas we produce and sell in the Rockies. The Kern capacity allows us to purchase and sell natural gas sales.at the same pricing indices.
We seek to mitigate a substantial portion of the gas purchase exposure for our cogeneration plants by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. Aside from the impact gas prices have on electricity prices, these sales are generally higher in the summer months as they include seasonal capacity amounts. Gas prices declined in the first quarter of 2024 compared to the fourth quarter of 2023. The natural gas futures indicate that prices will rise toward the end of 2024 and into 2025.
Our earnings are also affected by the performance of our cogeneration facilities. These cogeneration facilities generate both electricity and steam for our properties and electricity for off-lease sales. While a portion of the electric output of our cogeneration facilities is utilized within our production facilities to reduce operating expenses, we also sell electricity produced by threetwo of our cogeneration facilities under long-term contracts.contracts with terms ending in December 2024 and November 2026. The most significant input and cost of the cogeneration facilities is natural gas.
Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products which are used as feedstock. In addition, infrastructure constraints magnify pricing volatility.
Regulatory Matters
Like other companies in the oil and gas industry, both our E&P business and CJWS are subject to complex and stringent federal, state, and local laws and regulations, and California, where most of our operations and assets are located, is one of the most heavily regulated states in the United States with respect to oil and gas operations. Collectively, the effect of the existing laws and regulations is to limit the number and location of our wells through restrictions on the use of our properties; limit our ability to develop certain assets and conduct certain operations, including through a restrictive and burdensome permitting and approval process; and have the effect of reducing the amount of oil and natural gas that we can produce from our wells, potentially reducing such production below levels that would otherwise be possible or economical. Additionally, the regulatory burden in the past has resulted, and in the future could result, in increased costs, and consequently has had an adverse effect on operations, capital expenditures, earnings and our competitive position, and may continue to have such effects in the future. Violations and liabilities with respect to these laws and regulations could also result in reputational damage and significant administrative, civil or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns, and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and future prospects. Our operations in California are particularly exposed to increased regulatory risks given the stringent environmental regulations imposed on the oil and gas industry, and current political and social trends in California continue to increase limitations on and impose additional permitting, mitigation and emissions control obligations, amongst others, upon the oil and gas industry. We cannot predict what new environmental laws or regulations California (or the federal government) may impose upon our operations in the future; however, any such future laws or regulations could materially and adversely impact our business and results of operations. For additional information about the potential impact that government regulations, including those regarding environmental matters, may have upon our business, operations, capital expenditures, earnings and competitive position, please see Part I, Item 1 “Regulatory Matters,” as well as Part I, Item 1A. “Risk Factors” in our Annual Report.
Over the last few years, a number of developments at both the California state and local levels have resulted in significant delays in the issuance of permits to drill new oil and gas wells in Kern County, where all of our California assets are located, as well as a more time and cost-intensive permitting process. The issuance of permits and other approvals for drilling and production activities by state and local agencies or by federal agencies are subject to environmental reviews under the California Environmental Quality Act (“CEQA”) and/or the National Environmental Policy Act (“NEPA”), respectively. The requirement to demonstrate compliance with CEQA and/or NEPA is currently resulting in (and in the future may result in) significant delays in the issuance of permits to drill new wells, as well as the potential imposition of mitigation measures and restrictions on proposed oil field operations, among other things. Before an operator can pursue drilling operations in California, they must first obtain permission to engage in oil and gas land use. CEQA requires the reviewing state and local agencies to consider the environmental impacts of the proposed oil and gas operations for permitting decisions. Historically, we satisfied CEQA by complying with the Kern County zoning ordinance for oil and gas operations, which was supported by the Kern County Environmental Impact Report (“EIR”). However, the EIR was legally challenged in 2020 and the use of the EIR is currently stayed and has been stayed through most of the litigation. On March 7, 2024 the California appellate court delivered an opinion finding certain deficiencies in the EIR and enjoining reliance on the EIR in connection with the issuance of oil and natural gas permit approvals until such deficiencies are remedied. Accordingly, our ability to rely on the EIR to demonstrate CEQA compliance to obtain permits and approvals to drill new wells is constrained unless and until Kern County is able to favorably resolve the litigation and certify a new revised EIR in compliance with CEQA. As a result of the litigation, since December 2022, neither we nor any other operator have received permits to drill new wells using the EIR to demonstrate CEQA compliance. In the meantime, to obtain permits for drilling new wells in Kern County we must demonstrate compliance with CEQA to CalGEM through means other than the EIR. Berry does have a separate environmental impact analysis covering certain assets, and we have historically received permits to drill new wells in the covered areas. However, we began to experience delays in the issuance of new drill permits in those areas during the third quarter of 2023, which we believe is due to changes in CalGEM’s CEQA review process. In fact, since January 2023, relatively few permits to drill new wells in California have been issued to any oil producer. Additionally, in the third quarter of 2023, we started to experience delays in the approval process for sidetrack and workover permits as well, which we believe is
also due to changes in CalGEM’s review process. Since that time, CalGEM has provided continued assurances that it is reviewing sidetrack and workover applications and working to finalize its approach to CEQA compliance with respect to such permit review that would allow the agency to ultimately return to regularly issuing these permits on a more predictable timeline. Nevertheless, CalGEM has only approved a relatively low number of sidetrack permits since November 2023 and we also continue to experience some delays in the approval process for workover permits. We currently have sufficient permits in hand that should allow us to maintain planned sidetrack drilling activity into July 2024 and conduct workover activity throughout the year. However, it is possible that such permit approval delays could continue throughout 2024, which would impede our ability to meet our planned 2024 sidetrack drilling program and/or limit our planned 2024 workover program. We are currently exploring a number of alternative permitting strategies to meet our 2024 drilling plan if the remaining sidetrack permits for our 2024 plan are not approved timely by CalGEM; however, we cannot guarantee that any of these strategies will ultimately be successful, and the inability to secure permits (on a timely basis or at all) could adversely impact our business and results of operations. See Part I, Item 1 and 2. “Business and Properties—Regulatory Matters—Regulation of the Oil and Gas Industry” in our Annual Report, as well as Part I, Item 1A. “Risk Factors” in our Annual Report for more information regarding the EIR and other permitting considerations.
On September 16, 2022, the California Governor signed into law Senate Bill No. 1137 (SB 1137) which prohibits CalGEM from permitting any new wells, or the rework of existing wells, if the proposed new drill or rework is within 3,200 feet of certain sensitive receptors such as homes, schools or parks. The bill would have become effective January 1, 2023. However, in December 2022, proponents of a voter referendum (the “Referendum”) collected more than the required number of signatures to put Senate Bill No. 1137 on the November 2024 ballot. On February 3, 2023, the Secretary of State of California certified the signatures and confirmed that the Referendum qualifies for the November 2024 ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote. Relatedly, a legislator introduced Senate Bill No. 556 (SB 556) into the California Senate in 2023, providing for joint and several liability for operators and owners of an entity that owns an oil and gas production facility for certain adverse health conditions within 3,200 feet of such facility, subject to limited defenses. Although this bill died during the last legislative session, an identical bill—Assembly Bill 3155 (AB 3155)—was introduced into the California Legislature in early 2024 and is currently under consideration. Separately, Assembly Bill 2716 (AB 2716) was introduced in 2024, which would require the plugging and abandonment of certain low-production wells located within 3,200 feet of a sensitive receptor within a certain timeframe or otherwise subjects operators to administrative penalties. We continue to monitor the progression of these bills, but we currently estimate that approximately 10% of our overall proved reserves as of December 31, 2023 are within the setbacks established by Senate Bill No. 1137. We do not expect this law to result in any material change in our overall existing proved developed producing reserves or current production rates.
Assembly Bill 1167 (AB 1167), signed into law by the California Governor in October 2023, imposes more stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in the state of California. AB 1167 requires such persons to fulfill bonding requirements in an amount determined by the state to sufficiently cover full plugging and abandonment costs, decommissioning, and site restoration of all wells and production facilities. Transfer of operatorship of a well or production facility is prohibited until the state has determined the appropriate bond amount and the bond has been filed. Upon signing AB 1167, the California Governor called for further legislative changes to the new requirements to mitigate against the potential risk of an increase in the number of orphaned wells becoming state liabilities following the implementation of the law. Similar to AB 1167, in early 2024, a California legislator introduced Assembly Bill 1866 (AB 1866) which would require the operator of any idle well to file, on or before July 1, 2025, a plan with the state to provide for the management and elimination of all idle wells, with consideration shown to a number of specified factors when prioritizing idle wells for testing or plugging and abandonment. Additionally, AB 1866 would require operators to restore the surface of the well pad to as near a natural state as practicable or to a condition suitable for alternative use. Any operator who fails to comply with AB 1866 would be subject to civil penalties.
In October 2023, the California Governor signed two bills that require quantitative and qualitative climate disclosures for certain public and private companies doing business in California. Senate Bill 253 (SB 253) requires the annual disclosure of Scope 1, 2 and 3 GHG emissions, with certain emissions data subject to third party assurance. The bill requires disclosure of Scope 1 and 2 GHG emissions beginning in 2026 for the 2025 reporting year and disclosure of Scope 3 GHG emissions beginning in 2027 for the 2026 reporting year. SB 253 is effective for public and private companies with total annual revenues exceeding $1 billion. Senate Bill 261 (SB 261) requires biennial disclosures posted on a company’s website related to climate-related financial risks and the measures a company has adopted to reduce and adapt to such risks. The bill requires disclosure of the climate-related financial risk disclosures beginning in 2026 for the 2025 reporting year. SB 261 is effective for public and private companies with total annual revenues exceeding $500 million. Both SB 253 and 261 have been challenged in the U.S. District Court for the Central District of California.
Inflation
The U.S. inflation rate has become more significant in recent years. The Company, similar to other companies in our industry, has experienced inflationary pressures on our costs—namely inflationary pressures have resulted in increases to the costs of our goods, services and personnel, which in turn, have caused our capital expenditures and operating costs to rise. Such inflationary pressures have resulted from supply chain disruptions caused by the COVID-19 pandemic, increased demand, labor shortages and other factors, including the conflict between Russia and Ukraine. During 2024, inflation rates continued their trend of stabilizing as seen in the latter half of 2023. We are unable to accurately predict if such inflationary pressures and contributing factors will continue through 2024. However, as of March 31, 2024, we determined there have not been any material changes in inflationary pressures since the year ended December 31, 2023.
Seasonality
Seasonal weather conditions have in the past, and lease stipulations can limitin the future likely will, impact our drilling, production and producingwell servicing activities. These seasonalExtreme weather conditions can occasionally pose challenges in our operations forto meeting well-drilling and completion objectives and increaseproduction goals. Seasonal weather can also lead to increased competition for equipment, supplies and personnel, which could lead to shortages and increaseincreased costs or delaydelayed operations. For example, ourOur operations mayhave been, and in the future could be, impacted by ice and snow in the winter, especially in Utah, and by electrical storms and high temperatures in the spring and summer, as well as by wild fires.wildfires and rain.
We seek to mitigate a substantial portion of the gas purchase exposure for our cogeneration plants by selling excess electricity from our cogeneration operations to third parties at prices linked to the price of natural gas. Aside from the impact gas prices have on electricity prices, these sales are generally higher in the summer months as they include seasonal capacity amounts. In the first quarter of 2024, gas prices decreased from prices in the fourth quarter of 2023. Our hedging strategy coupled with our midstream access to gas from the Rockies helps us mitigate the impact of high natural gas prices on our cost structure.
Capital Expenditures
For the three months ended March 31, 2024, our total capital expenditures were approximately $17 million, including capitalized overhead and interest and excluding acquisitions and asset retirement spending. E&P and corporate expenditures were $16 million for the three months ended March 31, 2024 (excluding well servicing and abandonment capital of $1 million). Approximately 90% and 10% of these capital expenditures for the three months ended March 31, 2024 were directed to California and Utah operations, respectively.
Our 2024 capital expenditure budget for E&P operations, CJWS and corporate activities is between $95 to $110 million, which, if executed fully, we expect will result in 2024 production to be essentially flat compared with 2023. We currently anticipate oil production will be approximately 93% of total production volume in 2024, substantially consistent with 2023. Based on current commodity prices and our drilling success rate to date, we expect to be able to fund our 2024 capital development programs from cash flow from operations. Our current capital program for 2024 focuses on sidetracks and workovers. We also expect to benefit from a full year of production from the assets acquired from bolt-on acquisitions in the second half of 2023, which should help keep our production essentially flat in 2024 if we execute fully on our 2024 capital budget. As a result of ongoing regulatory uncertainty in California impacting the permitting process in Kern County where all of our California assets are located, the capital program has been prepared based on the assumption that we will not receive additional new drill permits in California in 2024, but that we will continue to timely receive the other permits and approvals needed for planned activities. However, as discussed elsewhere in this Quarterly Report, we are seeing delays in our ability to timely obtain workover and sidetrack permits, in addition to new drill permits. These delays have the potential to adversely affect our 2024 sidetrack drilling and workover programs. Please see “—Regulatory Matters” in this Quarterly Report, as well as in our Annual Report, for additional discussion of the laws and regulations that impact our ability to drill and develop our assets, including those impacting regulatory approval and permitting requirements.
Exclusive of the capital expenditures noted above, for the full year 2024, we plan to spend approximately $21 million to $24 million on plugging and abandonment activities, most of which is planned to meet our annual obligation requirements under California idle well program. We spent approximately $2 million for plugging and abandonment activities in the three months ended March 31, 2024.
For information about the potential risks related to our capital program, see Part I, Item IA. “Risk factors” in our Annual Report, as well as “—Regulatory Matters.”
Production Prices and CostsPrices
The following table sets forth information regarding total production, average daily production, average pricestotal production and average costsprices for each of the periods indicated.
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| |
| Three Months Ended | | |
| March 31, 2024 | | December 31, 2023 | | March 31, 2023 | | | | | | |
Average daily production:(1) | | | | | | | | | | | |
| Oil (mbbl/d) | 23.8 | | | 24.0 | | | 22.6 | | | | | | | |
| Natural Gas (mmcf/d) | 7.9 | | | 7.8 | | | 8.7 | | | | | | | |
| NGL (mbbl/d) | 0.3 | | | 0.6 | | | 0.2 | | | | | | | |
Total (mboe/d)(2) | 25.4 | | | 25.9 | | | 24.3 | | | | | | | |
| Total Production: | | | | | | | | | | | |
| Oil (mbbl) | 2,161 | | | 2,209 | | | 2,037 | | | | | | | |
| Natural gas (mmcf) | 723 | | | 717 | | | 779 | | | | | | | |
| NGLs (mbbl) | 28 | | | 56 | | | 20 | | | | | | | |
Total (mboe)(2) | 2,310 | | | 2,384 | | | 2,187 | | | | | | | |
| Weighted-average realized sales prices: | | | | | | | | | | | |
| Oil without hedges ($/bbl) | $ | 75.31 | | | $ | 76.00 | | | $ | 74.69 | | | | | | | |
| Effects of scheduled derivative settlements ($/bbl) | $ | (2.17) | | | $ | (3.35) | | | $ | (3.65) | | | | | | | |
| Oil with hedges ($/bbl) | $ | 73.14 | | | $ | 72.65 | | | $ | 71.04 | | | | | | | |
| Natural gas ($/mcf) | $ | 3.76 | | | $ | 4.48 | | | $ | 17.39 | | | | | | | |
| NGL ($/bbl) | $ | 29.60 | | | $ | 24.01 | | | $ | 34.10 | | | | | | | |
| Average Benchmark prices: | | | | | | | | | | | |
| Oil (bbl) – Brent | $ | 81.76 | | | $ | 82.85 | | | $ | 82.16 | | | | | | | |
| Oil (bbl) – WTI | $ | 77.02 | | | $ | 78.49 | | | $ | 76.15 | | | | | | | |
Natural gas (mmbtu) – SoCal Gas city-gate(3) | $ | 4.21 | | | $ | 6.25 | | | $ | 24.81 | | | | | | | |
Natural gas (mmbtu) – Northwest, Rocky Mountains(4) | $ | 3.41 | | | $ | 4.53 | | | $ | 22.36 | | | | | | | |
Natural gas (mmbtu) – Henry Hub(4) | $ | 2.15 | | | $ | 2.74 | | | $ | 2.64 | | | | | | | |
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| | Berry Corp.
(Successor) |
| | Three Months Ended | Three Months Ended | Three Months Ended | Variance | Variance |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 | Q2 2018 vs. Q1 2018 | Q2 2018 vs. Q2 2017 |
| Average daily production: | | | | | |
| Oil (MBbl/d) | 21.1 |
| 21.1 |
| 19.2 |
| — |
| 1.9 |
|
| Natural Gas (MMcf/d) | 28.0 |
| 27.6 |
| 73.1 |
| 0.4 |
| (45.1 | ) |
| NGL (MBbl/d) | 0.7 |
| 0.5 |
| 2.9 |
| 0.2 |
| (2.2 | ) |
| Total (MBoe/d)(1) | 26.5 |
| 26.2 |
| 34.4 |
| 0.3 |
| (7.9 | ) |
| Total Production: | | | | | |
| Oil (MBbl) | 1,920 |
| 1,897 |
| 1,752 |
| 23 |
| 168 |
|
| Natural gas (MMcf) | 2,551 |
| 2,481 |
| 6,656 |
| 70 |
| (4,105 | ) |
| NGLs (MBbl) | 62 |
| 45 |
| 267 |
| 17 |
| (205 | ) |
| Total combined production (MBoe)(1) | 2,408 |
| 2,356 |
| 3,128 |
| 52 |
| (720 | ) |
| Weighted average realized prices: | | | | — |
| — |
|
| Oil with hedges (Bbl) | $ | 53.22 |
| $ | 52.74 |
| $ | 46.97 |
| $ | 0.48 |
| $ | 6.25 |
|
| Oil without hedges (Bbl) | $ | 67.93 |
| $ | 62.14 |
| $ | 44.27 |
| $ | 5.79 |
| $ | 23.66 |
|
| Natural gas (Mcf) | $ | 2.12 |
| $ | 2.64 |
| $ | 2.74 |
| $ | (0.52 | ) | $ | (0.62 | ) |
| NGL (Bbl) | $ | 24.38 |
| $ | 25.56 |
| $ | 22.72 |
| $ | (1.18 | ) | $ | 1.66 |
|
| Average Benchmark prices: | | | | $ | — |
| $ | — |
|
| Oil (Bbl) – Brent | $ | 74.87 |
| $ | 67.16 |
| $ | 50.90 |
| $ | 7.71 |
| $ | 23.97 |
|
| Oil (Bbl) – WTI | $ | 67.76 |
| $ | 62.87 |
| $ | 48.28 |
| $ | 4.89 |
| $ | 19.48 |
|
| Natural gas (MMBtu) – NYMEX Henry Hub | $ | 2.80 |
| $ | 3.00 |
| $ | 3.18 |
| $ | (0.20 | ) | $ | (0.38 | ) |
| Average costs per Boe(2): | | | | | |
| Lease operating expenses | $ | 17.24 |
| $ | 18.80 |
| $ | 14.62 |
| $ | (1.56 | ) | $ | 2.62 |
|
| Electricity generation expenses | $ | 1.30 |
| $ | 1.94 |
| $ | 1.43 |
| $ | (0.64 | ) | $ | (0.13 | ) |
| Electricity sales (2) | $ | (2.48 | ) | $ | (2.31 | ) | $ | (1.83 | ) | $ | (0.17 | ) | $ | (0.65 | ) |
| Transportation expenses | $ | 0.97 |
| $ | 1.26 |
| $ | 3.01 |
| $ | (0.29 | ) | $ | (2.04 | ) |
| Transportation sales (2) | $ | (0.09 | ) | $ | — |
| $ | — |
| $ | (0.09 | ) | $ | (0.09 | ) |
| Marketing expenses | $ | 0.17 |
| $ | 0.25 |
| $ | 0.23 |
| $ | (0.08 | ) | $ | (0.06 | ) |
| Marketing revenues (2) | $ | (0.22 | ) | $ | (0.33 | ) | $ | (0.26 | ) | $ | 0.11 |
| $ | 0.04 |
|
| Total operating expenses | $ | 16.89 |
| $ | 19.61 |
| $ | 17.20 |
| $ | (2.72 | ) | $ | (0.31 | ) |
| General and administrative expenses (3) | $ | 5.18 |
| $ | 5.09 |
| $ | 7.11 |
| $ | 0.09 |
| $ | (1.93 | ) |
| Depreciation, depletion and amortization | $ | 9.08 |
| $ | 7.82 |
| $ | 6.57 |
| $ | 1.26 |
| $ | 2.51 |
|
| Taxes, other than income taxes | $ | 3.62 |
| $ | 3.50 |
| $ | 3.28 |
| $ | 0.12 |
| $ | 0.34 |
|
(1) Production represents volumes sold during the period. We also consume a portion of the natural gas we produce on lease to extract oil and gas.
(2) Natural gas volumes have been converted to Boeboe based on energy content of six Mcfmcf of gas to one Bblbbl 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 yearthree months ended DecemberMarch 31, 2017,2024, the average prices of ICE (Brent)Brent oil and NYMEX Henry Hub natural gas were $54.82$81.76 per Bblbbl and $3.11$2.15 per Mcf, respectively, resulting in an oil-to-gas ratio of over 17mmbtu.
(3) The natural gas we purchase to 1.
