CDN NEWS | 
US NEWS 
BAKERSFIELD, Calif., Aug. 22, 2018 (GLOBE NEWSWIRE) — Berry Petroleum Corporation (NASDAQ: BRY) (“Berry” or the “Company”), a California-based independent upstream energy company engaged primarily in the development and production of onshore conventional oil reserves located in the western United States, today reported a net loss attributable to common stockholders of $34 million or $0.84 per diluted share for the second quarter of 2018. Adjusted net income for the second quarter of 2018 was $9 million. In addition, the Board approved a regular $0.12 per share dividend on a pro-rated basis from the date of the Company’s initial public offering, which will result in a payment of $0.09 per share.
Highlights for the Quarter
- Unhedged adjusted EBITDA of $78 million and Adjusted EBITDA of $50 million
- Lower Operating Expenses (“OpEx”) by $2.72/BOE compared to first quarter
- California oil price realizations of 92% of Brent pricing or $68.73/Bbl before hedging, up $6.36/Bbl versus the first quarter
- Restructured hedge portfolio increases weighted average price of hedged volumes to $69.76/Bbl Brent from $53.29/Bbl WTI through 2020 on 6.1 million Bbls.
- Capital Expenditures of $39 million with over 90% directed to California development
- Production increase of 300 BOE/D over first quarter 2018 to 26,500 BOE/D
Trem Smith, Berry president and chief executive officer stated, “We are pleased to report Berry’s 2018 second quarter financial and operational results – our first such report as a public company. Our second quarter results reflect the company’s strategy of being oil focused and growing our value and production while operating within levered free cash flow today and into the future. We are starting to see the expected quarter over quarter production growth. We expect this growth to continue as we invest in our existing, growing inventory of opportunities. Also, our Board approved our first regular quarterly dividend which demonstrates our commitment of returning capital to our shareholders. I am excited that Berry is now public, so the market can see the strength of our assets and our ability to focus on what we do best including our ability to execute our plan.”
Quarterly Results
Adjusted net income was $9 million for both the second and first quarters of 2018. Adjusted net income is calculated by excluding non-cash derivative gains and losses and non-recurring items such as reorganization and restructuring gains and costs. The adjusted income in the second quarter of