(2) We reportgenerate steam and electricity is primarily based on Rockies price indexes, including transportation and marketing sales separately in our financial statementscharges, 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 efficiencywe currently purchase a substantial majority of our hydrocarbon recovery. We purchase third-party
gas to generate electricity through our cogeneration facilities to beneeds from the Rockies, with the balance purchased in California. SoCal Gas city-gate Index is the relevant index 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 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, reported in "Other Revenues", relates to water and other liquids that we transport on our systems on behalf of third parties.
(3) Includes non-recurring restructuring and other costs and non-cash stock compensation expense, in aggregate, of approximately $1.24, $1.31 and $5.39 per Boeonly for the three months ended June 30, 2018, March 31, 2018portion of gas purchases in California. Beginning in the first quarter of 2023, we are purchasing a majority of our fuel gas in the Rockies; most of the purchases made in California utilize the SoCal Gas city-gate index, whereas prior to this shift the predominant index for California purchases was Kern, Delivered.
(4) Most of our gas purchases and June 30, 2017, respectively.gas sales in the Rockies are predicated on the Northwest, Rocky Mountains index, and to a lesser extent based on Henry Hub.
The following table sets forth average daily production by operating area for the periods indicated:
| | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2024 | | December 31, 2023 | | March 31, 2023 |
Average daily production (mboe/d):(1) | | | | | |
| California | 21.3 | | | 21.5 | | | 19.9 | |
| Utah | 4.1 | | | 4.4 | | | 4.4 | |
| | | | | |
| | | | | |
| Total average daily production | 25.4 | | | 25.9 | | | 24.3 | |
|
| | | | | | |
| | Berry Corp.
(Successor) |
| | Three Months Ended | Three Months Ended | Three Months Ended |
| | June 30, 2018 | March 31, 2018 | June 30, 2017 |
| Average daily production (MBoe/d): | | | |
| California(1) | 18.8 |
| 18.8 |
| 16.3 |
|
| Hugoton basin(2) | — |
| — |
| 8.6 |
|
| Uinta basin | 5.3 |
| 5.0 |
| 5.9 |
|
| Piceance basin | 1.6 |
| 1.6 |
| 2.5 |
|
| East Texas | 0.8 |
| 0.8 |
| 1.1 |
|
| | 26.5 |
| 26.2 |
| 34.4 |
|
(1) Production represents volumes sold during the period.
| |
(1) | On July 31, 2017, we purchased the remaining approximately 84% working interest of our South Belridge Hill property, located in Kern County, California. |
| |
(2) | On July 31, 2017, we sold our 78% working interest in the Hugoton natural gas field located in southwest Kansas and the Oklahoma Panhandle.
Our Hugoton assets represented approximately 24% of our average net daily production for the year ended December 31, 2016. |
Average daily production volumes decreased to approximately 26.5 MBoe/d2%, or 23% for the three months ended June 30, 2018 from approximately 34.4 MBoe/0.5 mboe/d, for the three months ended June 30, 2017. TheMarch 31, 2024, compared to the three months ended December 31, 2023. Our California production was 21.3 mboe/d for the first quarter of 2024, a decrease primarily reflected the decreased natural gas and NGL volumesof less than 1% or 0.2 mboe/d from the salefourth quarter of an approximately 78% non-operating, working interest2023, which was principally due to the natural decline experienced by the wells placed in the Hugoton natural gas field (the "Hugoton Disposition")service in July 2017,late 2023. This decrease was partially offset by production from development activities as well as the additional oil volumes fromimpact of the acquisition of an approximately 84% non-operating, working interest in a South Belridge Hill property, (the "Hill Acquisition") in July 2017. Also contributing to the decrease to a lesser degreeyear end acquisition. The Utah decline was the delay between our increase in capital spending in late 2017 to arrest production declines due to reduced capital spendinglower drilling and workover activity as 2024 development plans are expected to begin in 2016 and early 2017, and the effectiveness of the increase which we began to observe in early and mid 2018.second quarter (see “—Capital Expenditures” for further discussion).
Average
Our average daily production volumes increased 5%, or 1.1 mboe/d, for the three months ended June 30, 2018March 31, 2024 compared to the three months ended March 31, 20182023. Higher 2024 production in California was due to the increased development capital spendingbolt-on acquisitions in late 20172023 and early 2018.
The following tables set forth information regarding totalincreased well operating time from improved weather conditions and less abandonment activity. California production average daily production, average prices and average costs for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods. The information for the six months ended June 30, 2017 are reflectedwas negatively impacted in the tablesfirst quarter of 2023 by severe rainstorms which lowered operating times and narrative discussion that follows in two distinct periods, the four months ended June 30, 2017 and the two months ended February 28, 2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations to the six months ended June 30, 2017 are used to provide comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for comparing the periods presented.
|
| | | | | | | | | |
| | Berry Corp.
(Successor) | Berry LLC (Predecessor) |
| | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| | | | |
| Average Daily Production: | | | |
| Oil (MBbl/d) | 21.1 |
| 19.2 |
| 19.5 |
|
| Natural Gas (MMcf/d) | 27.8 |
| 72.8 |
| 71.7 |
|
| NGL (MBbl/d) | 0.6 |
| 3.1 |
| 5.2 |
|
| Total (MBoe/d)(1) | 26.3 |
| 34.4 |
| 36.6 |
|
| Total Production: | | | |
| Oil (MBbl) | 3,818 |
| 2,338 |
| 1,153 |
|
| Natural gas (MMcf) | 5,032 |
| 8,877 |
| 4,232 |
|
| NGLs (MBbl) | 108 |
| 379 |
| 304 |
|
| Total combined production (MBoe)(1) | 4,764 |
| 4,196 |
| 2,162 |
|
| Weighted average realized prices: | | | |
| Oil with hedges (Bbl) | $ | 52.98 |
| $ | 46.84 |
| $ | 47.40 |
|
| Oil without hedges (Bbl) | $ | 65.06 |
| $ | 44.34 |
| $ | 46.94 |
|
| Natural gas (Mcf) | $ | 2.38 |
| $ | 2.67 |
| $ | 3.42 |
|
| NGL (Bbl) | $ | 24.88 |
| $ | 21.64 |
| $ | 18.20 |
|
| Average benchmark prices: | | | |
| Oil (Bbl) – Brent | $ | 71.01 |
| $ | 51.31 |
| $ | 55.72 |
|
| Oil (Bbl) – WTI | $ | 65.32 |
| $ | 48.63 |
| $ | 53.04 |
|
| Natural gas (MMBtu) – NYMEX Henry Hub | $ | 2.90 |
| $ | 3.05 |
| $ | 3.66 |
|
| Average costs per Boe (2): | | | |
| Lease operating expenses | $ | 18.01 |
| $ | 14.01 |
| $ | 13.06 |
|
| Electricity generation expenses | $ | 1.62 |
| $ | 1.34 |
| $ | 1.48 |
|
| Electricity sales (2) | $ | (2.40 | ) | $ | (1.57 | ) | $ | (1.69 | ) |
| Transportation expenses | $ | 1.12 |
| $ | 3.11 |
| $ | 2.86 |
|
| Transportation sales (2) | $ | (0.05 | ) | $ | — |
| $ | — |
|
| Marketing expenses | $ | 0.21 |
| $ | 0.24 |
| $ | 0.30 |
|
| Marketing revenues (2) | $ | (0.27 | ) | $ | (0.26 | ) | $ | (0.29 | ) |
| Total operating expenses | $ | 18.24 |
| $ | 16.87 |
| $ | 15.72 |
|
| General and administrative expenses (3) | $ | 5.14 |
| $ | 7.58 |
| $ | 3.68 |
|
| Depreciation, depletion and amortization | $ | 8.46 |
| $ | 6.57 |
| $ | 13.02 |
|
| Taxes, other than income taxes | $ | 3.56 |
| $ | 3.18 |
| $ | 2.41 |
|
(1) 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.
(2) 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 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, reported in "Other Revenues", relate to water and other liquids that we transport on our systems on behalf of third parties.
(3) Includes non-recurring restructuring and other costs and non-cash stock compensation expense, in aggregate, of approximately $1.28, $5.83 and none per Boe for the six months ended June 30, 2018, the four months ended June 30, 2017 and the two months ended February 28, 2017, respectively.
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| | Berry Corp.
(Successor) | Berry LLC (Predecessor) |
| | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| Average daily production (MBoe/d): | | | |
| California (San Joaquin) (1) | 18.8 |
| 16.3 |
| 17.0 |
|
| Hugoton basin(2) | — |
| 8.9 |
| 10.8 |
|
| Uinta basin | 5.1 |
| 5.7 |
| 5.4 |
|
| Piceance basin | 1.6 |
| 2.5 |
| 2.3 |
|
| East Texas | 0.8 |
| 1.0 |
| 1.1 |
|
| | 26.3 |
| 34.4 |
| 36.6 |
|
Average daily production volumes decreased to approximately 26.3 MBoe/d for the six months ended June 30, 2018 from approximately 35.1 MBoe/d for the six months ended June 30, 2017, including the successor and predecessor periods. The decrease primarily reflected the decreased natural gas and NGL volumes from the sale of the approximately 78% non-operating, working interest in the Hugoton natural gas field in July 2017, partially offset by the additional oil volumes from the Hill Acquisition. Also contributing to the decrease, to a lesser degree, was the delayed impact of increasing capital after our emergence from bankruptcy in early 2017 following the reduced development capital spending in 2016 and early 2017.
Balance Sheet Analysis
The changes in our balance sheet from December 31, 2017 to June 30, 2018 are discussed below. |
| | | | | | | |
| | Berry Corp. (Successor) |
| | June 30, 2018 | | December 31, 2017 |
| | (in thousands) |
| Cash and cash equivalents | $ | 3,600 |
| | $ | 33,905 |
|
| Accounts receivable, net | $ | 56,860 |
| | $ | 54,720 |
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| Restricted cash | $ | 19,710 |
| | $ | 34,833 |
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| Other current assets | $ | 14,981 |
| | $ | 14,066 |
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| Property, plant & equipment, net | $ | 1,397,919 |
| | $ | 1,387,191 |
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| Other noncurrent assets | $ | 22,086 |
| | $ | 21,687 |
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| Accounts payable and accrued liabilities | $ | 113,170 |
| | $ | 97,877 |
|
| Derivative instruments-current and long term | $ | 15,010 |
| | $ | 60,165 |
|
| Liabilities subject to compromise | $ | 19,710 |
| | $ | 34,833 |
|
| Long term debt | $ | 457,333 |
| | $ | 379,000 |
|
| Asset retirement obligation | $ | 88,575 |
| | $ | 94,509 |
|
| Other noncurrent liabilties | $ | 12,862 |
| | $ | 3,704 |
|
| Equity | $ | 808,496 |
| | $ | 859,310 |
|
See “Liquidity and Capital Resources” for a discussion about the changes in cash and cash equivalents, asprevented routine well as long term debt.
Restricted cash at June 30, 2018 and December 31, 2017 represents funds set aside to settle the general unsecured creditors claims resulting from our bankruptcy process.maintenance. The decrease in restricted cash, and the corresponding decrease in liabilities subject to compromise, represents the settlement of these claims, the return of undistributed funds in the amount of $9 million and professional fees related to the settlement of these claims.
The increase in accounts payable and accrued liabilities is largely the result of the new interest payment obligations on our 2026 Notes, issued in February of 2018 of $11 million.
The decrease in the derivative liability reflects the early termination and replacement of certain hedge contracts to move from a WTI-based positionUtah was due to a Brent-based positionreduction of drilling and to align our hedging program with higher current commodity prices.workover activity.
The increase in long term debt represents the issuance
The increase in other noncurrent liabilities represents an additional greenhouse gas liability of $9 million for production during the six months ended June 30, 2018 and which is due for payment more than one year from June 30, 2018.
The decrease in equity reflects the $20 million repurchase from certain general unsecured creditors of the right to receive shares of our common stock in settlement of their claims, the declaration of approximately $11 million in dividends on our Series A Preferred Stock and our results of operations.
Results of Operations
Results of Operations - Three Months Ended June 30, 2018March 31, 2024 compared to Three Months Ended December 31, 2023.
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| Three Months Ended | | | | | | |
| March 31, 2024 | | December 31, 2023 | | $ Change | | % Change | |
| (in thousands) | | | | | | |
| Revenues and other: | | | | | | | | | |
| Oil, natural gas and NGL sales | $ | 166,318 | | | $ | 172,439 | | | $ | (6,121) | | | (4) | % | | |
Service revenue(1) | 31,683 | | | 40,746 | | | (9,063) | | | (22) | % | | |
| Electricity sales | 4,243 | | | 2,905 | | | 1,338 | | | 46 | % | | |
| (Losses) gains on oil and gas sales derivatives | (71,200) | | | 83,918 | | | (155,118) | | | n/a | | |
| Other revenues | 67 | | | 319 | | | (252) | | | (79) | % | | |
| | | | | | | | | |
| Total revenues and other | $ | 131,111 | | | $ | 300,327 | | | $ | (169,216) | | | (56) | % | | |
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__________(1) The well servicing and abandonment segment occasionally provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $35 million and $43 million, and after the intercompany elimination of $4 million and $2 million, net service revenue was approximately $32 million and approximately $41 million for the quarters ended March 31,
2018. |
| | | | | | | | | | | |
| | Berry Corp.
(Successor) | |
| | Three Months Ended | Three Months Ended | | |
| (in thousands) | June 30, 2018 | March 31, 2018 | $ Change | % Change |
| Revenues and other: | | | | |
| Oil, natural gas and NGL sales | $ | 137,385 |
| $ | 125,624 |
| $ | 11,761 |
| 9 | % |
| Electricity sales | 5,971 |
| 5,453 |
| 518 |
| 9 | % |
| (Losses) gains on oil and natural gas derivatives | (78,143 | ) | (34,644 | ) | (43,499 | ) | 126 | % |
| Marketing and other revenues | 769 |
| 851 |
| (82 | ) | (10 | )% |
| | 65,982 |
| 97,284 |
| (31,302 | ) | (32 | )% |
| Expenses and other: | | | | |
| Lease operating expenses | 41,517 |
| 44,303 |
| (2,786 | ) | (6 | )% |
| Electricity generation expenses | 3,135 |
| 4,590 |
| (1,455 | ) | (32 | )% |
| Transportation expenses | 2,343 |
| 2,978 |
| (635 | ) | (21 | )% |
| Marketing expenses | 407 |
| 580 |
| (173 | ) | (30 | )% |
| General and administrative expenses | 12,482 |
| 11,985 |
| 497 |
| 4 | % |
| Depreciation, depletion, amortization and accretion | 21,859 |
| 18,429 |
| 3,430 |
| 19 | % |
| Taxes, other than income taxes | 8,715 |
| 8,256 |
| 459 |
| 6 | % |
| (Gains) losses on sale of assets and other, net | 123 |
| — |
| 123 |
| |
| | 90,581 |
| 91,121 |
| (540 | ) | (1 | )% |
| Other income and (expenses): | | | | |
| Interest expense | (9,155 | ) | (7,796 | ) | (1,359 | ) | 17 | % |
| Other, net | (239 | ) | 27 |
| (266 | ) | (985 | )% |
| Reorganization items, net | 456 |
| 8,955 |
| (8,499 | ) | (95 | )% |
| Income (loss) before income taxes | (33,537 | ) | 7,349 |
| (40,886 | ) | (556 | )% |
| Income tax expense (benefit) | (5,476 | ) | 939 |
| (6,415 | ) | (683 | )% |
| Net income (loss) | (28,061 | ) | 6,410 |
| (34,471 | ) | (538 | )% |
| Dividends on Series A Preferred Stock | (5,650 | ) | (5,650 | ) | — |
| — | % |
| Net income (loss) available to common stockholders | $ | (33,711 | ) | $ | 760 |
| $ | (34,471 | ) | (4,536 | )% |
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Revenues and Other
Oil, natural gas and NGL sales increased $12decreased by $6 million, or 9%4%, to approximately $137$166 million for the three months ended June 30, 2018March 31, 2024, compared to the three months ended December 31, 2023. The decrease was driven by a $4 million decrease in oil volumes and $2 million decrease in oil prices.
Service revenue consisted entirely of revenue from the well servicing and abandonment business. Service revenue decreased by $9 million, or 22%, to approximately $32 million for the three months ended March 31, 2018.2024, compared to the three months ended December 31, 2023. The increase reflects improved oil pricesdecrease was driven by lower activity in the first quarter of 2024 and a slight increaseshift in production.services from third parties to our E&P segment.
Electricity sales represent sales to utilities and increased by approximately $0.5$1 million, or 9%46%, to approximately $6 million for the three months ended June 30, 2018, compared to the three months ended March 31, 2018. The increase was primarily due to higher seasonal prices.
Losses on oil and natural gas derivatives were approximately $78 million for the three months ended June 30, 2018 compared to losses of approximately $35$4 million for the three months ended March 31, 2018. The increase represents improved commodity prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018. Marketing revenues in these periods primarily represent sales of third-party natural gas and were comparable for these periods.
Expenses and other
We report sales of electricity, marketing and transportation activities (as applicable) 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, reported in "Other Revenues", relate to water and other liquids that we transport on our systems on behalf of third parties.
Operating expenses, as defined above, decreased to $16.89 per Boe for the quarter ended June 30, 2018 from $19.61 per Boe for the quarter ended March 31, 2018, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $3 million, or 6%, to approximately $42 million for the three months ended June 30, 2018,2024 compared to the three months ended MarchDecember 31, 2018. The decrease2023. This increase was primarily due to lower well servicing activity, lower fuel gas costs and increased oil inventory caused by market disruptions in Utahhigher resource adequacy payments in the first quarter ended June 30, 2018. For the same reasons, lease operating expenses per Boe decreased to $17.24 per Boe for the three months ended June 30, 2018 from $18.80 per Boeof 2024.
Gain or loss on oil and gas sales derivatives consists of settlement gains and losses and mark-to-market gains and losses. Our settlement loss for the three months ended March 31, 2018.
Electricity generation expenses decreased by approximately $1.52024 and December 31, 2023 was $5 million or 32% for the three months ended June 30, 2018 compared to the three months ended March 31, 2018,and $7 million, respectively. This quarter-over-quarter decrease in settlement loss was primarily due to a higher fixed price of settled positions and lower fuel gas costs and reduced cogen operating costs due to replacement of a third party service provider with internal staffing.
Transportation expenses decreased by approximately $0.6 million, or 21%, to approximately $2 millionBrent settlement prices, the index for the three months ended June 30, 2018, compared to the three months ended March 31, 2018, primarily due to reduced costs for use of certain third-party systems.
Marketing expenses for the three months ended June 30, 2018 were comparable to the three months ended March 31, 2018.
General and administrative expenses increased by approximately $0.5 million, or 4%, to approximately $12 million for the three months ended June 30, 2018 compared to the three months ended March 31, 2018, primarily due to increased costs related to preparing to be a public company.all our oil derivatives. The increase in absolute dollars incurred resulted in slightly higher general and administrative expenses of $5.18 per Boe for the three months ended June 30, 2018, compared to $5.09 per Boemark-to-market non-cash loss for the three months ended March 31, 2018. For2024 was $67 million compared to a gain of $91 million in the three months ended June 30, 2018 and MarchDecember 31, 2018, general and administrative expenses included non-recurring restructuring and other costs of approximately $1.7 million and $2.0 million, respectively, and non-cash stock compensation costs of approximately $1.3 million and $1.0 million, respectively.2023. Because we are the floating price payer on these swaps, generally, period to period decreases (increases) in the associated price index create valuation gains (losses).
Depreciation, depletion and amortization ("DD&A") increased by approximately $3 million, or 19%, to approximately $22 millionOther revenues were not material for the three months ended June 30, 2018March 31, 2024 and December 31, 2023.
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| Three Months Ended | | | | $ Change | | % Change |
| March 31, 2024 | | December 31, 2023 | | | |
| (in thousands) | | | | | | |
| Expenses and other: | | | | | | | | | |
| Lease operating expenses | $ | 60,697 | | | $ | 67,342 | | | | | $ | (6,645) | | | (10) | % |
Costs of services(1) | 27,304 | | | 32,783 | | | | | (5,479) | | | (17) | % |
| Electricity generation expenses | 1,093 | | | 1,827 | | | | | (734) | | | (40) | % |
| Transportation expenses | 1,059 | | | 1,260 | | | | | (201) | | | (16) | % |
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Acquisition costs(2) | 2,617 | | | 284 | | | | | 2,333 | | | 821 | % |
| General and administrative expenses | 20,234 | | | 20,729 | | | | | (495) | | | (2) | % |
| Depreciation, depletion and amortization | 42,831 | | | 40,937 | | | | | 1,894 | | | 5 | % |
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| Taxes, other than income taxes | 15,689 | | | 15,826 | | | | | (137) | | | (1) | % |
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| Losses (gains) on natural gas purchase derivatives | 4,481 | | | 21,397 | | | | | (16,916) | | | (79) | % |
| Other operating (income) expense | (133) | | | 36 | | | | | (169) | | | 469 | % |
| Total expenses and other | 175,872 | | | 202,421 | | | | | (26,549) | | | (13) | % |
| Other expenses: | | | | | | | | | |
| Interest expense | (9,140) | | | (9,680) | | | | | 540 | | | (6) | % |
| Other, net | (83) | | | (10) | | | | | (73) | | | 730 | % |
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| Total other expenses | (9,223) | | | (9,690) | | | | | 467 | | | (5) | % |
| (Loss) income before income taxes | (53,984) | | | 88,216 | | | | | (142,200) | | | (161) | % |
| Income tax (benefit) expense | (13,900) | | | 25,665 | | | | | (39,565) | | | 154 | % |
| Net (loss) income | $ | (40,084) | | | $ | 62,551 | | | | | $ | (102,635) | | | (164) | % |
Adjusted EBITDA(3) | $ | 68,534 | | | $ | 70,036 | | | | | $ | (1,502) | | | (2) | % |
Adjusted Net Income(3) | $ | 10,910 | | | $ | 10,426 | | | | | $ | 484 | | | 5 | % |
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__________(1) The well servicing and abandonment segment occasionally provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $31 million and $35 million, and after the intercompany elimination of $4 million and $2 million, net costs of services was $27 million and $33 million for the quarters ended March 31, 2024 and December 31, 2023, respectively.
(2) Includes legal and other professional expenses related to various transaction activities.
(3) Adjusted EBITDA and Adjusted Net Income (Loss) are financial measures that are not calculated in accordance with GAAP. For definitions and a reconciliation to the Net Cash Provided by Operating Activities and Net Income (loss), please see “—Non-GAAP Financial Measures”.
Expenses
Lease operating expenses, which do not include the effects of gas purchase hedges, decreased 10% or $7 million to $61 million for the first quarter of 2024 when compared to the fourth quarter of 2023. The majority of this decrease was the result of lower natural gas (fuel) costs of $8 million for our California steam generation facilities due to a decline in fuel prices. Lease operating expenses, excluding fuel, increased $1 million due to higher well service and maintenance activity.
Cost of services decreased $5 million, or 17%, to $27 million in the first quarter of 2024 due to lower activity.
Electricity generation decreased $1 million due to lower fuel prices for the three months ended March 31, 2024 compared to the three months ended MarchDecember 31, 2018, primarily due to increased DD&A rates, slightly higher production and increased asset retirement accretion expense.2023.
Taxes, Other Than Income Taxes
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| | Berry Corp. (Successor) |
| | Three Months Ended | Three Months Ended | |
| | June 30, 2018 | March 31, 2018 | Variance |
| (in thousands) | | | |
| Severance taxes | $ | 2,997 |
| $ | 2,764 |
| $ | 233 |
|
| Ad valorem and property taxes | 3,141 |
| 3,417 |
| (276 | ) |
| Greenhouse gas allowances | 2,577 |
| 2,075 |
| 502 |
|
| | $ | 8,715 |
| $ | 8,256 |
| $ | 459 |
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For the three months ended June 30, 2018 compared to the three months ended March 31, 2018, greenhouse gas allowance costs increased due to the higher unit cost and increased activity.
Other income and (expenses)
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| | Berry Corp.
(Successor) |
| | Three Months Ended | Three Months Ended | |
| | June 30, 2018 | March 31, 2018 | Variance |
| (in thousands) | | | |
| Interest expense, net of amounts capitalized | $ | (9,155 | ) | $ | (7,796 | ) | $ | (1,359 | ) |
| Other, net | (239 | ) | 27 |
| (266 | ) |
| | $ | (9,394 | ) | $ | (7,769 | ) | $ | (1,625 | ) |
Interest expense increasedTransportation expenses were comparable for the three months ended June 30, 2018 by $1.4 million or 17%, compared to the three months ended March 31, 2018, due to increased borrowingsperiods presented.
Gains and losses on the RBL Facility and three monthsnatural gas purchase derivatives resulted in a loss of the interest on the 2026 Notes in the second quarter versus one and a half months in the first quarter.
The following table summarizes the components of reorganization items included in the statement of operations: |
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| | Berry Corp. (Successor) |
| | Three Months Ended | Three Months Ended | |
| (in thousands) | June 30, 2018 | March 31, 2018 | Variance |
| Return of Undistributed Funds from Cash Distribution Pool | $ | — |
| $ | 9,000 |
| $ | (9,000 | ) |
| Refund of pre-emergence prepaid costs | — |
| 579 |
| (579 | ) |
| Legal and other professional advisory fees | (1,178 | ) | (624 | ) | (554 | ) |
| Gain on resolution of pre-emergence liabilities | 1,634 |
| — |
| 1,634 |
|
| | $ | 456 |
| $ | 8,955 |
| $ | (8,499 | ) |
Reorganization items, net consisted of a gain of approximately $0.5 million for the three months ended June 30, 2018. The gain was primarily due to the resolution of certain pre-emergence liabilities, partially offset by legal and other professional fees. For the three months ended March 31, 2018, the gain of $9 million reflected the return of undistributed funds reserved for settlement of claims of general unsecured creditors.
Income taxes
The three months ended June 30, 2018 had a $5.5 million tax benefit compared to income tax expense of $0.9$4 million for the three months ended March 31, 2018. The effective tax rate was 16%2024 and a loss of $21 million for the three months ended June 30, 2018 and 13%December 31, 2023. Settlements for the three months ended March 31, 2018.2024 and December 31, 2023 were a loss of $4 million, or $1.91 per boe, and a loss of $2 million, or $0.93 per boe, respectively. The increased loss was due to an decrease in settlement price relative to the fixed price in the first quarter of 2024 compared to the fourth quarter of 2023. The mark-to-market valuation loss for the three months ended March 31, 2024 was $0.1 million compared to a loss of $19 million for the three months ended December 31, 2023. Because we are the fixed price payer on these natural gas swaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).
Acquisition costs increased $2 million for the three months ended March 31, 2024 compared to the three months ended December 31, 2023, and includes legal and other professional expenses related to various transaction activities.
ResultsGeneral and administrative expenses were flat at $20 million for the three months ended March 31, 2024, compared to the three months ended December 31, 2023. For the three months ended March 31, 2024, general and administrative expenses included immaterial non-cash stock compensation costs, the result of Operations - stock award forfeitures, compared to $3 million for three months ended December 31, 2023. We incurred non-recurring costs related to severance of approximately $1 million for the three months ended March 31, 2024 and none for the three months ended December 31, 2023.
Adjusted General and Administrative Expenses, which excludes non-cash stock compensation expense and non-recurring costs, increased $1 million primarily due to higher payroll taxes driven by stock vestings for the three months ended March 31, 2024 compared to the three months ended December 31, 2023. See “—Non-GAAP Financial Measures” for a reconciliation of general and administrative expenses, the most directly comparable financial measure calculated and presented in accordance with GAAP, to Adjusted General and Administrative Expenses.
DD&A increased $2 million for the three months ended March 31, 2024 compared to the three months ended December 31, 2023 due to higher depletion rates.
Taxes, Other Than Income Taxes
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| Three Months Ended | | $ Change | | % Change |
| March 31, 2024 | | December 31, 2023 | |
| (per boe) | | | | |
| Severance taxes | $ | 1.67 | | | $ | 1.41 | | | $ | 0.26 | | | 18 | % |
| Ad valorem and property taxes | 2.51 | | | 1.96 | | | 0.55 | | | 28 | % |
| Greenhouse gas allowances and other emission costs | 2.61 | | | 3.27 | | | (0.66) | | | (20) | % |
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| Total taxes other than income taxes | $ | 6.79 | | | $ | 6.64 | | | $ | 0.15 | | | 2 | % |
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Taxes, other than income taxes, increased in the three months ended March 31, 2024 by $0.15 per boe, or 2%, to $6.79. The increase in ad valorem and property taxes is due to increased property values in part due to the additional properties acquired in 2023. This is partially offset by a decrease in greenhouse gas allowance expense due to lower mark-to-market-prices.
Interest Expense
Interest expense increased $1 million for the three months ended March 31, 2024, compared to the three months ended December 31, 2023 as we had higher working capital borrowings on the RBL Facility.
Income Taxes
Our effective tax rate was 26% for the three months ended March 31, 2024 and 29% for the three months ended December 31, 2023. The rate in both periods included the impact of certain permanent items which were not deductible.
Three Months Ended
June 30, 2018March 31, 2024 compared to Three Months Ended
June 30, 2017.March 31, 2023. |
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| | Berry Corp.
(Successor) | |
| | Three Months Ended | Three Months Ended | | |
| (in thousands) | June 30, 2018 | June 30, 2017 | $ Change | % Change |
| Revenues and other: | | | | |
| Oil, natural gas and NGL sales | $ | 137,385 |
| $ | 101,884 |
| $ | 35,501 |
| 35 | % |
| Electricity sales | 5,971 |
| 5,712 |
| 259 |
| 5 | % |
| (Losses) gains on oil and natural gas derivatives | (78,143 | ) | 23,962 |
| (102,105 | ) | (426 | )% |
| Marketing and other revenues | 769 |
| 3,164 |
| (2,395 | ) | (76 | )% |
| | 65,982 |
| 134,722 |
| (68,740 | ) | (51 | )% |
| Expenses and other: | | |
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| Lease operating expenses | 41,517 |
| 45,726 |
| (4,209 | ) | (9 | )% |
| Electricity generation expenses | 3,135 |
| 4,465 |
| (1,330 | ) | (30 | )% |
| Transportation expenses | 2,343 |
| 9,404 |
| (7,061 | ) | (75 | )% |
| Marketing expenses | 407 |
| 730 |
| (323 | ) | (44 | )% |
| General and administrative expenses | 12,482 |
| 22,257 |
| (9,775 | ) | (44 | )% |
| Depreciation, depletion, amortization and accretion | 21,859 |
| 20,549 |
| 1,310 |
| 6 | % |
| Taxes, other than income taxes | 8,715 |
| 10,249 |
| (1,534 | ) | (15 | )% |
| (Gains) losses on sale of assets and other, net | 123 |
| 5 |
| 118 |
| 2,360 | % |
| | 90,581 |
| 113,385 |
| (22,804 | ) | (20 | )% |
| Other income and (expenses): | | |
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| Interest expense | (9,155 | ) | (4,885 | ) | (4,270 | ) | 87 | % |
| Other, net | (239 | ) | 2,916 |
| (3,155 | ) | (108 | )% |
| Reorganization items, net | 456 |
| 713 |
| (257 | ) | (36 | )% |
| Income (loss) before income taxes | (33,537 | ) | 20,081 |
| (53,618 | ) | (267 | )% |
| Income tax expense (benefit) | (5,476 | ) | 7,961 |
| (13,437 | ) | (169 | )% |
| Net income (loss) | (28,061 | ) | 12,120 |
| (40,181 | ) | (332 | )% |
| Dividends on Series A Preferred Stock | (5,650 | ) | (5,404 | ) | (246 | ) | 5 | % |
| Net income (loss) available to common stockholders | $ | (33,711 | ) | $ | 6,716 |
| $ | (40,427 | ) | (602 | )% |
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March 31, | | $ Change | | % Change |
| 2024 | | 2023 | |
| (in thousands) | | | | |
| Revenues and other: | | | | | | | |
| Oil, natural gas and NGL sales | $ | 166,318 | | | $ | 166,357 | | | $ | (39) | | | — | % |
Service revenue(1) | 31,683 | | | 44,623 | | | (12,940) | | | (29) | % |
| Electricity sales | 4,243 | | | 5,445 | | | (1,202) | | | (22) | % |
| (Losses) gains on oil and gas sales derivatives | (71,200) | | | 38,499 | | | (109,699) | | | n/a |
| Other revenues | 67 | | | 45 | | | 22 | | | 49 | % |
| Total revenues and other | $ | 131,111 | | | $ | 254,969 | | | $ | (123,858) | | | (49) | % |
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__________(1) The well servicing and abandonment segment occasionally provides services to our E&P segment. Prior to the intercompany elimination, service revenue was approximately $35 million and $46 million, and after the intercompany elimination of $4 million and $2 million, net service revenue was approximately $32 million and approximately $45 million for the quarters ended March 31, 2024 and 2023, respectively.
Revenues and Other
Oil, natural gas and NGL sales increased $36 million, or 35% towere flat at approximately $137$166 million for the three months ended June 30, 2018March 31, 2024 when compared to the three months ended June 30, 2017. The increase reflects improved oil pricesMarch 31, 2023. Oil sales revenue increased approximately $11 million, primarily from higher sales volume, and an increased mixwas offset by the effect of oil productionlower natural gas prices.
Service revenue decreased by $13 million to $32 million for the three months ended March 31, 2024, compared to gas production asthe three months ended March 31, 2023, due to lower activity and a result of the Hill Acquisition and Hugoton Disposition, partially offset by decreased production on an oil-equivalent basis.
shift in service from third parties to our E&P segment.
Electricity sales represent sales to utilities and increased by approximately $0.3decreased $1 million, or 5%22%, to approximately $6$4 million for the three months ended June 30, 2018,March 31, 2024 when compared to the three months ended June 30, 2017. The increaseMarch 31, 2023. This decrease was primarily due to lower energy prices partially offset by higher volumes sold externally as a resultresource adequacy revenue.
Gain or loss on oil and gas sales derivatives consists of lower downtime at our cogens insettlement gains and losses and mark-to-market gains and losses. Our settlement losses for the three months ended June 30, 2018March 31, 2024 and March 31, 2023 were $5 million and $7 million, respectively. The decrease in settlement losses was driven by lower oil prices relative to our derivative fixed prices in the first quarter of 2024 than that of the same period in 2023. Notional volumes were 17 mbbl/d in the first quarter of 2024 and 15 mbbl/d in the first quarter of 2023. The mark-to-market non-cash loss for the three months ended June 30, 2017.
Losses on oilMarch 31, 2024 was $67 million and natural gas derivatives were approximately $78a gain of $46 million for the three months ended June 30, 2018 comparedMarch 31, 2023. Because we are the floating price payer on these swaps, generally, period to approximately $24 million ofperiod decreases (increases) in the associated price index create valuation gains (losses).
Other revenues were not material for the three months ended June 30, 2017. LossesMarch 31, 2024 and March 31, 2023.
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| Three Months Ended
March 31, | | $ Change | | % Change |
| 2024 | | 2023 | |
| (in thousands) | | | | |
| Expenses and other: | | | | | | | |
| Lease operating expenses | $ | 60,697 | | | $ | 134,835 | | | $ | (74,138) | | | (55) | % |
Costs of services(1) | 27,304 | | | 36,099 | | | (8,795) | | | (24) | % |
| Electricity generation expenses | 1,093 | | | 2,500 | | | (1,407) | | | (56) | % |
| Transportation expenses | 1,059 | | | 1,041 | | | 18 | | | 2 | % |
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Acquisition costs(2) | 2,617 | | | — | | | 2,617 | | | 100 | % |
| General and administrative expenses | 20,234 | | | 31,669 | | | (11,435) | | | (36) | % |
| Depreciation, depletion and amortization | 42,831 | | | 40,121 | | | 2,710 | | | 7 | % |
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| Taxes, other than income taxes | 15,689 | | | 10,460 | | | 5,229 | | | 50 | % |
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| Losses (gains) on natural gas purchase derivatives | 4,481 | | | (610) | | | 5,091 | | | n/a |
| Other operating (income) | (133) | | | (286) | | | (153) | | | 53 | % |
| Total expenses and other | 175,872 | | | 255,829 | | | (79,957) | | | (31) | % |
| Other expenses: | | | | | | | |
| Interest expense | (9,140) | | | (7,837) | | | (1,303) | | | 17 | % |
| Other, net | (83) | | | (75) | | | (8) | | | 11 | % |
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| Total other expenses | (9,223) | | | (7,912) | | | (1,311) | | | 17 | % |
| Loss before income taxes | (53,984) | | | (8,772) | | | (45,212) | | | 515 | % |
| Income tax (benefit) | (13,900) | | | (2,913) | | | (10,987) | | | (377) | % |
| Net loss | $ | (40,084) | | | $ | (5,859) | | | $ | (34,225) | | | 584 | % |
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Adjusted EBITDA(3) | $ | 68,534 | | | $ | 59,337 | | | $ | 9,197 | | | 15 | % |
Adjusted Net Income(3) | $ | 10,910 | | | $ | 5,307 | | | $ | 5,603 | | | 106 | % |
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__________(1) The well servicing and abandonment segment occasionally provides services to our E&P segment. Prior to the intercompany elimination, costs of services was $31 million and $38 million, and after the intercompany elimination of $4 million and $2 million, net costs of services was $27 million and $36 million for the quarters ended March 31, 2024 and December 31, 2023, respectively.
(2) Includes legal and other professional expenses related to various transactions activities.
(3) Adjusted EBITDA and Adjusted Net Income (Loss) are financial measures that are not calculated in accordance with GAAP. For definitions and a reconciliation to the Net Cash Provided by Operating Activities and Net Income (loss), please see “—Non-GAAP Financial Measures”.
Expenses
Lease operating expenses, which do not include the effects of gas purchase hedges, decreased 55% or $74 million on oilan absolute dollar basis to $61 million for the first quarter of 2024 when compared to the first quarter of 2023. The decrease was the result of $75 million lower natural gas (fuel) costs for our California steam generation facilities due to a decline in fuel prices, partially offset by a $1 million increase in non-fuel lease operating expense.
Cost of services decreased $9 million, or 24%, to $27 million for the first quarter of 2024 compared to the first quarter of 2023 primarily due to lower activity.
Electricity generation expenses decreased $1 million, or 56%, to $1 million for the three months ended March 31, 2024 compared to the same period in 2023 due to a decrease in fuel prices.
Gains and losses on natural gas purchase derivatives for the three months ended June 30, 2018March 31, 2024 and March 31, 2023 resulted in a loss of $4 million and a gain of $1 million, respectively. Settlements for the three months ended March 31, 2024 were primarilya loss of $4 million, or $1.91 per boe, and a gain of $55 million or $25.11 per boe for the three
months ended March 31, 2023. The change in settlements was due to an increasea decline in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commoditynatural gas index prices relative tobelow the fixed pricesprice of our derivative contracts.
Marketing and other revenues decreased by approximately $2 million, or 76%, to approximately $0.8settled positions. The mark-to-market non-cash loss was $0.1 million for the three months ended June 30, 2018, compared to theMarch 31, 2024 and $54 million for three months ended June 30, 2017. Marketing revenues inMarch 31, 2023. Because we are the fixed price payer on these periods primarily represent sales of third-party natural gas andswaps, generally, period to period increases (decreases) in the associated price index create valuation gains (losses).
Transportation expenses were comparable for these periods. Other revenues in 2017 comprised mostly helium sales, all of which were derived from our Hugoton asset prior to its disposition in July 2017.the periods presented.
Expenses and Other
We report sales of electricity, marketing and transportation activities (as applicable) 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.
Operating expenses, as defined above, decreased to $16.89 per Boe for the quarter ended June 30, 2018 from $17.20 per Boe for the quarter ended June 30, 2017, for the reasons noted below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $4 million, or 9%, to approximately $42 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017. The decrease was primarily due to a decrease in the price of fuel gas used in operations. Further, lease operating expenses per BoeAcquisition costs increased to $17.24 per Boe for the three months ended June 30, 2018 from $14.62 per Boe for the three months ended June 30, 2017, primarily due to increased oil production to 80% of total production from 56% of total production as a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) which adversely impacted costs per Boe. Replacing low cost natural gas production with oil production in 2017 had a disproportionate impact (oil volume rose 10% and gas volume decreased 62% but cost per Boe rose 18%), on our costs per Boe when comparing these respective periods.
Electricity generation expenses decreased approximately $1 million or 30% to $3 million for the three months ended June 30, 2018 andMarch 31, 2024 compared to the three months ended June 30, 2017, primarily dueMarch 31, 2023, and includes legal and other professional expenses related to a decreasevarious transaction activities.
General and administrative expenses decreased $11 million or 36% in the pricethree months ended March 31, 2024 when compared to the three months ended March 31, 2023. For the three months ended March 31, 2024 general and administrative expenses had an immaterial amount of natural gas.
Transportation expenses decreased by approximately $7non-cash stock compensation expense, the result of stock award forfeitures, compared to $5 million or 75%, to approximately $2for March 31, 2023. We incurred non-recurring costs of $1 million for the three months ended June 30, 2018,March 31, 2024 compared to $7 million for the three months ended March 31, 2023.
Adjusted General and Administrative Expenses, which exclude non-cash stock compensation expense and non-recurring costs decreased $1 million for the three months ended March 31, 2024 compared to the three months ended June 30, 2017, primarily dueMarch 31, 2023. The decrease was the result of lower professional services and employee compensation costs. See “—Non-GAAP Financial Measures” for a reconciliation of general and administrative expenses, the most directly comparable financial measure calculated and presented in accordance with GAAP, to the Hugoton Disposition of gas properties, which required significant transportation expense because gas transportation is generally borne by the sellerAdjusted General and oil transportation costs are borne by the buyer.Administrative Expenses.
Marketing expenses decreased $0.3DD&A increased $3 million, or 44%7%, to $0.4$43 million forin the three months ended June 30, 2018March 31, 2024 when compared to the three months ended June 30, 2017, primarilyMarch 31, 2023 due to the decreasean increase in natural gas prices.depletion rates.
General and administrative expenses decreased by approximately $10 million, or 44%,Taxes, Other Than Income Taxes
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March 31, | | $ Change | | % Change |
| 2024 | | 2023 | |
| (per boe) | | | | |
| Severance taxes | $ | 1.67 | | | $ | 1.81 | | | $ | (0.14) | | | (8) | % |
| Ad valorem and property taxes | 2.51 | | | 2.21 | | | 0.30 | | | 14 | % |
| Greenhouse gas allowances and other emission costs | 2.61 | | | 0.76 | | | 1.85 | | | 243 | % |
| Total taxes other than income taxes | $ | 6.79 | | | $ | 4.78 | | | $ | 2.01 | | | 42 | % |
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Taxes, other than income taxes increased 42% to approximately $12 million$6.79 per boe for the three months ended June 30, 2018March 31, 2024, compared to $4.78 per boe for the three months ended March 31, 2023. The GHG allowance expense increase was due to higher mark-to-market prices in the first quarter of 2024. The increase in ad valorem and property taxes is due to increased property values in part due to the additional properties acquired in 2023.
Interest Expense
Interest expense increased $1 million, or 17%, in the three months ended March 31, 2024 when compared to the three months ended June 30, 2017, primarily due toMarch 31, 2023 as we had higher working capital borrowings on the management change in conjunction with our emergence from bankruptcy. The reduction in absolute dollars spent, as well as lower production volumes resulted in lower general and administrative expenses of $5.18 per BoeRBL Facility.
Income Taxes
Our effective tax rate was approximately 26% for the three months ended June 30, 2018,March 31, 2024 compared to $7.11 per Boeapproximately 33% for the three months ended June 30, 2017.March 31, 2023. The rate in both periods included the impact of certain permanent items which were not deductible.
E&P Field Operations
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| March 31, 2024 | | December 31, 2023 | | $ Change | | % Change |
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| Expenses from field operations | | | | | | | |
| Lease operating expenses | $ | 26.28 | | | $ | 28.25 | | | $ | (1.97) | | | (7) | % |
| Electricity generation expenses | 0.47 | | | 0.77 | | | (0.30) | | | (39) | % |
| Transportation expenses | 0.46 | | | 0.53 | | | (0.07) | | | (13) | % |
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| Total | $ | 27.21 | | | $ | 29.55 | | | $ | (2.34) | | | (8) | % |
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| Cash settlements paid for gas purchase hedges | $ | 1.91 | | | $ | 0.93 | | | $ | 0.98 | | | 105 | % |
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| Electricity sales | $ | 1.84 | | | $ | 1.22 | | | $ | 0.62 | | | 51 | % |
| Transportation sales | 0.03 | | | 0.13 | | | (0.10) | | | (77) | % |
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| Total | $ | 1.87 | | | $ | 1.35 | | | $ | 0.52 | | | 39 | % |
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| March 31, 2024 | | March 31, 2023 | | $ Change | | % Change |
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| Lease operating expenses | $ | 26.28 | | | $ | 61.65 | | | $ | (35.37) | | | (57) | % |
| Electricity generation expenses | 0.47 | | | 1.14 | | | (0.67) | | | (59) | % |
| Transportation expenses | 0.46 | | | 0.48 | | | (0.02) | | | (4) | % |
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| Total | $ | 27.21 | | | $ | 63.27 | | | $ | (36.06) | | | (57) | % |
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| Cash settlements paid (received) for gas purchase hedges | $ | 1.91 | | | $ | (25.11) | | | $ | 27.02 | | | (108) | % |
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| Electricity sales | $ | 1.84 | | | $ | 2.49 | | | $ | (0.65) | | | (26) | % |
| Transportation sales | 0.03 | | | 0.02 | | | 0.01 | | | 50 | % |
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| Total | $ | 1.87 | | | $ | 2.51 | | | $ | (0.64) | | | (25) | % |
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See “—How We Plan and Evaluate Operations” for details.
Non-GAAP Financial Measures
Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss), and Adjusted General and Administrative Expenses
Adjusted Net Income (Loss) is not a measure of net income (loss), Adjusted Free Cash Flow is not a measure of cash flow, and Adjusted EBITDA is not a measure of either net income (loss) or cash flow, in all cases, as determined by GAAP. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and unusual and infrequent items. Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. We also use Adjusted EBITDA in planning our capital expenditure allocation to sustain production levels and to determine our strategic hedging needs aside from the hedging requirements of the 2021 RBL Facility.
We define Adjusted Free Cash Flow, which is a non-GAAP financial measure, as cash flow from operations less regular fixed dividends and capital expenditures. In 2024, we updated the definition of Adjusted Free Cash Flow, a non-GAAP measure, as cash flow from operations less regular fixed dividends and capital expenditures. This update better aligns with the full capital expenditure requirements of the Company. For 2023, Adjusted Free Cash Flow was defined as cash flow from operations less regular fixed dividends and maintenance capital. Management believes Adjusted Free Cash Flow may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base after maintaining the existing production volumes of that asset base to return capital to stockholders, fund further business expansion through acquisitions or investments in our existing asset base to increase production volumes and pay other non-discretionary expenses. Management also uses Adjusted Free Cash Flow as the primary metric to plan for future growth.
Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchases, strategic acquisitions or other growth opportunities, or other discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from this measure.
We define Adjusted Net Income (Loss) as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our statutory tax rate. Adjusted Net Income (Loss) excludes the impact of unusual and infrequent items affecting earnings that vary widely and unpredictably, including non-cash items such as derivative gains and losses. This measure is used by management when comparing results period over period. We believe Adjusted Net Income (Loss) is useful to investors because it reflects how management evaluates the Company’s ongoing financial and operating performance from period-to-period after removing certain transactions and activities that affect comparability of the metrics and are not reflective of the Company’s core operations. We believe this also makes it easier for investors to compare our period-to-period results with our peers.
We define Adjusted General and Administrative Expenses as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and infrequent costs. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period. We believe Adjusted General and Administrative Expenses is useful to investors because it reflects how management evaluates the Company’s ongoing general and administrative expenses from period-to-period after removing non-cash stock compensation, as well as unusual or infrequent costs that affect comparability of the metrics and are not reflective of the Company’s administrative costs. We believe this also makes it easier for
investors to compare our period-to-period results with our peers.
While Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses are non-GAAP measures, the amounts included in the calculation of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and should not be considered as an alternative to, or more meaningful than income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Our computations of Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by other companies. Adjusted EBITDA, Adjusted Free Cash Flow, Adjusted Net Income (Loss) and Adjusted General and Administrative Expenses should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
The following tables present reconciliations of the GAAP financial measures of net income (loss) and net cash provided (used) by operating activities to the non-GAAP financial measure of Adjusted EBITDA, as applicable, for each of the periods indicated.
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2023 | | March 31,
2023 | | | | |
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| Adjusted EBITDA reconciliation: |
| Net (loss) income | $ | (40,084) | | | $ | 62,551 | | | $ | (5,859) | | | | | |
| Add (Subtract): | | | | | | | | | |
| Interest expense | 9,140 | | | 9,680 | | | 7,837 | | | | | |
| Income tax (benefit) expense | (13,900) | | | 25,665 | | | (2,913) | | | | | |
| Depreciation, depletion and amortization | 42,831 | | | 40,937 | | | 40,121 | | | | | |
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| Losses (gains) on derivatives | 75,681 | | | (62,521) | | | (39,109) | | | | | |
| Net cash (paid) received for scheduled derivative settlements | (9,094) | | | (9,616) | | | 47,467 | | | | | |
| Other operating (income) expenses | (133) | | | 36 | | | (286) | | | | | |
Stock compensation expense(1) | 385 | | | 3,020 | | | 4,766 | | | | | |
Acquisition costs(2) | 2,617 | | | 284 | | | — | | | | | |
Non-recurring costs(3) | 1,091 | | | — | | | 7,313 | | | | | |
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| Adjusted EBITDA | $ | 68,534 | | | $ | 70,036 | | | $ | 59,337 | | | | | |
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| Three Months Ended | | |
| March 31,
2024 | | December 31,
2023 | | March 31,
2023 | | | | |
| (in thousands) |
| Adjusted EBITDA reconciliation: |
| Net cash provided by operating activities | $ | 27,273 | | | $ | 79,018 | | | $ | 1,781 | | | | | |
| Add (Subtract): | | | | | | | | | |
| Cash interest payments | 15,256 | | | 1,794 | | | 14,388 | | | | | |
| Cash income tax payments | — | | | 525 | | | — | | | | | |
Acquisition costs(2) | 2,617 | | | 284 | | | — | | | | | |
Non-recurring costs(3) | 1,091 | | | — | | | 7,313 | | | | | |
| | | | | | | | | |
Changes in operating assets and liabilities - working capital(4) | 22,543 | | | (11,070) | | | 36,745 | | | | | |
Other operating (income) expenses - cash portion(5) | (246) | | | (515) | | | (890) | | | | | |
| | | | | | | | | |
| Adjusted EBITDA | $ | 68,534 | | | $ | 70,036 | | | $ | 59,337 | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
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__________(1) Decrease in the first quarter of 2024 is the result of stock award forfeitures.
(2) Includes legal and other professional expenses related to various transaction activities.
(3) In 2024, non-recurring costs included workforce reduction costs in the first quarter. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter.
(4) Changes in other assets and liabilities consists of working capital and various immaterial items.
(5) Represents the cash portion of other operating (income) expenses from the income statement, net of the non-cash portion in the cash flow statement.
The following table presents a reconciliation of the GAAP financial measure of operating cash flow to the non-GAAP financial measure of Adjusted Free Cash Flow for each of the periods indicated. We use Adjusted Free Cash Flow for our shareholder return model.
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31,
2024 | | December 31,
2023 | | March 31,
2023 | | | | |
| (in thousands) |
| Adjusted Free Cash Flow reconciliation: | | | | | | | | |
Net cash provided by operating activities(1) | $ | 27,273 | | | $ | 79,018 | | | $ | 1,781 | | | | | |
| Subtract: | | | | | | | | | |
Capital expenditures(2) | (16,936) | | | (15,114) | | | (19,272) | | | | | |
Fixed dividends(3) | (9,233) | | | (9,080) | | | (9,190) | | | | | |
| Adjusted Free Cash Flow | $ | 1,104 | | | $ | 54,824 | | | $ | (26,681) | | | | | |
__________
(1) On a consolidated basis.
(2) In 2024, we updated Adjusted Free Cash Flow to include all capital expenditures in the calculation of Adjusted Free Cash Flow. This update better aligns with the full capital expenditure requirements of the Company. In 2023, the definition of capital expenditures was the required amount to keep annual production essentially flat (maintenance capital), calculated as the capital expenditures for the E&P business for the periods presented. We did not retrospectively adjust 2023.
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| | | | | | | | Three Months Ended | | | | |
| | | | | | December 31,
2023 | | March 31,
2023 | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | (in thousands) |
Consolidated capital expenditures(a) | | | | | | | | $ | (17,003) | | | $ | (20,633) | | | | | | | |
Excluded items(b) | | | | | | | | 1,889 | | | 1,361 | | | | | | | |
| Maintenance capital | | | | | | | | $ | (15,114) | | | $ | (19,272) | | | | | | | |
__________
(a) Capital expenditures include capitalized overhead and interest and excludes acquisitions and asset retirement spending.
(b) Comprised of the capital expenditures in our E&P segment that are related to strategic business expansion, such as acquisitions of oil and gas properties and any exploration and development activities to increase production beyond the prior year’s annual production volumes and capital expenditures in our well servicing and abandonment segment and corporate expenditures that are related to ancillary sustainability initiatives or other expenditures that are discretionary and unrelated to maintenance of our core business. For the three months ended June 30, 2018, generalDecember 31, 2023 and administrative expenses included non-recurring restructuringMarch 31, 2023, we excluded approximately $1 million of capital expenditures related to our well servicing and abandonment segment, for both periods presented, which was substantially all used for sustainability initiatives or other costsexpenditures that are discretionary and unrelated to maintenance of approximately $1.7 million and non-cash stock compensation costs of approximately $1.3 million.our core business. For the three months ended June 30, 2017,December 31, 2023 and March 31, 2023, we excluded approximately $0.5 million and $0.4 million of corporate capital expenditures, respectively, which we determined was not related to the maintenance of our baseline production.
(3) Represents fixed dividends declared for the periods presented.
The following table presents a reconciliation of the GAAP financial measures of net income (loss) and net income (loss) per share — diluted to the non-GAAP financial measures of Adjusted Net Income (Loss) and Adjusted Net Income (Loss) per share — diluted for each of the periods indicated.
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| Three Months Ended |
| March 31, 2024 | | December 31, 2023 | | March 31, 2023 |
| (in thousands) | | per share - diluted | | (in thousands) | | per share - diluted | | (in thousands) | | per share - diluted |
| Adjusted Net Income (Loss) reconciliation: | | |
| Net (loss) income | $ | (40,084) | | | $ | (0.52) | | | $ | 62,551 | | | $ | 0.81 | | | $ | (5,859) | | | $ | (0.07) | |
| | | | | | | | | | | |
| Add (Subtract): | | | | | | | | | | | |
| Losses (gains) on derivatives | 75,681 | | | 0.98 | | | (62,521) | | | (0.81) | | | (39,109) | | | (0.49) | |
| Net cash (paid) received for scheduled derivative settlements | (9,094) | | | (0.12) | | | (9,616) | | | (0.12) | | | 47,467 | | | 0.60 | |
| Other operating (income) expenses | (133) | | | — | | | 36 | | | — | | | (286) | | | (0.01) | |
| | | | | | | | | | | |
Acquisition costs(1) | 2,617 | | | 0.03 | | | 284 | | | — | | | — | | | — | |
Non-recurring costs(2) | 1,091 | | | 0.02 | | | — | | | — | | | 7,313 | | | 0.09 | |
| | | | | | | | | | | |
| Total additions (subtractions), net | 70,162 | | | 0.91 | | | (71,817) | | | (0.93) | | | 15,385 | | | 0.19 | |
Income tax (benefit) expense of adjustments(3) | (19,168) | | | (0.25) | | | 19,692 | | | 0.25 | | | (4,219) | | | (0.05) | |
| Adjusted Net Income | $ | 10,910 | | | $ | 0.14 | | | $ | 10,426 | | | $ | 0.13 | | | $ | 5,307 | | | $ | 0.07 | |
| | | | | | | | | | | |
| Basic EPS on Adjusted Net Income | $ | 0.14 | | | | | $ | 0.14 | | | | | $ | 0.07 | | | |
| Diluted EPS on Adjusted Net Income | $ | 0.14 | | | | | $ | 0.13 | | | | | $ | 0.07 | | | |
| | | | | | | | | | | |
| Weighted average shares of common stock outstanding - basic | 76,254 | | | | 75,667 | | | | 76,112 | | | |
| Weighted average shares of common stock outstanding - diluted | 77,373 | | | | 77,349 | | | | 79,210 | | | |
__________(1) Includes legal and other professional expenses related to various transaction activities.
(2) In 2024, non-recurring costs included workforce reduction costs in the first quarter. In 2023, non-recurring costs included executive transition costs and workforce reduction costs in the first quarter.
(3) The federal and state statutory rates were utilized for all periods presented.
The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses included non-recurring restructuring and other costs of approximately $17 million and no non-cash stock compensation costs.
DD&A increased by approximately $1 million, or 6%, to approximately $22 million for the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due tonon-GAAP financial measure of Adjusted General and Administrative Expenses for each of the Hill Acquisition. The Hill property which had a higher depletion rate thanperiods indicated.
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| Three Months Ended | | |
| March 31,
2024 | | December 31,
2023 | | March 31,
2023 | | | | |
| (in thousands) |
| Adjusted General and Administrative Expense reconciliation: | | |
| General and administrative expenses | $ | 20,234 | | | $ | 20,729 | | | $ | 31,669 | | | | | |
| Subtract: | | | | | | | | | |
Non-cash stock compensation expense (G&A portion)(1) | (200) | | | (2,843) | | | (4,619) | | | | | |
| | | | | | | | | |
Non-recurring costs(2) | (1,091) | | | — | | | (7,313) | | | | | |
| Adjusted general and administrative expenses | $ | 18,943 | | | $ | 17,886 | | | $ | 19,737 | | | | | |
| | | | | | | | | |
| Well servicing and abandonment segment | $ | 2,929 | | | $ | 2,177 | | | $ | 3,126 | | | | | |
| | | | | | | | | |
| E&P segment, and corporate | $ | 16,014 | | | $ | 15,709 | | | $ | 16,611 | | | | | |
| E&P segment, and corporate ($/boe) | $ | 6.93 | | | $ | 6.59 | | | $ | 7.60 | | | | | |
| | | | | | | | | |
| Total mboe | 2,310 | | 2,384 | | 2,187 | | | | |
| | | | | | | | | |
| | | | | | | | | |
__________(1) Decrease in the Hugoton field.
Taxes, Other Than Income Taxes
|
| | | | | | | | | |
| | Berry Corp. (Successor) |
| | Three Months Ended | Three Months Ended | |
| | June 30, 2018 | June 30, 2017 | Variance |
| (in thousands) | | | |
| Severance taxes | $ | 2,997 |
| $ | 2,466 |
| $ | 531 |
|
| Ad valorem and property taxes | 3,141 |
| 4,498 |
| (1,357 | ) |
| Greenhouse gas allowances | 2,577 |
| 3,285 |
| (708 | ) |
| | $ | 8,715 |
| $ | 10,249 |
| $ | (1,534 | ) |
Taxes, other than income taxes decreased by approximately $1.5 million or 15% for the three months ended June 30, 2018 compared to the three months ended June 30, 2017 due to (i) an increase in gross sales revenue whichfirst quarter of 2024 is the basis for severance taxes, (ii) lower ad valorem and property taxes due to reduced tax assessments in 2018 and (iii) lower prices for greenhouse gas emission credits, partially offset by an increase in emissions in 2018.result of stock award forfeitures.
Other income and (expenses)
|
| | | | | | | | | |
| | Berry Corp. (Successor) |
| | Three Months Ended | Three Months Ended | |
| | June 30, 2018 | June 30, 2017 | Variance |
| (in thousands) | | | |
| Interest expense, net of amounts capitalized | $ | (9,155 | ) | $ | (4,885 | ) | $ | (4,270 | ) |
| Other, net | (239 | ) | 2,916 |
| (3,155 | ) |
| | $ | (9,394 | ) | $ | (1,969 | ) | $ | (7,425 | ) |
Interest expense increased for the three months ended June 30, 2018 by approximately $4 million or 87%, compared to the three months ended June 30, 2017, primarily due to the addition of interest expense on the 2026 Notes, which were issued in February 2018, partially offset by lower interest on the RBL Facility due to the decrease in borrowings period over period.
The following table summarizes the components of reorganization items(2) In 2024, non-recurring costs included workforce reduction costs in the statement of operations: |
| | | | | | | | | |
| | Berry Corp. (Successor) |
| | Three Months Ended | Three Months Ended | |
| (in thousands) | June 30, 2018 | June 30, 2017 | Variance |
| Legal and other professional advisory fees | (1,178 | ) | (3,199 | ) | 2,021 |
|
| Gain on resolution of pre-emergence liabilities | 1,634 |
| 3,912 |
| (2,278 | ) |
| | $ | 456 |
| $ | 713 |
| $ | (257 | ) |
Reorganization items, net consisted of a gain of approximately $0.5 million for the three months ended June 30, 2018, compared to the $0.7 million gain for the three months ended June 30, 2017. The second quarter 2018 gain was primarily due to the resolution of certain pre-emergence liabilities, partially offset by legalfirst quarter. In 2023, non-recurring costs included executive transition costs and other professional fees. The 2017 gain amount was primarily due to a resolution of certain pre-emergence liabilities of $3.9 million partially offset by legal and professional fees to resolve outstanding bankruptcy-related claims.
Income tax benefit was $5.5 million for the three months ended June 30, 2018, compared to the income tax expense of $8.0 million for the three months ended June 30, 2017 due to recording pre-tax loss in 2018 compared to pre-tax income in 2017. The decreaseworkforce reduction costs in the effective tax rates from 40% in 2017 to 16% in 2018 was primarily a resultfirst quarter.
Results of Operations - Six Months Ended June 30, 2018 compared to the Six Months ended June 30, 2017 , including the successor and predecessor periods.
Our results of operations for the six months ended June 30, 2017 are reflected in the tables and narrative discussion that follow in two distinct periods, the four months ended June 30, 2017 and the two months ended February 28, 2017, as a result of our emergence from bankruptcy on February 28, 2017. References in these results of operations to the six months ended June 30, 2017 are used to provide comparable periods. While this combined presentation is a non-GAAP presentation for which there is no comparable GAAP measure, management believes that providing this financial information is the most relevant and useful method for comparing the periods presented.
|
| | | | | | | | | | | | | | |
| | Berry Corp.
(Successor) | Berry LLC (Predecessor) | | |
| | (a) | (b) | (c) | (a)-((b)+(c)) | |
| | Six Months Ended | Four Months Ended | Two Months Ended | | |
| | June 30, 2018 | June 30, 2017 | February 28, 2017 | $ Change | % Change |
| (in thousands) | | | | | |
| Revenues and other: | | | | | |
| Oil, natural gas and NGL sales | $ | 263,010 |
| $ | 135,562 |
| $ | 74,120 |
| $ | 53,328 |
| 25 | % |
| Electricity sales | 11,423 |
| 6,603 |
| 3,655 |
| 1,165 |
| 11 | % |
| (Losses) gains on oil and natural gas derivatives | (112,787 | ) | 48,085 |
| 12,886 |
| (173,758 | ) | (285 | )% |
| Marketing and other revenues | 1,619 |
| 4,127 |
| 2,057 |
| (4,565 | ) | (74 | )% |
| | 163,265 |
| 194,377 |
| 92,718 |
| (123,830 | ) | (43 | )% |
| Expenses and other: | | | | — |
| |
| Lease operating expenses | 85,819 |
| 58,790 |
| 28,238 |
| (1,209 | ) | (1 | )% |
| Electricity generation expenses | 7,725 |
| 5,613 |
| 3,197 |
| (1,085 | ) | (12 | )% |
| Transportation expenses | 5,321 |
| 13,059 |
| 6,194 |
| (13,932 | ) | (72 | )% |
| Marketing expenses | 987 |
| 1,000 |
| 653 |
| (666 | ) | (40 | )% |
| General and administrative expenses | 24,466 |
| 31,800 |
| 7,964 |
| (15,298 | ) | (38 | )% |
| Depreciation, depletion, amortization and accretion | 40,288 |
| 27,571 |
| 28,149 |
| (15,432 | ) | (28 | )% |
| Taxes, other than income taxes | 16,972 |
| 13,330 |
| 5,212 |
| (1,570 | ) | (8 | )% |
| (Gains) losses on sale of assets and other, net | 123 |
| 5 |
| (183 | ) | 301 |
| (169 | )% |
| | 181,701 |
| 151,168 |
| 79,424 |
| (48,891 | ) | (21 | )% |
| Other income and (expenses): | | | | — |
| |
| Interest expense | (16,951 | ) | (6,600 | ) | (8,245 | ) | (2,106 | ) | 14 | % |
| Other, net | (212 | ) | 2,916 |
| (63 | ) | (3,065 | ) | (107 | )% |
| Reorganization items, net | 9,411 |
| (593 | ) | (507,720 | ) | 517,724 |
| (102 | )% |
| Income (loss) before income taxes | (26,188 | ) | 38,932 |
| (502,734 | ) | 437,614 |
| (94 | )% |
| Income tax expense (benefit) | (4,537 | ) | 15,435 |
| 230 |
| (20,202 | ) | (129 | )% |
| Net income (loss) | (21,651 | ) | 23,497 |
| (502,964 | ) | 457,816 |
| (95 | )% |
| Dividends on Series A Preferred Stock | (11,301 | ) | (7,196 | ) | — |
| (4,105 | ) | 57 | % |
| Net income (loss) available to common stockholders | $ | (32,952 | ) | $ | 16,301 |
| $ | (502,964 | ) | $ | 453,711 |
| (93 | )% |
Revenues and Other
Oil, natural gas and NGL sales increased approximately $53 million, or 25% to approximately $263 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods. The increase reflects improved oil prices and an increased mix of oil production compared to gas production as a result of the Hill Acquisition and Hugoton Disposition, partially offset by decreased overall production, as well as slightly lower gas prices.
Electricity sales represent sales to utilities and increased by approximately $1 million, or 11%, to approximately $11 million for the six months ended June 30, 2018, compared to the six months ended June 30, 2017, including the successor and predecessor periods, primarily due to higher volumes sold externally as a result of lower downtime at our cogens.
Losses on oil and natural gas derivatives increased to approximately $113 million in the six months ended June 30, 2018, compared to gains of approximately $61 million in the six months ended June 30, 2017, including the successor and predecessor periods. Losses on oil and natural gas derivatives in 2018 were primarily due to an increase in hedging activity, a portion of which was required by the RBL Facility at closing in July 2017, and improved commodity prices relative to the fixed prices of our derivative contracts.
Marketing and other revenues decreased approximately $5 million or 74% for the six months ended June 30, 2018 when compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the lost helium sales revenue as a result of the Hugoton Disposition.
Expenses and other
We report sales of electricity, marketing and transportation activities (as applicable) 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. Operating expenses increased to $18.24 per Boe for the six months ended June 30, 2018 from $15.78 for the six months ended June 30, 2017 including the successor and predecessor periods, for the reasons described below.
Lease operating expenses include fuel, labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses in absolute dollars for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods, reflected lower fuel gas costs offset by higher activity in 2018 compared to 2017. Lease operating expenses per Boe increased to $18.01 per Boe for the six months ended June 30, 2018, from $13.69 per Boe for the six months ended June 30, 2017, including the successor and predecessor periods. The increase in oil production to 80% of total production from 56% as a result of the Hugoton Disposition (natural gas production) and Hill Acquisition (oil production) adversely impacted costs per Boe in 2018 compared to 2017.
Electricity generation expenses were comparable for the six months ended June 30, 2018 and the six months ended June 30, 2017, including the successor and predecessor periods.
Transportation expenses decreased by approximately $14 million or 72% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the Hugoton disposition of gas properties, which required significant transportation expense because gas transportation is generally borne by the seller and oil transportation costs are borne by the buyer.
Marketing expenses decreased $0.7 million or 40% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the decrease in natural gas prices.
General and administrative expenses decreased by approximately $15 million for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, in terms of absolute dollars, primarily due to the reduced spending on non-recurring restructuring and other costs, slightly offset by increased headcount-related costs. This activity was consistent with our post-emergence efforts to build out our corporate structure while reducing restructuring costs. This also resulted in a decrease in general and administrative expenses per Boe to $5.14 in 2018 from $6.25 in 2017 For the six months ended June 30, 2018 and 2017, general and administrative expenses included non-recurring restructuring and other costs of approximately $4 million and $24 million, respectively, and non-cash stock compensation costs of approximately $2.3 million and none, respectively.
Depreciation, depletion and amortization decreased by approximately $15 million, or 28% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including successor and predecessor periods, primarily due to the increase in oil and gas reserves in 2018, which resulted in lower DD&A rates and the fair market revaluation of our assets in fresh start accounting which resulted in a lower depreciable asset base in the periods following our emergence from bankruptcy.
Taxes, Other Than Income Taxes
|
| | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) | |
| | Six Months Ended | Four Months Ended | Two Months Ended | |
| | June 30, 2018 | June 30, 2017 | February 28, 2017 | Variance |
| | (a) | (b) | (c) | (a)-((b)+(c)) |
| (in thousands) | | | | |
| Severance taxes | $ | 5,761 |
| $ | 3,611 |
| $ | 1,540 |
| $ | 610 |
|
| Ad valorem and property taxes | 6,558 |
| 5,572 |
| 2,108 |
| (1,122 | ) |
| Greenhouse gas allowances | 4,653 |
| 4,146 |
| 1,564 |
| (1,057 | ) |
| | $ | 16,972 |
| $ | 13,329 |
| $ | 5,212 |
| $ | (1,569 | ) |
Taxes, other than income taxes decreased by approximately $1.5 million or 15% for the six months ended June 30, 2018 compared to the six months ended June 30, 2017, including the successor and predecessor periods, due to (i) an increase in gross sales revenue which is the basis for severance taxes (ii) lower ad valorem and property taxes due to reduced tax assessments in 2018 and (iii) lower prices for greenhouse gas emission credits, partially offset by an increase in emissions in 2018.
Other income and (expenses)
|
| | | | | | | | | | | | |
| | Berry Corp.
(Successor) | Berry LLC (Predecessor) | |
| | Six Months Ended | Four Months Ended | Two Months Ended | |
| | June 30, 2018 | June 30, 2017 | February 28, 2017 | Variance |
| | (a) | (b) | (c) | (a)-((b)+(c)) |
| (in thousands) | | | | |
| Interest expense, net of amounts capitalized | $ | (16,951 | ) | $ | (6,600 | ) | $ | (8,245 | ) | $ | (2,106 | ) |
| Other, net | (212 | ) | 2,916 |
| (63 | ) | (3,065 | ) |
| | $ | (17,163 | ) | $ | (3,684 | ) | $ | (8,308 | ) | $ | (5,171 | ) |
Interest expense increased by $2 million or 14% for the six months ended June 30, 2018, compared to the six months ended June 30, 2017, including successor and predecessor periods, due to the additional 7% interest expense on the 2026 Notes which were issued in February 2018, partially offset by lower interest on the RBL Facility due to the decrease in borrowings from $385 million at June 30, 2017 to $66 million at June 30, 2018. Other, net for the four months ended June 30, 2017 primarily represents the refund of an overpayment on taxes from a prior year.
The following table summarizes the components of reorganization items included in the statement of operations:
|
| | | | | | | | | | | | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) | |
| | Six Months Ended | Four Months Ended | Two Months Ended | |
| (in thousands) | June 30, 2018 | June 30, 2017 | February 28, 2017 | Variance |
| | (a) | (b) | (c) | (a)-((b)+(c)) |
| Return of Undistributed Funds from Cash Distribution Pool | $ | 9,000 |
| $ | — |
| $ | — |
| $ | 9,000 |
|
| Legal and other professional advisory fees | (1,223 | ) | 112 |
| (19,481 | ) | 18,146 |
|
| Gain on resolution of pre-emergence suspended royalties | — |
| — |
| 421,774 |
| (421,774 | ) |
| Fresh-start valuation adjustments | — |
| — |
| (920,699 | ) | 920,699 |
|
| Gain on resolution of pre-emergence liabilities | 1,634 |
| — |
| — |
| 1,634 |
|
| Other | — |
| (705 | ) | 10,686 |
| (9,981 | ) |
| | $ | 9,411 |
| $ | (593 | ) | $ | (507,720 | ) | $ | 517,724 |
|
Reorganization items, net reflected a gain of approximately $9 million for the six months ended June 30, 2018, compared to an expense of approximately $507 million for the six months ended June 30, 2017, including successor and predecessor periods. The gain for the six months ended 2018 was primarily due to a return of $9 million from the funds reserved for the claims of the general unsecured creditors and the resolution of pre-emergence liabilities in the amount of $1.6 million offset by legal and professional fees of $1.2 million.
The loss for the two months ended February 28, 2017 was primarily due to the application of fresh-start accounting in conjunction with our emergence from bankruptcy, partially offset by the gain on settlement of liabilities subject to compromise. Reorganization items represent costs and income directly associated with the Chapter 11 Proceedings and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.
Income tax benefit was $4.5 million for the six months ended June 30, 2018, compared to an income tax expense of approximately $15.7 million for the six months ended June 30, 2017, including the successor and predecessor periods, due to recording pre-tax income in 2018 compared to a pre-tax loss in 2017. The decrease in the effective tax rates from 40% in 2017 to 17% in 2018 was primarily a result of the new tax laws for 2018.
For federal and state income tax purposes (with the exception of the State of Texas), the predecessor company was a limited liability company in which income tax liabilities and/or benefits were passed through to the Predecessor's unitholders. The Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the predecessor company resulting in an effective tax rate of zero for the two months ended February 28, 2017. The successor company was formed as a C Corporation.
Liquidity and Capital Resources
Currently,As of March 31, 2024, we had liquidity of $149 million, consisting of $3 million cash, $139 million available for borrowings under our 2021 RBL Facility and $7 million available for borrowings under our 2022 ABL Facility (as defined below). Based on current commodity prices and our development success rate to date, we expect to be able to fund our primary sources2024 capital development programs from cash flow from operations.
We review the allocations under our shareholder return model from time to time based on industry conditions, operational results and other factors. In 2024, we updated the definition of liquidity and capital resources will be internally generated freeAdjusted Free Cash Flow, a non-GAAP measure, as cash flow from operations after debt service, or levered freeless regular fixed dividends and all capital expenditures.For 2023, Adjusted Free Cash Flow was defined as cash flow from operations less regular fixed dividends and as needed, borrowings undermaintenance capital. Our goal is to continue maximizing enterprise value through overall returns. Beginning in 2023, the RBL Facility. Depending upon marketannual allocation of Adjusted Free Cash Flow has been (a) 80% primarily in the form of debt repurchases, stock repurchases, strategic growth, and acquisitions of producing bolt-on assets; and (b) 20% in the form of variable dividends. Any dividends (fixed or variable) actually paid will be determined by our Board of Directors in light of then existing conditions and circumstances, including our earnings, financial condition, restrictions in financing agreements, business conditions and other factors,factors. From time to time we consider bolt-on acquisitions, which may be used to maintain our existing production volumes or may support strategic growth, and could be at least partially funded by reallocating a portion of our capital expenditures, as a way of increasing Adjusted Free Cash Flow.
Adjusted Free Cash Flow does not represent the total increase or decrease in our cash balance, and it should not be inferred that the entire amount of Adjusted Free Cash Flow is available for variable dividends, debt or share repurchases, strategic acquisitions or other growth opportunities, or other discretionary expenditures, since we have issuednon-discretionary expenditures that are not deducted from this measure. Adjusted Free Cash Flow is a non-GAAP financial measure. See “Management’s Discussion and may issue additional equity and debt securities; however, we expect our operations to continue to generate sufficient levered freeAnalysis—Non-GAAP Financial Measures” for a reconciliation of the GAAP financial measure of operating cash flow, at current commodity pricesour most directly comparable financial measure calculated and presented in accordance with GAAP, to fund maintenance operations and organic growth. the non-GAAP financial measure of Adjusted Free Cash Flow.
We currently believe that our liquidity, and capital resources and cash will be sufficient to conduct our business and operations and meet our obligations for at least the next 12 months. In the longer term, if oil prices were to significantly decline and remain weak, we may not be able to continue to generate the same level of Adjusted Free Cash Flow we are currently generating and our liquidity and capital resources may not be sufficient to conduct our business and operations until commodity prices recover. Please see Part II, Item 1A. “Risk Factors” in this Quarterly Report and Part I, Item 1A. “Risk Factors” in our Annual Report for a discussion of known material risks, many of which are beyond our control, that could adversely impact our business, liquidity, financial condition, and results of operations.
2021 RBL Facility
See Note 2—Debt in the Notes to Consolidated Financial Statements in Part I, Item 1. “Financial Statements” of this Quarterly Report for details.
2022 ABL Facility
See Note 2—Debt in the Notes to Consolidated Financial Statements in Part I, Item 1. “Financial Statements” of this Quarterly Report for details.
Senior Unsecured Notes
In February 2018, we issued ourBerry LLC completed a private issuance of $400 million in aggregate principal amount of 7.0% senior unsecured notes due February 2026, Notes, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount.
The 2026 Notes are Berry LLC’s senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The 2026 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Berry Corp and certain of its subsidiaries. C&J and C&J Management do not guarantee the 2026 Notes. Macpherson Energy and certain of its subsidiaries became guarantors of the 2026 Notes on January 4, 2024 and February 8, 2024 pursuant to supplemental indentures.
The indenture governing the 2026 Notes contains customary covenants and events of default (in some cases, subject to grace periods). We used the net proceeds to repay borrowingswere in compliance with all covenants under the RBL Facility and used the remainder for general corporate purposes.
In March 2018, our board of directors approved a cumulative paid-in-kind dividend on the Series A Preferred Stock for the periods through December 31, 2017. The cumulative dividend was 0.050907 per share and approximately 1,825,000 shares in total. Also in March 2018, the board approved a $0.158 per share, or approximately $5.6 million, cash dividend on the Series A Preferred Stock for the quarter ended March 31, 2018. In both cases, the payments were to stockholders of record2026 Notes as of March 15, 2018. 31, 2024.
Debt Repurchase Program
In May 2018,February 2020, the board of directors approved(the “Board of Directors”) adopted a $0.15 per share, or approximately $5.6program to spend up to $75 million cash dividend, on the Series A Preferred Stock for the quarter ended June 30, 2018. The payment was made to stockholders of record as of June 7, 2018.
In July, we completed our IPO and as a result, on July 26, 2018, our common stock began trading on the NASDAQ Global Select Market under the ticker symbol BRY. The Company sold 10,497,849 shares and the selling stockholders sold 2,545,630 shares at a price of $14.00 per share. We used a portionopportunistic repurchase of our proceeds to repurchase 1,802,196 shares of our common stock owned by Benefit Street Partners2026 Notes. The manner, timing and Oaktree Capital Management. After giving effect to the IPO and the share repurchase, the number of shares of our common stock outstanding increased by 8,695,653. We and the selling stockholders have granted the underwriters the option to purchase up to an additional 1,534,895 shares and 421,626 shares of common stock, respectively, on the same terms and conditions set forth above.
In connection with the IPO, each of the 37.7 million shares of our Series A Preferred Stock was automatically converted into 1.05 shares of our common stock or 39.6 million shares in aggregate and the right to receive a cash payment of $1.75. The cash payment was reduced in respectamount of any cash dividend paid by the Company on such share of Series A Preferred Stock for any period commencing on or after April 1, 2018. Because we paid the second quarter preferred dividend of $0.15 per share in June, the cash payment for the conversion was reduced to $1.60 per share, or approximately $60 million.
The Company received approximately $136 million in net proceeds from the offering after deducting underwriting discounts and offering expenses payable by us. We did not receive any proceeds from the sale by the selling stockholders. We used approximately $24 million of the net proceeds to purchase shares of our common stock (at a price equal to the price paid by the underwriters for shares of common stock in the offering) from funds affiliated with Benefit Street Partners and Oaktree Capital Management.
Of the remaining approximately $112 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the $60 million we borrowed on the RBL Facility to make the payment to the holders of our Series A Preferred Stock in connection with the conversion of preferred stock to common stock. We used the remainder for general corporate purposes. On August 20, 2018, we had approximately $388 million of available borrowing capacity under the RBL Facility and approximately $36 million of cash on hand.
On August 21, 2018, our board of directors approved a $0.12 per share quarterly cash dividendpurchases will be determined based on our common stock on a pro-rata basis from the dateevaluation of our IPO through September 30, 2018 which will result in a payment of $0.09 per share.
The RBL Facility contains certain financial covenants, including the maintenance of (i) a Leverage Ratio (as defined in the RBL Facility) not to exceed 4.00:1.00 and (ii) a Current Ratio (as defined in the RBL Facility) not to be less than 1.00:1.00. As of June 30, 2018, our Leverage Ratio and Current Ratio were 2.63:1.00 and 3.18:1.00, respectively. As of June 30, 2018 our borrowing base was approximately $400 million and we had $327 million available for borrowing under the RBL Facility. At June 30, 2018, we were inmarket conditions, compliance with the financial covenants under the RBL Facility. In connection with the issuance ofoutstanding agreements and other factors, may be commenced or suspended at any time without notice and do not obligate Berry Corp. to purchase the 2026 Notes the RBL Facility borrowing base was setduring any period or at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. Borrowing base redeterminations become effective on, or about, each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations.all. We have not yet repurchased any notes under this program.
Historically, the Predecessor utilized funds from debt offerings, borrowings under its credit facility and net cash provided by operating activities, as well as funding from our former parent, for capital resources and liquidity, and the primary use of capital was for the development of oil and natural gas properties.Hedging
We have protected a significant portion of our anticipated cash flows through our commodity hedging program, including swaps, puts, calls and collars. We hedge crude oil and gas production to protect against oil and gas price decreases and we also hedge gas purchases to protect against price increases. We have also entered into gas transportation contracts in the Rockies to help reduce the price fluctuation exposure, however these do not qualify as hedges.
In addition, we also hedge to meet the hedging requirements of the 2021 RBL Facility. The 2021 RBL Facility requires us to maintain commodity hedges (other than three-way collars) on minimum notional volumes of (i) at least 75% of our reasonably projected production of crude oil from our PDP reserves, for 24 full calendar months after the effective date of the 2021 RBL Facility and after each May 1 and November 1 of each calendar year and (ii) at least 50% of our reasonably projected production of crude oil from our PDP reserves, for each full calendar month during the period from and including the 25th full calendar month following each such Minimum Hedging Requirement Date through fixed-price derivative contracts. and including the 36th full calendar month following each such Minimum Hedging Requirement Date; provided, that in the case of each of the above clauses (i) and (ii), the notional volumes hedged are deemed reduced by the notional volumes of any short puts or other similar derivatives having the effect of exposing us to commodity price risk below the “floor.”
In addition to minimum hedging requirements and other restrictions in respect of hedging described therein, the 2021 RBL Facility contains restrictions on our commodity hedging which prevent us from entering into hedging agreements (i) with a tenor exceeding 48 months or (ii) for notional volumes which (when aggregated with other hedges then in effect other than basis differential swaps on volumes already hedged) exceed, as of the date such hedging agreement is executed, 90% of our reasonably projected production of crude oil from our PDP reserves, for each month following the date such hedging agreement is entered into, provided that the volume limitations above do not apply to short puts or put options contracts that are not related to corresponding calls, collars, or swaps.
Our generally low-decline production base affords an ability to hedge a material amount of our future expected production. We expect our operations to generate sufficient cash flows at current commodity prices including our current hedging positions. For information regarding risks related to our hedging program, see Part I—Item 1A. “Risk Factors—Risks Related to Our Operations and Industry” in our Annual Report.
As of JuneApril 30, 2018,2024, we have hedgedhad the following crude oil production and gas purchases hedges.
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| | | | | | | Q2 2024 | | Q3 2024 | | Q4 2024 | | FY 2025 | | FY 2026 | | FY 2027 | | |
| Brent - Crude Oil production | | | | | | | | | | | | | | | | | | |
| Swaps | | | | | | | | | | | | | | | | | | | |
| Hedged volume (bbls) | | | | | | | 1,611,294 | | | 1,481,749 | | | 1,438,656 | | | 4,859,125 | | | 2,039,268 | | | 540,000 | | | |
| Weighted-average price ($/bbl) | | | | | | | $ | 78.97 | | | $ | 76.88 | | | $ | 76.93 | | | $ | 76.08 | | | $ | 71.11 | | | $ | 71.42 | | | |
Sold Calls(1) | | | | | | | | | | | | | | | | | | | |
| Hedged volume (bbls) | | | | | | | 91,000 | | | 92,000 | | | 92,000 | | | 296,127 | | | 1,251,500 | | | — | | | |
| Weighted-average price ($/bbl) | | | | | | | $ | 105.00 | | | $ | 105.00 | | | $ | 105.00 | | | $ | 88.69 | | | $ | 85.53 | | | $ | — | | | |
Purchased Puts (net)(2) | | | | | | | | | | | | | | | | | | | |
| Hedged volume (bbls) | | | | | | | 318,500 | | | 322,000 | | | 322,000 | | | — | | | — | | | — | | | |
| Weighted-average price ($/bbl) | | | | | | | $ | 50.00 | | | $ | 50.00 | | | $ | 50.00 | | | $ | — | | | $ | — | | | $ | — | | | |
Purchased Puts (net)(2) | | | | | | | | | | | | | | | | | | | |
| Hedged volume (bbls) | | | | | | | — | | | — | | | — | | | 296,127 | | | 1,251,500 | | | — | | | |
| Weighted-average price ($/bbl) | | | | | | | $ | — | | | $ | — | | | $ | — | | | $ | 60.00 | | | $ | 60.00 | | | $ | — | | | |
Sold Puts (net)(2) | | | | | | | | | | | | | | | | | | | |
| Hedged volume (bbls) | | | | | | | 45,500 | | | 46,000 | | | 46,000 | | | — | | | — | | | — | | | |
| Weighted-average price ($/bbl) | | | | | | | $ | 40.00 | | | $ | 40.00 | | | $ | 40.00 | | | $ | — | | | $ | — | | | $ | — | | | |
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NWPL - Natural Gas purchases(3) | | | | | | | | | | | | | | | | | | |
| Swaps | | | | | | | | | | | | | | | | | | | |
| Hedged volume (mmbtu) | | | | | | | 3,640,000 | | | 3,680,000 | | | 3,680,000 | | | 13,380,000 | | | 3,040,000 | | | — | | | |
| Weighted-average price ($/mmbtu) | | | | | | | $ | 3.96 | | | $ | 3.96 | | | $ | 3.96 | | | $ | 4.27 | | | $ | 4.26 | | | $ | — | | | |
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__________(1) Purchased calls and sold calls with the same strike price have been presented on a net basis.
(2) Purchased puts and sold puts with the same strike price have been presented on a net basis.
(3) The term “NWPL” is defined as Northwest Rocky Mountain Pipeline.
(Losses) gains on Derivatives
A summary of gains and losses on the derivatives included on the statements of operations is presented below:
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| Three Months Ended |
| March 31,
2024 | | December 31,
2023 | | March 31,
2023 |
| (in thousands) |
| Realized (losses) gains on commodity derivatives: | | | | | |
| Realized (losses) on oil sales derivatives | $ | (4,682) | | | $ | (7,405) | | | $ | (7,438) | |
| Realized (losses) gains on natural gas purchase derivatives | (4,412) | | | (2,211) | | | 54,905 | |
| Total realized (losses) gains on derivatives | $ | (9,094) | | | $ | (9,616) | | | $ | 47,467 | |
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| Unrealized (losses) gains on commodity derivatives: | | | | | |
| Unrealized (losses) gains on oil sales derivatives | $ | (66,518) | | | $ | 91,323 | | | $ | 45,937 | |
| Unrealized (losses) on natural gas purchase derivatives | (69) | | | (19,186) | | | (54,295) | |
| Total unrealized (losses) gains on derivatives | $ | (66,587) | | | $ | 72,137 | | | $ | (8,358) | |
| Total (losses) gains on derivatives | $ | (75,681) | | | $ | 62,521 | | | $ | 39,109 | |
The following table summarizes the historical results of our hedging activities.
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| Three Months Ended | | |
| March 31,
2024 | | December 31,
2023 | | March 31,
2023 | | | | |
| Crude Oil (per bbl): | | | | | | | | | |
| Realized sales price, before the effects of derivative settlements | $ | 75.31 | | | $ | 76.00 | | | $ | 74.69 | | | | | |
| Effects of derivative settlements | (2.17) | | | (3.35) | | | (3.65) | | | | | |
| Realized sales price, after the effects of derivatives | $ | 73.14 | | | $ | 72.65 | | | $ | 71.04 | | | | | |
| Purchased Natural Gas (per mmbtu): | | | | | | | | | |
| Purchase price, before the effects of derivative settlements | $ | 3.99 | | | $ | 5.29 | | | $ | 20.74 | | | | | |
| Effects of derivative settlements | 0.92 | | | 0.44 | | | (11.86) | | | | | |
| Purchase price, after the effects of derivatives settlements | $ | 4.91 | | | $ | 5.73 | | | $ | 8.88 | | | | | |
Cash Dividends
In the first quarter of 2024, our Board of Directors declared a quarterly fixed cash dividend totaling $0.12 per share, as well as a variable cash dividend of $0.14 per share which was based on the results of the fourth quarter of 2023, for a total of $0.26 per share, which we paid in March 2024. In April 2024, The Board of Directors approved a fixed cash dividend totaling $0.12 per share, which is expected to be paid in May 2024.
The following table represents the regular fixed cash dividends on our common stock and variable dividends approved by our Board of Directors in 2024.
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| First Quarter | | | | | | | | | | |
| Fixed Dividends | $ | 0.12 | | | | | | | | | | | |
Variable Dividends(1) | — | | | | | | | | | | | |
| Total | $ | 0.12 | | | | | | | | | | | |
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__________(1) Variable Dividends are declared the quarter following the period of results (the period used to determine the variable divided based on the shareholder return model). The table notes total dividends earned in each quarter. There is no variable dividend related to the results of the first quarter of 2024.
The Company anticipates that it will continue to pay quarterly cash dividends in the future. However, the payment and amount of future dividends remain within the discretion of the Board of Directors and will depend upon the Company’s future earnings, financial condition, capital requirements and other factors.
Stock Repurchase Program
The Company did not repurchase any shares during the three months ended March 31, 2024. As of March 31, 2024, the Company had repurchased a total of 11.9 million shares, cumulatively, under the stock repurchase program for approximately 2.1 MMBbls for 2018, 3.7 MMBbls for 2019$114 million in aggregate. According to the shareholder return model, the Company may allocate a portion of Adjusted Free Cash Flow, a non-GAAP measure, to opportunistic share repurchases.
As of March 31, 2024, the Company’s remaining total share repurchase authority approved by the Board of Directors was $190 million. The Board of Directors’ authorization permits the Company to make purchases of its common stock from time to time in the open market and 0.5 MMBbls for 2020.
Future cash flows arein privately negotiated transactions or by other means, subject to a numbermarket conditions and other factors, up to the aggregate amount authorized by the Board of variables discussed in "Risk Factors". Further,Directors. The Board of Directors authorization has no expiration date.
The manner, timing and amount of any purchases will be determined based on our capital investment budget forevaluation of market conditions, stock price, compliance with outstanding agreements and other factors. Purchases may be commenced or suspended at any time without notice and the year ended December 31, 2018,share repurchase program does not allocateobligate the Company to purchase shares during any amounts for acquisitions of oil and natural gas properties. If we make acquisitions, we would be required to reduce the expected level of capital investments or seek additional capital. If we require additional capital we may seek such capital through borrowings under the RBL Facility, joint venture partnerships, production payment financings, asset sales, additional offerings of debt or equity securities or other means. We cannot be sure that needed
capital would be available on acceptable termsperiod or at all. If weAny shares repurchased are unable to obtain funds on acceptable terms, we mayreflected as treasury stock and any shares acquired will be required to curtail our current development programs, which could result significant declines in our production.available for general corporate purposes.
See "-Capital Expenditures and Capital Budget" for a description
Statements of Cash Flows
The following is a comparative cash flow summary:
| | | Three Months Ended
March 31, | |
| | Berry Corp. (Successor) | Berry LLC (Predecessor) |
| Three Months Ended
March 31, | |
| | Six Months Ended | Four Months Ended | Two Months Ended |
| | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| Three Months Ended
March 31, | |
| 2024 | |
| 2024 | |
| 2024 | |
| (in thousands) | |
| (in thousands) | |
| (in thousands) | | | |
| Net cash: | | | |
| Provided by (used in) operating activities | $ | (49,548 | ) | $ | 44,937 |
| $ | 22,431 |
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| Provided by operating activities | |
| Provided by operating activities | |
| Provided by operating activities | |
| Used in investing activities | (42,347 | ) | (72,328 | ) | (3,133 | ) |
| Provided by (used in) financing activities | 46,467 |
| (15,000 | ) | (162,668 | ) |
| Net decrease in cash, cash equivalents and restricted cash | $ | (45,428 | ) | $ | (42,391 | ) | $ | (143,370 | ) |
| | |
| Used in investing activities | |
| Used in investing activities | |
| Used in financing activities | |
| Used in financing activities | |
| Used in financing activities | |
| Net (decrease) in cash and cash equivalents | |
| Net (decrease) in cash and cash equivalents | |
| Net (decrease) in cash and cash equivalents | |
Operating Activities
Cash used in operating activities was approximately $50 million for the six months ended June 30, 2018 compared to cash provided by operating activities of approximately $67 millionincreased for the sixthree months ended June 30, 2017, includingMarch 31, 2024 by approximately $25 million when compared to the successor and predecessor periods.three months ended March 31, 2023. The amounts used in 2018 included $127 million for early-terminated hedges which offset $77 million of cash provided by other operating activities. Aside from the impact of these early hedge terminations, theincrease was primarily related to a decrease in cash used inlease operating activities in the first six months of 2018 compared to 2017 reflected higher salesexpenses (largely fuel gas purchases), royalty payments and lowerexecutive transition costs, slightlypartially offset by negative working capital effects.an increase in derivative settlements paid.
Investing Activities
The following provides a comparative summary of cash flowflows from investing activities:
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| | Berry Corp.
(Successor) | Berry LLC (Predecessor) |
| | Six Months Ended | Four Months Ended | Two Months Ended |
| (in thousands) | June 30, 2018 | June 30, 2017 | February 28, 2017 |
| Capital expenditures (1) | $ | (45,369 | ) | $ | (32,878 | ) | $ | (3,158 | ) |
| Proceeds from sale of properties and equipment and other | 3,022 |
| — |
| 25 |
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| Deposit on acquisition of properties | — |
| (39,450 | ) | — |
|
| Cash used in investing activities: | $ | (42,347 | ) | $ | (72,328 | ) | $ | (3,133 | ) |
(1) based on actual cash payments rather than accruals. | | | | | | | | | | | | |
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| Three Months Ended
March 31, | |
| 2024 | | 2023 | |
| (in thousands) |
| Capital expenditures: | | | | |
| Capital expenditures | $ | (16,936) | | | $ | (20,633) | | |
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| Changes in capital expenditures accruals | (957) | | | (6,170) | | |
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| Acquisitions, net of cash received | (768) | | | (3,657) | | |
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| Net cash used in investing activities | $ | (18,661) | | | $ | (30,460) | | |
Cash used in investing activities was approximately $42decreased $12 million for the sixthree months ended June 30, 2018. The decrease in cash used for investing activities for the six months ended June 30, 2018March 31, 2024 when compared to the same period in 2017 including2023, primarily due to lower capital expenditures as we drilled fewer wells in the successorfirst quarter of 2024. However, we increased production utilizing less capital due to the bolt-on acquisitions in the second half of 2023.
Financing Activities
Cash used in financing activities decreased approximately $7 million for the three months ended March 31, 2024 when compared to the three months ended March 31, 2023 primarily due to decreased dividends paid, partially offset by decreased borrowings under the 2021 RBL credit facility.
Balance Sheet Analysis
The changes in our balance sheet from December 31, 2023 to March 31, 2024 are discussed below.
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| March 31, 2024 | | December 31, 2023 |
| (in thousands) |
| Cash and cash equivalents | $ | 3,457 | | | $ | 4,835 | |
| Accounts receivable, net | $ | 89,937 | | | $ | 86,918 | |
| Derivative instruments assets - current and long-term | $ | — | | | $ | 10,751 | |
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| Other current assets | $ | 45,979 | | | $ | 43,759 | |
| Property, plant & equipment, net | $ | 1,384,704 | | | $ | 1,406,612 | |
| Deferred income taxes asset - long-term | $ | 41,455 | | | $ | 30,308 | |
| Other noncurrent assets | $ | 9,984 | | | $ | 10,975 | |
| Accounts payable and accrued expenses | $ | 184,539 | | | $ | 213,401 | |
| Derivative instruments liabilities - current and long-term | $ | 66,575 | | | $ | 10,740 | |
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| Long-term debt | $ | 448,121 | | | $ | 427,993 | |
| Deferred income taxes liability - long-term | $ | — | | | $ | 2,344 | |
| Asset retirement obligations - long-term | $ | 177,900 | | | $ | 176,578 | |
| Other noncurrent liabilities | $ | 9,537 | | | $ | 5,126 | |
| Stockholders’ equity | $ | 688,844 | | | $ | 757,976 | |
See “—Liquidity and predecessor periods,Capital Resources” for discussions about the changes in cash and cash equivalents.
The $3 million increase in accounts receivable was primarily due to an increase in oil sales prices comparatively at the end of each period.
The $22 million decrease in property, plant and equipment was primarily due to year-to-date DD&A of $40 million offset by $17 million in capital investments and $1 million in acquisitions.
The $11 million increase in deferred income taxes assets - long term was primarily due to the deposit made for the acquisitiontax effect of the Hill property in 2017 offset by increased capital spendingbook loss in the six months ended June 30, 2018.first quarter. The asset now reflects both federal and state tax amounts whereas the year end balance only reflected federal taxes.
Financing ActivitiesThe $29 million decrease in accounts payable and accrued expenses included decreased fuel gas purchases and payments in the first quarter 2024 (without similar fourth quarter 2023 payments) for royalties, interest and annual incentive compensation.
Cash provided by financing activities was approximately $46The $67 million forincrease in net derivative liability, which includes the six months ended June 30, 2018derivative asset, is due to the increase in the net liability of $0 million at December 31, 2023 to $67 million as of March 31, 2024. Changes to mark-to-market derivative values at the end of each period result from differences in the forward curve prices relative to the contract fixed prices, changes in positions held and settlements received and paid throughout the periods.
The $20 million increase in long-term debt largely reflected first quarter borrowings on our 2021 RBL Facility related to typical first quarter working capital needs.
The $2 million decrease in deferred income taxes liability - long-term is due to the change in the state tax obligation changing from a liability to an asset.
The $1 million increase in the long-term portion of the asset retirement obligations from $177 million at December 31, 2023 to $178 million at March 31, 2024 was due to receiving $391$3 million net proceeds from the issuance of our 2026 Notesaccretion expense, largely offset by payments on our RBL Facility, additional net
borrowings of $313 million, the repurchase of a right to our shares of $20 million, which is reflected as treasury stock, cash dividends declared on our Series A Preferred Stock in the aggregate amount of $11 million and $9$2 million of debt issuance costs. Forliabilities settled during the six months ended June 30, 2017, includingperiod.
The $4 million increase in other noncurrent liabilities is primarily a result of the successorfirst quarter obligation for greenhouse gas allowances due in over one year.
The $69 million decrease in stockholders’ equity was due to $24 million of common stock dividends, $40 million in net loss, and predecessor periods, net cash used in financing activities related to payments$5 million of shares withheld for payment of taxes on our previous credit facilities of approximately $513 millionequity awards, partially offset by the receipt$1 million of proceeds from the issuance of our Series A Preferred Stock of $335 million.stock-based compensation.
Debt
2026 Notes Offering
In February 2018, we issued $400 million in aggregate principal amount of our 2026 Notes, which resulted in net proceeds to us of approximately $391 million after deducting expenses and the initial purchasers’ discount. We used the net proceeds from the issuance to repay the $379 million outstanding balance on the RBL Facility and used the remainder for general corporate purposes.
We may, at our option, redeem all or a portion of the 2026 Notes at any time on or after February 15, 2021. We are also entitled to redeem up to 35% of the aggregate principal amount of the 2026 Notes before February 15, 2021, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107% of the principal amount of the 2026 Notes being redeemed, plus accrued and unpaid interest, if any. In addition, prior to February 15, 2021, we may redeem some or all of the 2026 Notes at a price equal to 100% of the principal amount thereof, plus a “make-whole” premium, plus any accrued and unpaid interest. If we experience certain kinds of changes of control, holders of the 2026 Notes may have the right to require us to repurchase their notes at 101% of the principal amount of the 2026 Notes, plus accrued and unpaid interest, if any.
The 2026 Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. The notes are fully and unconditionally guaranteed on a senior unsecured basis by us and will also be guaranteed by certain of our future subsidiaries (other than Berry LLC). The 2026 Notes and related guarantees are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under the RBL Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any future subsidiaries that do not guarantee the 2026 Notes.
The indenture governing the 2026 Notes contains restrictive covenants that may limit our ability to, among other things:
incur or guarantee additional indebtedness or issue certain types of preferred stock;
pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness
transfer, sell or dispose of assets;
make investments;
create certain liens securing indebtedness;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of our assets; and
engage in transactions with affiliates.
The indenture governing the 2026 Notes contains customary events of default, including, among others, (a) non-payment; (b) non-compliance with covenants (in some cases, subject to grace periods); (c) payment default under, or acceleration events affecting, material indebtedness and (d) bankruptcy or insolvency events involving us or certain of our subsidiaries.
The RBL Facility
On July 31, 2017, Berry LLC, as borrower, entered into the RBL Facility. The RBL Facility provides for a revolving loan with up to $1.5 billion of commitments, subject to a reserve borrowing base, and provided an initial commitment of $500 million. The RBL Facility also provides a letter of credit subfacility for the issuance of letters of credit in an aggregate amount not to exceed $25 million. Issuances of letters of credit reduce the borrowing availability for revolving loans under the RBL Facility on a dollar for dollar basis. Borrowing base redeterminations become effective on or about each May 1 and November 1, although each of us and the administrative agent may make one interim redetermination between scheduled redeterminations. In connection with the issuance of the 2026 Notes, the RBL Facility borrowing base was set at $400 million, which incorporated a $100 million reduction, or 25%, of the face value of the 2026 Notes. In March 2018, we completed a borrowing base redetermination that reaffirmed our borrowing base at $400 million with an elected commitment feature that allows us to increase the borrowing base to $575 million with lender approval. As of June 30, 2018, we had $66 million in borrowings and
approximately $7 million in letters of credit outstanding and borrowing availability of $327 million under the RBL Facility. The RBL Facility matures on July 29, 2022, unless terminated earlier in accordance with the RBL Facility terms.
The outstanding borrowings under the revolving loan bear interest at a rate equal to either (i) a customary London interbank offered rate plus an applicable margin ranging from 2.50% to 3.50% per annum, and (ii) a customary base rate plus an applicable margin ranging from 1.50% to 2.50% per annum, in each case depending on levels of borrowing base utilization. In addition, we must pay the lenders a quarterly commitment fee of 0.50% on the average daily unused amount of the borrowing availability under the RBL Facility. We have the right to prepay any borrowings under the RBL Facility with prior notice at any time without a prepayment penalty, other than customary “breakage” costs with respect to eurodollar loans.
Berry Corp. guarantees, and each future subsidiary of Berry Corp. (other than Berry LLC), with certain exceptions, is required to guarantee, our obligations and obligations of the other guarantors under the RBL Facility and under certain hedging transactions and banking services arrangements (the “Guaranteed Obligations”). In addition, pursuant to a Guaranty Agreement dated as of July 31, 2017 (the “Guaranty Agreement”), Berry LLC guarantees the Guaranteed Obligations. The lenders under the RBL Facility hold a mortgage on at least 85% of the present value of our proven oil and gas reserves. The obligations of Berry LLC and the guarantors are also secured by liens on substantially all of our personal property, subject to customary exceptions. The RBL Facility, with certain exceptions, also requires that any future subsidiaries of Berry LLC will also have to grant mortgages, security interests and equity pledges.
The RBL Facility requires us to maintain on a consolidated basis as of September 30, 2017 and each quarter-end thereafter (i) a Leverage Ratio of no more than 4.00 to 1.00 and (ii) a Current Ratio of at least 1.00 to 1.00. The RBL Facility also contains customary restrictions that may limit our ability to, among other things:
incur or guarantee additional indebtedness;
transfer, sell or dispose of assets;
make loans to others;
make investments;
merge with another entity;
make or declare dividends;
hedge future production or interest rates;
enter into transactions with affiliates;
incur liens; and
engage in certain other transactions without the prior consent of the lenders.
The RBL Facility contains customary events of default and remedies for credit facilities of a similar nature. If we do not comply with the financial and other covenants in the RBL Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the RBL Facility and exercise all of their other rights and remedies, including foreclosure on all of the collateral.
Lawsuits, Claims, Commitments, Contingencies and Contractual ObligationsContingencies
In the normal course of business, we, or our subsidiary,subsidiaries, are the subject of, or party to, lawsuits, environmentalpending or threatened legal proceedings, contingencies and other claims and other contingenciescommitments involving a variety of matters that seek, or may seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civilfines and penalties, remediation costs, or injunctive or declaratory relief.
On May 11, 2016 our predecessor entity filed the Chapter 11 Proceeding. Our bankruptcy case was jointly administered with that of Linn Energy and its affiliates under the caption In re Linn Energy, LLC, et. al., Case No. 16-60040. On January 27, 2017, the Bankruptcy Court approved and confirmed our plan of reorganization in the Chapter 11 Proceeding. On the Effective Date the plan became effective and was implemented. The Chapter 11 Proceeding will, however, remain pending until final resolution of all outstanding claims.
We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. We have not recorded any reserve balances at June 30, 2018March 31, 2024 and December 31, 2017.2023. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on our balance sheet would not be material to our consolidated financial position or results of operations. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accruedaccruals on our balance sheet would not be material to our consolidated financial position or results of operations.
For information related to Berry LLC’s emergence from bankruptcy and the terms of the RBL Facility, see “—Chapter 11 Bankruptcy and Our Emergence” and “Description of Other Indebtedness—The RBL Facility.”
We, or our subsidiary,subsidiaries, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with transactions that they have entered into with us. As of June 30, 2018,March 31, 2024, we are not aware of material indemnity claims pending or threatened against us.
Securities Litigation Matters
Counterparty Credit Risk
We accountOn November 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class action lawsuit (the “Securities Class Action”) in the United States District Court for our commodity derivatives at fair value. We had three commodity derivative counterparties at June 30,the Northern District of Texas against Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933 (as amended, the “Securities Act”), and Sections 10(b) and 20(a) of the Exchange Act of 1934 (as amended, the “Exchange Act”), on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.’s securities between July 26, 2018 and fiveNovember 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined following release of its financial results for the third quarter of 2020 on November 3, 2020.
On November 1, 2021, the court-appointed co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a motion to dismiss on January 24, 2022 and on September 13, 2022, the court issued an order denying that motion, and the case moved into discovery. On February 13, 2023, the plaintiffs filed a motion for class certification, and on April 14, 2023, the defendants filed their opposition; the plaintiffs filed their reply on May 26, 2023, and a hearing on the motion for class certification was set for August 23, 2023.
On July 31, 2023, the parties executed a Memorandum of Understanding memorializing an agreement-in-principle to settle all claims in the Securities Class Action for an aggregate sum of $2.5 million. On September 18, 2023, the plaintiffs and Defendants executed a Stipulation and Agreement of Settlement, and the plaintiffs filed a motion seeking preliminary approval of the settlement. On October 18, 2023, the Court granted that motion, issuing a preliminary approval order and scheduling a final settlement approval hearing for February 6, 2024. Following notice to the class and an opt-out and objection process, the Court granted final approval of the settlement at December 31, 2017. We did not receive collateralthe hearing on February 6, 2024. On February 16, 2024, the Court entered a final settlement-approval order and judgment and terminated the case, and the settlement funds were subsequently disbursed to the class from anyan existing escrow account. The Defendants continue to maintain that the claims are without merit and admitted no liability in connection with the settlement. This litigation is now concluded,and the Company will no longer report on it in future filings.
On October 20, 2022, a shareholder derivative lawsuit (the “Assad Lawsuit”) was filed in the United States District Court for the Northern District of our counterparties. We minimizeTexas by putative stockholder George Assad, allegedly on behalf of the credit riskCompany, that piggy-backs on the Securities Class Action and which is currently pending before the same court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of ourthe Exchange Act. On January 27, 2023, the court granted the parties’ joint stipulated request to stay the Assad Lawsuit pending resolution of the Securities Class Action.
On January 20, 2023, a second shareholder derivative instrumentslawsuit (the “Karp Lawsuit,” together with the Assad Lawsuit, the “Shareholder Derivative Actions”) was filed, this time in the United States District Court for the District of Delaware, by limiting our exposureputative stockholder Molly Karp, allegedly on behalf of the Company, again piggy-backing on the Securities Class Action. This complaint, similar to any single counterparty.the Assad Lawsuit, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the securities violations alleged in the securities class action. In addition, the RBL Facility prevents us from entering into hedging arrangementscomplaint asserts a claim under Section 14(a) of the Exchange Act, alleging that are secured except with our lendersBerry’s 2022 proxy statement was false and their affiliates,misleading in that have margin call requirements,it suggested the Company’s internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that otherwise require uswas not the case. On February 13, 2023, the court granted the parties’ joint stipulated request to provide collateral or withstay the Karp Lawsuit pending resolution of a non-lender counterparty thatmotion for summary judgment by the defendants in the Securities Class Action. The settlement of the Securities Class Action does not have an A-relate to the Shareholder Derivative Actions. The defendants continue to believe the claims in the Shareholder Derivative Actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or A3 credit ratingthe amount of liability, if any, related to these matters.
In addition, on or better from Standard & Poor’s or Moody’s, respectively. In accordance witharound April 17, 2023, the Company received a stockholder litigation demand that the Board of Directors investigate and commence legal proceedings against certain current and former officers and directors based ostensibly on the same claims asserted in the Shareholder Derivative Actions. The Board of Directors appointed a Demand Review Committee for the purpose of reviewing the demand.
Contractual Obligations
The following is a summary of our standard practice, our commodity derivativescommitments and contractual obligations as of March 31, 2024:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due |
| | Total | | Less Than 1 Year | | 1-3
Years | | 3-5
Years | | Thereafter |
| | (in thousands) |
| Debt obligations: | | | | | | | | | | |
| RBL Facility | | $ | 51,000 | | | $ | — | | | $ | 51,000 | | | $ | — | | | $ | — | |
| 2026 Notes | | 400,000 | | | — | | | 400,000 | | | — | | | — | |
Interest(1) | | 52,500 | | | 28,000 | | | 24,500 | | | — | | | — | |
Deferred acquisition payable(2) | | 19,500 | | | 19,500 | | | — | | | — | | | — | |
| Other: | | | | | | | | | | |
| Leases | | 8,147 | | | 3,154 | | | 3,850 | | | 1,143 | | | — | |
Asset retirement obligations(3) | | 197,900 | | | 20,000 | | | — | | | — | | | 177,900 | |
Off-Balance Sheet arrangements:(4) | | | | | | | | | | |
Transportation contracts(5) | | 78,387 | | | 11,233 | | | 17,543 | | | 16,165 | | | 33,446 | |
Other purchase obligations(6) | | 17,100 | | | 8,400 | | | 8,700 | | | — | | | — | |
| Total contractual obligations | | $ | 824,534 | | | $ | 90,287 | | | $ | 505,593 | | | $ | 17,308 | | | $ | 211,346 | |
__________
(1) Represents interest on the 2026 Notes computed at 7% through contractual maturity in 2026.
(2) Relates to the remaining payable of $20 million, on a discounted basis, for the acquisition of Macpherson Energy, LLC due in July 2024. The remaining payable amount is subject to customary purchase price adjustments.
(3) Represents the estimated future asset retirement obligations on a discounted basis. We do not show the long-term asset retirement obligations by year as we are not able to precisely predict the timing of these amounts. Because these costs typically extend many years into the future, estimating these future costs requirement management to make estimates and judgements that are subject to counterparty nettingrevisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See Note 1—Basis of Presentation in the notes to consolidated financial statements in Part II—Item 8. “Financial Statements and Supplementary Data” in our Annual Report for more information.
(4) These commitments and contractual obligations are expected to be funded by our cash flow from operations.
(5) Amounts include payments which will become due under long-term agreements governing such derivativesto purchase goods and thereforeservices used in the risknormal course of loss duebusiness to counterparty nonperformance is somewhat mitigated.secure pipeline transportation of natural gas to market and between markets.
(6) As of March 31, 2024, we have a total drilling commitment in California of $17.1 million. We are required to drill 57 wells consisting of 28 wells by December 2024 and the remaining 29 wells by June 2025.
Off-Balance Sheet Arrangements
During the six months ended June 30, 2018, there wereCritical Accounting Policies and Estimates
There have been no significant changes to our critical accounting policies and estimates from those disclosed on our Annual Report. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our consolidated contractual obligations from those reported in the prospectus.Annual Report.
Recently Adopted Accounting and Disclosure Changes
SeeCautionary Note 1, Accounting and Disclosure Changes, in the Notes to Consolidated Condensed FinancialRegarding Forward-Looking Statements in Part I, Item 1 of this Form 10-Q.
Safe Harbor Statement Regarding Outlook and Forward-Looking Information
The information included or incorporated by reference in this documentQuarterly Report includes forward-looking statements that involve riskswithin the meaning of Section 27A of the Securities Act and uncertainties that could materially affect our expected resultsSection 21E of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, maintenance capital requirements, expected production and costs, reserves, hedging activities, capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance.the Exchange Act. You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, budget, continue, could, effort, estimate, expect, forecast, goal, guidance, intend, likely, may, might, objective, outlook, plan, potential, predict, project, seek, should, target, will or would and other similar words that reflect the prospective nature of events or outcomes. All statements other than statements of historical facts included in this Quarterly Report that address plans, activities, events, objectives, goals, strategies or developments that the Company expects, believes or anticipates will or may occur in the future, such as those regarding our financial position, liquidity, cash flows (including, but not limited to, Adjusted Free Cash Flow), financial and operating results, capital program and development and production plans, operations and business strategy, potential acquisition and other strategic opportunities, reserves, hedging activities, capital expenditures, return of capital, our shareholder return model and the payment of future dividends, future repurchases of stock or debt, capital investments, our ESG strategy and the initiation of new projects or business in connection therewith, recovery factors and other guidance, are forward-looking statements. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Material risks that may affect us are discussed in Part I, Item 1A. “Risk Factors” in our results of operationsAnnual Report and financial position appear in Risk Factors inother filings with the prospectus.
Securities and Exchange Commission.
Factors (but not necessarily all the factors) that could cause results to differ include among others:
•the regulatory environment, including availability or timing of, and conditions imposed on, obtaining and/or maintaining permits and approvals, including those necessary for drilling and/or development projects;
•the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to permitting, drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, GHGs or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;
•inflation levels and government efforts to reduce inflation, including related interest rate determinations;
•overall domestic and global political and economic trends, geopolitical risks and general economic and industry conditions, such as inflation, high interest rates, increased volatility in financial and credit markets, global supply chain disruptions and the government interventions into the financial markets and economy;
•the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions, including the ongoing conflict in Ukraine, the ongoing conflict in the Middle East, or a prolonged recession, among other factors;
•volatility of oil, natural gas and NGL prices;prices, including as a result of political instability, armed conflicts or economic sanctions;
•the California and global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources;
•supply of and demand for oil, natural gas and NGLs, including due to the actions of foreign producers, importantly including OPEC+ and change in OPEC+'s production levels;
•disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations;
•inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, and meet our working capital requirements;requirements or fund planned investments;
•price fluctuations and availability of natural gas;gas and electricity and the cost of steam;
•competition and consolidation in the oil and gas E&P industry;
•our ability to use derivative instruments to manage commodity price risk;
impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;
uncertainties associated with estimating proved reserves and related future cash flows;
our inability to replace our reserves through exploration and development activities;
•our ability to meet our proposedplanned drilling schedule, including due to our ability to obtain permits on a timely basis or at all, and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
effects of competition;•concerns about climate change and other air quality issues;
•uncertainties associated with estimating proved reserves and related future cash flows;
•our ability to replace our reserves through exploration and development activities or acquisitions;
•drilling and production results, lower–than–expected production, reserves or resources from development projects or higher–than–expected decline rates;
•our ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating wells;
•changes in tax laws;
•uncertainties and liabilities associated with acquired and divested assets;
•our ability to make acquisitions and successfully integrate any acquired businesses;
•risks related to acquisitions, including the risk that we may fail to successfully integrate the assets into our operations, identify risks or liabilities associated with the acquired entity, its operations or assets, or realize any anticipated benefits or growth;
•market fluctuations in electricity prices and the cost of steam;
•asset impairments from commodity price declines;
•large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
•geographical concentration of our operations;
•the creditworthiness and performance of our ability to improve our financial results and profitability following our emergence from bankruptcy and other risks and uncertainties relatedcounterparties with respect to our emergence from bankruptcy;hedges;
changes in tax laws;
•impact of derivatives legislation affecting our ability to hedge;
•failure of risk management and ineffectiveness of internal controls;
•catastrophic events, including wildfires, earthquakes, floods, and epidemics or pandemics, including the effects of related public health concerns about climate changeand the impact of actions that may be taken by governmental authorities and other air quality issues;third parties in response to a pandemic;
catastrophic events;•environmental risks and liabilities under federal, state, tribal and local laws and regulations (including remedial actions);
•potential liability resulting from pending or future litigation;
•our ability to recruit and/or retain key members of our senior management and key technical employees;
•information technology failures or cyber attacks:cyberattacks; and
•governmental actions and political conditions, as well as actions by other third parties that are beyond our control.
Any forward-looking statement speaks only as of the date on which such statement is made. Except as required by law, we undertake no responsibility to publicly release thecorrect or update any forward-looking statements, whether as a result of any revision of our forward-looking statements after the date they are made.
new information, future events or otherwise except as required by applicable law.
All forward-looking statements, expressed or implied, included in this reportQuarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For the three months ended June 30, 2018,As of March 31, 2024, there werehave been no material changes in the information required to be provided under Item 305 of Regulation S-K included under the caption Management's Discussion and Analysis of Financial Condition and Results of Operations (Incorporatingin Part II, Item 7A)- Quantitative7A. “Quantitative and Qualitative Disclosures About Market Risk, Risk” in the prospectus.our Annual Report, except as discussed below.
Price Risk
Our most significant market risk relates to prices for oil, natural gas, and NGLs. Management expects energy prices to remain unpredictable and potentially volatile. As energy prices decline or rise significantly, revenues, certain costs such as fuel gas, and cash flows are likewise affected. In addition, aAdditional non-cash write-down ofimpairment charges for our oil and gas properties may be required if commodity prices experience a significant decline.
We have historically hedged a large portion of our expected crude oil and our natural gas production, as well as our natural gas purchase requirements to reduce exposure to fluctuations in commodity prices. We use derivatives such as swaps, calls, puts and collars to hedge. We do not enter into derivative contracts for speculative trading purposes and we have not accounted for our derivatives as cash-flow or fair-value hedges. We continuously consider the level of our oil production and gas purchases that is appropriate to hedge based on a variety of factors, including, among other things, current and future expected commodity prices, our expected capital and operating costs, our overall risk profile, including leverage, size and scale, as well as any requirements for, or restrictions on, levels of hedging contained in any credit facility or other debt instrument applicable at the time.
We determine the fair value of our oil and gas sales and natural gas purchase derivatives and emission allowances required by California’s cap-and-trade program using valuation techniques which utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. We validate data provided by third parties by understanding the valuation inputs used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.
At June 30, 2018,March 31, 2024, the fair value of our hedge positions was a net liability of approximately $15 million, as determined from prices provided by external sources that are not actively quoted.$67 million. A 10% increase in the oil and natural gas index prices above the June 30, 2018March 31, 2024 prices would result in a net liability of approximately $57 million, which represents a decrease in the fair value of approximately $42$153 million; conversely, a 10% decrease in the oil and natural gas index prices below the June 30, 2018March 31, 2024 prices would result in a net liabilityasset of approximately $4 million, which represents an increase in the fair value of approximately $11$15 million. For additional information about derivative activity, see Note 4.3—Derivatives in the notes to the condensed consolidated financial statements in Part I, Item 1. “Financial Statements” of this Quarterly Report.
Counterparty Credit Risk
We had three commodity derivative counterparties at June 30, 2018, which were all liability positions. We did not receive collateral from anyAt March 31, 2024, the fair value of our counterparties. We minimize the credit risk of our derivative instrumentsemission allowances required by limiting our exposure to any single counterparty. In addition, the RBL Facility prevents us from entering into hedging arrangements that are secured except with our lenders and their affiliates, that have margin call requirements, that otherwise require us to provide collateralCalifornia’s cap-and-trade program was $6 million. A 10% increase or with a non-lender counterparty that does not have an A- or A3 credit rating or better from Standard & Poor’s or Moody’s, respectively. In accordance with our standard practice, our commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Interest Rate Risk
Our RBL Facility has a variable interest rate on outstanding balances. As of June 30, 2018, there were $66 million outstanding borrowings under our RBL Facility which incurred interest at floating rates. See Note 3 for additional information regarding interest rates on outstanding debt. As of June 30, 2018, a 1% increasedecrease in the respective market rateprice would result in an estimated $0.7 million increasea change in annual interest expense. The 2026 Notes haveexpense by less than $1 million.
Actual gains or losses recognized related to our derivative contracts depend exclusively on the price of the underlying commodities on the specified settlement dates provided by the derivative contracts. Additionally, we cannot be assured that our counterparties will be able to perform under our derivative contracts. If a fixed interest ratecounterparty fails to perform and thus we are not exposed to interest rate risk on these.the derivative arrangement is terminated, our cash flows could be negatively impacted.
Item 4. Controls and Procedures
Our President and Chief Executive Officer and our Executive Vice President, Chief Financial Officer and Chief FinancialAccounting Officer supervised and participated in our evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934)Act) as of the end of the period covered by this report. Based upon that evaluation, our President and Chief Executive Officer and our Executive Vice President and Chief Financial Officerthey each concluded that our disclosure controls and procedures were effective as of June 30, 2018.March 31, 2024.
The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC. The Company’s disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the Chief Executive Officer and the Vice President, Chief Financial Officer and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.
There were no changes in the Company’s internal control over financial reporting during the first quarter of 2024 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II – Other Information
Item 1. Legal Proceedings
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
Securities Litigation Matter
On November 20, 2020, Luis Torres, individually and on behalf of a putative class, filed a securities class action lawsuit (the “Securities Class Action”) in the United States District Court for the Northern District of Texas against Berry Corp. and certain of its current and former directors and officers (collectively, the “Defendants”). The complaint asserts violations of Sections 11 and 15 of the Securities Act of 1933 (as amended, the “Securities Act”), and Sections 10(b) and 20(a) of the Exchange Act of 1934 (as amended, the “Exchange Act”), on behalf of a putative class of all persons who purchased or otherwise acquired (i) common stock pursuant and/or traceable to the Company’s 2018 IPO; or (ii) Berry Corp.’s securities between July 26, 2018 and November 3, 2020 (the “Class Period”). In particular, the complaint alleges that the Defendants made false and misleading statements during the Class Period and in the offering materials for the IPO, concerning the Company’s business, operational efficiency and stability, and compliance policies, that artificially inflated the Company’s stock price, resulting in injury to the purported class members when the value of Berry Corp.’s common stock declined following release of its financial results for the third quarter of 2020 on November 3, 2020.
On November 1, 2021, the court-appointed co-lead plaintiffs filed an amended complaint asserting claims on behalf of the same putative class under Sections 11 and 15 of the Securities Act and Sections 10(b) and 20(a) of the Exchange Act, alleging, among other things, that the Company and the individual Defendants made false and misleading statements between July 26, 2018 and November 3, 2020 regarding the Company’s permits and permitting processes. The amended complaint does not quantify the alleged losses but seeks to recover all damages sustained by the putative class as a result of these alleged securities violations, as well as attorneys’ fees and costs. The Defendants filed a motion to dismiss on January 24, 2022 and on September 13, 2022, the court issued an order denying that motion, and the case moved into discovery. On February 13, 2023, the plaintiffs filed a motion for class certification, and on April 14, 2023, the defendants filed their opposition; the plaintiffs filed their reply on May 26, 2023, and a hearing on the motion for class certification was set for August 23, 2023.
On July 31, 2023, the parties executed a Memorandum of Understanding memorializing an agreement-in-principle to settle all claims in the Securities Class Action for an aggregate sum of $2.5 million. On September 18, 2023, the plaintiffs and Defendants executed a Stipulation and Agreement of Settlement, and the plaintiffs filed a motion seeking preliminary approval of the settlement. On October 18, 2023, the Court granted that motion, issuing a preliminary approval order and scheduling a final settlement approval hearing for February 6, 2024. Following notice to the class and an opt-out and objection process, the Court granted final approval of the settlement at the hearing on February 6, 2024. On February 16, 2024, the Court entered a final settlement-approval order and judgment and terminated the case, and the settlement funds were subsequently disbursed to the class from an existing escrow account. The Defendants continue to maintain that the claims are without merit and admitted no liability in connection with the settlement. This litigation is now concluded,and the Company will no longer report on it in future filings.
On October 20, 2022, a shareholder derivative lawsuit (the “Assad Lawsuit”) was filed in the United States District Court for the Northern District of Texas by putative stockholder George Assad, allegedly on behalf of the Company, that piggy-backs on the Securities Class Action and which is currently pending before the same court. The derivative complaint names certain current and former officers and directors as defendants, and generally alleges that they breached their fiduciary duties by causing or failing to prevent the securities violations alleged in the securities class action. The derivative complaint also alleges claims for unjust enrichment as against all defendants, and claims for contribution and indemnification under Sections 10(b) and 21D of the Exchange Act. On January 27, 2023, the court granted the parties’ joint stipulated request to stay the Assad Lawsuit pending resolution of the Securities Class Action.
On January 20, 2023, a second shareholder derivative lawsuit (the “Karp Lawsuit,” together with the Assad Lawsuit, the “Shareholder Derivative Actions”) was filed, this time in the United States District Court for the District of Delaware, by putative stockholder Molly Karp, allegedly on behalf of the Company, again piggy-backing on the Securities Class Action. This complaint, similar to the Assad Lawsuit, is brought against certain current and former officers and directors of the Company, asserting breach of fiduciary duty, aiding and abetting, and contribution claims based on the defendants allegedly having caused or failed to prevent the securities violations alleged in the securities class action. In addition, the complaint asserts a claim under Section 14(a) of the Exchange Act, alleging that Berry’s 2022 proxy statement was false and misleading in that it suggested the Company’s internal controls were sufficient and the Board of Directors was adequately overseeing material risks facing the Company when, according to the derivative plaintiff, that was not the case. On February 13, 2023, the court granted the parties’ joint stipulated request to stay the Karp Lawsuit pending resolution of a motion for summary judgment by the defendants in the Securities Class Action. The settlement of the Securities Class Action does not relate to the Shareholder Derivative Actions. The defendants continue to believe the claims in the Shareholder Derivative Actions are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. At this time, we are unable to estimate the probability or the amount of liability, if any, related to these matters.
In addition, on or around April 17, 2023, the Company received a stockholder litigation demand that the Board of Directors investigate and commence legal proceedings against certain current and former officers and directors based ostensibly on the same claims asserted in the Shareholder Derivative Actions. The Board of Directors appointed a Demand Review Committee for the purpose of reviewing the demand.
Other Matters
For additional information regarding legal proceedings, see Note 54—Commitments and Contingencies in the notes to thecondensed consolidated financial statements in Part I, ofItem 1. “Financial Statements” in this Form 10-QQuarterly Report and Note 75—Commitments and Contingencies in the notes to our consolidated financial statements for the year ended December 31, 2017 included in the prospectus.Part II, Item 8. “Financial Statements and Supplementary Data” in our Annual Report.
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading “Item 1A. Risk FactorsFactors” in the prospectus.our Annual Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
DuringStock Repurchase Program
The Company did not repurchase any shares during the quarterthree months ended June 30, 2018, we issued 190,260 RSUs and 117,088 PRSUs to certain of our employees and directors in connection with services provided to us by such persons.March 31, 2024. As of August 21, 2018, 681,092 RSUs and 749,833 PRSUs remain outstanding. We also granted 1,566March 31, 2024, the Company had repurchased a total of 11.9 million shares, of restricted stock to employees in connection with services provided to us by such persons.
The offers, sales and issuances of the securities described in the preceding paragraph were deemed to be exempt from registration either under Rule 701 promulgatedcumulatively, under the Securities Actstock repurchase program for approximately $114 million in that the transactions were under compensatory benefit plans and contracts relating to compensation, or under Section 4(a)(2)aggregate, which is 16% of the Securities Act in that the transactions were between an issuer and membersoutstanding shares as of its senior executive management and did not involve any public offering within the meaning of Section 4(a)(2).
Use of Proceeds
On July 30, 2018, we completed our IPO of common stock pursuant to our registration statement on Form S-1 (File 333-226011), as amended and declared effective by the SEC on July 25, 2018. Goldman Sachs & Co. LLC, Wells Fargo Securities, LLC and BMO Capital Markets Corp. served as representatives of the several underwriters for the IPO. The offering did not terminate before all of the shares in the IPO that were registered in the registration statement were sold. Upon completion of the IPO, we and the selling stockholders sold 13,043,479 shares at a priceMarch 31, 2024. According to the public of $14.00 per share, raising approximately $183 million of gross proceeds, with gross proceeds to Berry of approximately $147 million and gross proceeds toshareholder return model, the selling stockholders of approximately $36 million. Of the 13,043,479 shares sold to the public, 10,497,849 shares were issued and sold by us, and 2,545,630 shares were sold by the selling stockholders named in the prospectus. We incurred expenses in connection with the IPO of approximately $2.6 million as of July 30, 2018. After subtracting underwriting discounts and commissions of approximately $8.8 million and offering expenses, Berry received net proceeds of approximately $136 million. None of the expenses associated with our IPO were paid to directors, officers or persons owning ten percent or
more of our common stock or to their associates, or to our affiliates. We did not receive any proceeds from the sale of the shares by the selling stockholders. We and the selling stockholders granted the underwriters a 30-day option to purchase up to an additional 1,534,895 shares and 421,626 shares, respectively, of common stock at the IPO price, less underwriting discounts and commissions. We intend to useCompany may allocate a portion of Adjusted Free Cash Flow, a non-GAAP measure, to opportunistic share repurchases.
As of March 31, 2024, the proceeds we receiveCompany’s remaining total share repurchase authority approved by the Board of Directors was $190 million. The Board of Directors’ authorization permits the Company to make purchases of its common stock from any saletime to time in the open market and in privately negotiated transactions or by other means, subject to market conditions and other factors, up to the aggregate amount authorized by the Board of Directors. The Board of Directors authorization has no expiration date.
The manner, timing and amount of any such option shares to purchase up to an additional 230,548 sharespurchases will be determined based on our evaluation of commonmarket conditions, stock owned by Benefit Street.
We used approximately $24 million ofprice, compliance with outstanding agreements and other factors. Purchases may be commenced or suspended at any time without notice and the net proceeds fromshare repurchase program does not obligate the IPOCompany to purchase shares of our commonduring any period or at all. Any shares repurchased are reflected as treasury stock (at a price equal to the price paid by the underwritersand any shares acquired will be available for shares of common stock in the IPO) from funds affiliated with Benefit Street Partners and Oaktree Capital Management, each of which owned more than ten percent of our common stock prior to the IPO and repurchase. Of the remaining approximately $112 million of net proceeds received by us in the IPO, we used approximately $105 million to repay borrowings under our RBL Facility. This included the amounts we borrowed on the RBL Facility to make the payment to the holders of our Series A Preferred Stock in connection with the conversion of the Series A Preferred Stock to common stock. We used the remainder for working capital.general corporate purposes.
Item 5. Other DisclosuresInformation
Amended and Restated Employment Agreements with Arthur T. Smith, Cary D. Baetz and Gary A. Grove(c) Trading Plans
On August 22, 2018, Berry LLC, a wholly-owned subsidiaryDuring the three months ended March 31, 2024, no director or officer of the Company entered into amended and restated employment agreements with its Chief Executive Officer, Arthur T. “Trem” Smith (the “Smith Agreement”), its Chief Financial Officer, Cary D. Baetz (the “Baetz Agreement”) and its Chief Operating Officer, Gary A. Grove (the “Grove Agreement” and, together with the Smith Agreement and the Baetz Agreement, the “Amended Agreements”), inadopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each case, to replace the executive’s previous employment agreement with the Company (each, a “Prior Agreement”). The Amended Agreements became effective as of August 22, 2018.
Each Amended Agreement modifies certain terms of the corresponding Prior Agreement, including the following:
Each executiveterm is eligible to receive an annual equity award, as determined by the board of directors of the Company or a committee thereof.
Upon a termination of each executive’s employment under certain circumstances, the executive is eligible to receive (a) any earned but unpaid annual bonus for the year prior to the year of termination, (b) a prorated annual bonus for the year of termination and (c) severance in an amount equal to 18 months’ worth, for Mr. Smith, and 12 months’ worth, for Messrs. Baetz and Grove (or, following a Qualifying Termination (as defined in the applicable Amended Agreement), 24 months’ worth for Mr. Smith and 18 months’ worth for Messrs. Baetz and Grove)Item 408(a) of the sumRegulation S-K.
Modifies the definition of Good Reason in certain respects.
With respect to the Smith Agreement, Mr. Smith is eligible to receive an annual bonus in a target amount equal to 100% of his then-current base salary.
All other material terms contained in the Prior Agreements remain substantially unchanged in the Amended Agreements. Copies of the Smith Agreement, Baetz Agreement and Grove Agreement are attached hereto as Exhibits 10.14, 10.15 and 10.16, respectively, and are incorporated herein by reference. The description of the material changes to the Prior Agreements contained herein is qualified in its entirety by reference to the full text of the Amended Agreements.
Item 6. Exhibits
| | | | | | | | |
| Exhibit Number | | Description |
| 3.1 | | |
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| | |
Exhibit Number | | Description |
3.1 | | |
| 3.2 | | |
| 3.3 | | |
| 3.4 | | |
3.54.1 | | Second Amended and Restated BylawsFirst Supplemental Indenture, dated as of January 4, 2024, among Berry Petroleum Company, LLC, as issuer, Berry Corporation (bry) (f/k/a Berry Petroleum Corporation), the subsidiary guarantors party thereto and Computershare Trust Company, N.A. (as successor to Wells Fargo Bank, National As-sociation), as trustee (incorporated by reference to Exhibit 3.34.4 of the Company’s Annual Report on Form 8-K10-K filed July 30, 2018)March 8, 2024) |
10.14.2 | | Amended and Restated Stockholders Agreement betweenSecond Supplemental Indenture, dated as of February 8, 2024, among Berry Petroleum Company, LLC, as issuer, Berry Corporation (bry) (f/k/a Berry Petroleum Corporation), Macpherson Green Power Company, LLC and certain holders party theretoComputershare Trust Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee (incorporated by reference to Exhibit 10.14.5 of the Company’s Annual Report on Form 8-K10-K filed July 30, 2018)March 8, 2024) |
10.210.1
| | |
10.3 | | |
10.4 | | |
10.5 | | |
10.6 | | |
10.710.2
| | |
10.810.3
| | |
10.9 | | |
10.1010.4
| | |
10.1110.5
| | |
10.1210.6 | | |
10.1310.7 | | Stock PurchaseSixth Amendment to the Credit Agreement dated as of February 23, 2024, by and betweenamong Berry Petroleum Company, LLC, as borrower, Berry Corporation (bry), JPMorgan Chase Bank, N.A., as administrative agent, and certain funds affiliated with Benefit Street Partners named in Schedule Ieach of the lenders signatory thereto dated July 17, 2018 (incorporated by reference to Exhibit 10.3 of10.42 to the Company’s Annual Report on Form 8-K10-K filed July 30, 2018)March 8, 2024) |
10.14*10.8 | | AmendedSecond Amendment to Revolving Loan and Restated EmploymentSecurity Agreement Arthur T. Smithand Amendment to Other Loan Documents, dated as of November 15, 2023, by and among C&J Well Services, LLC, as a borrower, CJ Berry Well Services Management, LLC, as a borrower, and Tri Counties Bank, as lender (incorporated by reference to Exhibit 10.43 to the Company’s Annual Report on Form 10-K filed March 8, 2024) |
10.15*31.1* | | |
|
| | |
10.16* | | |
31.1* | | |
| 31.2* | | |
32.1** | | |
| 101.INS* | | Inline XBRL Instance Document (the Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document) |
| 101.SCH* | | Inline XBRL Taxonomy Extension Schema Document |
| | | | | | | | |
| 101.CAL* | | Inline XBRL Taxonomy Extension Calculation Linkbase Document |
| 101.DEF* | | Inline XBRL Taxonomy Extension Definition Linkbase Document |
*101.LAB* | | Filed herewith.Inline XBRL Taxonomy Extension Label Linkbase Data Document |
**101.PRE* | | Furnished herewith.Inline XBRL Taxonomy Extension Presentation Linkbase Document |
| 104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
__________
(*) Filed herewith.
GLOSSARY OF OIL AND NATURAL GASCOMMONLY USED TERMS
The following are abbreviations and definitions of certain terms that may be used in this report, which are commonly used in the oil and natural gas industry:
“APIAdjusted EBITDA” gravity is a non-GAAP financial measure defined 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.
“Adjusted Free Cash Flow” is a non-GAAP financial measure which is defined (i) through December 31, 2023, as cash flow from operations less regular fixed dividends and maintenance capital and (ii) beginning January 1, 2024, as cash flow from operations, less regular fixed dividends and capital expenditures. Adjusted Free Cash Flow for prior periods has not been retroactively adjusted for the updated definition.
“Adjusted General and Administrative Expenses” is a non-GAAP financial measure defined as general and administrative expenses adjusted for non-cash stock compensation expense and unusual and infrequent costs.
“Adjusted Net Income (Loss)” is a non-GAAP financial measure defined as net income (loss) adjusted for derivative gains or losses net of cash received or paid for scheduled derivative settlements, unusual and infrequent items, and the income tax expense or benefit of these adjustments using our effective tax rate.
“AROs” means the relative density, expressed in degrees, of petroleum liquids based on a specific gravity scale developed by the American Petroleum Institute.asset retirement obligations.
“basin” means a large area with a relatively thick accumulation of sedimentary rocks.
“Bblbbl” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bcfbcf” means one billion cubic feet, which is a unit of measurement of volume for natural gas.
“BoeBLM” means for the U.S. Bureau of Land Management.
“boe” means barrel of oil equivalent, determined using the ratio of one Bblbbl of oil, condensate or natural gas liquids to six Mcfmcf of natural gas.
“Boe/boe/d” means Boeboe per day.
“Brent” means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea.
“Btubtu” means one British thermal unit-aunit—a measure of the amount of energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit at sea level.
“CalGEM” is an abbreviation for the California Geologic Energy Management Division.
“Cap-and-trade” is a statewide program in California established by the Global Warming Solutions Act of 2006 which outlined an enforceable compliance obligation beginning with 2013 GHG emissions and currently extended through 2030.
“CEQA” is an abbreviation for the California Environmental Quality Act which, among other things, requires certain governmental agencies to conduct environmental review of projects for which the agency is issuing a permit.
“CJWS” refers to C&J Well Services, LLC and CJ Berry Well Services Management, LLC, the two entities that
constitute our upstream well servicing and abandonment business segment in California.
“Clean Water Rule” refers to the rule issued in August 2015 by the EPA and U.S. Army Corps of Engineers which expanded the scope of the federal jurisdiction over wetlands and other types of waters.
“Completion” means the installation of permanent equipment for the production of oil or natural gas.
“Condensate” means a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
“Development drilling or CPUC” is an abbreviation for the California Public Utilities Commission.
“DD&A” means depreciation, depletion & amortization.
“Development well” means a well drilled to a known producing formation in a previously discovered field, usually offsetting a producing well on the same or an adjacent oil and natural gas lease.
“Diatomite” means a sedimentary rock composed primarily of siliceous, diatom shells.
“Differential” means an adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
“Downspacing” means additional wells drilled between known producing wells to better develop the reservoir.
“Enhanced oil recoveryHSE” is an abbreviation for Health, Safety, and Environmental.
“EPA” means a techniqueis an abbreviation for increasing the amount of oil that can be extracted from a field.United States Environmental Protection Agency.
“EOREPS” means enhanced oil recovery.is an abbreviation for earnings per share.
“Estimated ultimate recovery” or “EUR” means the sum of reserves remaining as of a given date and cumulative production as of that date. EUR is shown on a combined basis for oil and natural gas.
“Exploration activities” means the initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.
“FASB” is an abbreviation for the Financial Accounting Standards Board.
“Field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
“Formation” means a layer of rock which has distinct characteristics that differ from those of nearby rock.
“Fracturing” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.
“GAAP” is an abbreviation for U.S. generally accepted accounting principles.
“Gas” or “Natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain liquids.
“Gross AcresGHG” or “GHGs” is an abbreviation for greenhouse gases.
“Gross Acres” or “Gross Wells” means the total acres or wells, as the case may be, in which we have a working interest.
“Held by production” means acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or natural gas.
“Henry Hub” is a distribution hub on the natural gas pipeline system in Erath, Louisiana.
“Horizontal drilling” means a wellbore that is drilled laterally.
“Hydraulic fracturing” means a procedure to stimulate production by forcing a mixture of fluid and proppant (usually sand) into the formation under high pressure. This creates artificial fractures in the reservoir rock, which increases permeability.
“Horizontal drilling” means a wellbore that is drilled laterally.
“ICE” means Intercontinental Exchange.
“Infill drilling” means drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.
“Injection Well” means a well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.
“IOR” means improved oil recovery.
“IPO”is an abbreviation for initial public offering.
“LCFS” is an abbreviation for low carbon fuel standard.
“Leases” means full or partial interests in oil or gas properties authorizing the owner of the lease to drill for, produce and sell oil and natural gas in exchange for any or all of rental, bonus and royalty payments. Leases are generally acquired from private landowners (fee leases) and from federal and state governments on acreage held by them.
“MBblmbbl” means one thousand barrels of oil, condensate or NGLs.
“MBoembbl/d” means mbbl per day.
“mboe” means one thousand barrels of oil equivalent.
“MBoe/mboe/d” means MBoemboe per day.
“Mcfmcf” means one thousand cubic feet, which is a unit of measurement of volume for natural gas.
“MMBblmmbbl” means one million barrels of oil, condensate or NGLs.
“MMBoe”mmboe” means one million barrels of oil equivalent.
“MMBtummbtu” means one million Btus.btus.
“MMcfmmbtu/d” means mmbtu per day.
“mmcf” means one million cubic feet, which is a unit of measurement of volume for natural gas.
“MMcf/mmcf/d” means MMcfmmcf per day.
“MW” means megawatt.
“MWHs” means megawatt hours.
“NASDAQ” means Nasdaq Global Select Market.
“NEPA” is an abbreviation for the National Environmental Policy Act, which requires careful evaluation of the environmental impacts of oil and natural gas production activities on federal lands.
“Net Acres” or “Net Wells” is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.
“Net revenue interest” means all of the working interests, less all royalties, overriding royalties, non-participating royalties, net profits interest or similar burdens on or measured by production from oil and natural gas.
“NGA” is an abbreviation for the Natural Gas Act.
“NGL” or “NGLs” means natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
“NRI” is an abbreviation for net revenue interest.
“NYMEX” means New York Mercantile Exchange.
“Oil” means crude oil or condensate.
“OPEC” is an abbreviation for the Organization of the Petroleum Exporting Countries.
“Operator” means the individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.
“OTC”means over-the-counter
“PALs” is an abbreviation for project approval letters.
“PCAOB” is an abbreviation for the Public Company Accounting Oversight Board.
“PDNP” is an abbreviation for proved developed non-producing.
“PDP” is an abbreviation for proved developed producing.
“Permeability” means the ability, or measurement of a rock’s ability, to transmit fluids.
“Play” means a regionally distributed oil and natural gas accumulation. Resource plays are characterized by continuous, aerially extensive hydrocarbon accumulations.
“Porosity” means the total pore volume per unit volume of rock.
“PPA” is an abbreviation for power purchase agreement.
“Production costs” means costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. For a complete definition of production costs, refer to the SEC’s Regulation S-X, Rule 4-10(a)(20).
“Productive well” means a well that is producing oil, natural gas or NGLs or that is capable of production.
“Proppant” means sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.
“Prospect” means a specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved developed producing reserves” means reserves that are being recovered through existing wells with existing equipment and operating methods.
“Proved reserves” means the estimated quantities of oil, gas and gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
“Proved undeveloped drilling location” means a site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
“Proved undeveloped reserves” or “PUDs” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
“PSUs” means performance-based restricted stock units
“PV-10” is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. While this measure does not include the effect of income
taxes as it would in the use of the standardized measure calculation, it does provide an indicative representation of the relative value of the company on a comparative basis to other companies and from period to period.
“QF” means qualifying facility.
“Realized price” means the cash market price less all expected quality, transportation and demand adjustments.
“Reasonable certainty” means a high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
“Recompletion” means the completion for production from an existing wellbore in a formation other than that in which the well has previously been completed.
“Relative TSR” means relative total stockholder return.
“Reserves” means estimated remaining quantities of oil and natural gas and related substances anticipated to be
economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Resources” means quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
“Royalty” means the share paid to the owner of mineral rights, expressed as a percentage of gross income from oil and natural gas produced and sold unencumbered by expenses relating to the drilling, completing and operating of the affected well.
“Royalty interest” means an interest in an oil and natural gas property entitling the owner to shares of oil and natural gas production, free of costs of exploration, development and production operations.
“RSUs” is an abbreviation for restricted stock units.
“SEC Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules based on the unweighted arithmetic average of oil and natural gas prices as of the first day of each of the 12 months ended on the given date.
“Seismic Data” means data produced by an exploration method of sending energy waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of a subsurface rock formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional views.
“SOFR” is an abbreviation for Secured Overnight Financing Rate.
“Spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Steamflood” means cyclic or continuous steam injection.
“Standardized measure” means discounted future net cash flows estimated by applying year-end prices to the estimated future production of proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Stimulating” means mechanically inducing a crack or surface of breakage within rock not related to foliation or cleavage in metamorphic rock in order to enhance the permeability of rocks by connecting pores together.
“Strip Pricing” means pricing calculated using oil and natural gas price parameters established by current guidelines of the SEC and accounting rules with the exception of pricing that is based on average annual forward-month ICE (Brent) oil and NYMEX Henry Hub natural gas contract pricing in effect on a given date to reflect the market expectations as of that date.
“Superfund” is a commonly known term for CERCLA.
“UIC” is an abbreviation for the Underground Injection Control program.
“Unconventional resource plays” means a resource play that uses methods other than traditional vertical well extraction. Unconventional resources are trapped in reservoirs with low permeability, meaning little to no ability for the oil or natural gas to flow through the rock and into a wellbore. Examples of unconventional oil resources include oil shales, oil sands, extra-heavy oil, gas-to-liquids and coal-to-liquids.
“Undeveloped acreage” means lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.
“Unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Unproved reserves” means reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
“Wellbore” means the hole drilled by the bit that is equipped for natural gasresource production on a completed well. Also called well or borehole.
“Working interest” means an interest in an oil and natural gas lease entitling the holder at its expense to conduct drilling and production operations on the leased property and to receive the net revenues attributable to such interest, after deducting the landowner’s royalty, any overriding royalties, production costs, taxes and other costs.
“Workover” means maintenance on a producing well to restore or increase production.
“WST” is an abbreviation for well stimulation treatment.
“WTI” means West Texas Intermediate.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | Berry Corporation (bry) |
| | (Registrant) |
| | |
| Date: | May 1, 2024 | /s/ Fernando Araujo |
| | BERRY PETROLEUM CORPORATIONFernando Araujo |
| | (Registrant)Chief Executive Officer |
| | (Principal Executive Officer) |
| Date: August 23, 2018 | |
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| | |
| Date: | May 1, 2024 | /s/ Michael S. Helm |
| | Michael S. Helm |
| | Vice President, Chief Financial Officer and
Chief Accounting Officer |
| | (Duly AuthorizedPrincipal Financial Officer and
Principal Accounting Officer) |
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Date: August 23, 2018 | /s/ Cary Baetz |
| Cary Baetz |
| Executive Vice President and Chief Financial Officer |
| (Principal Financial Officer) |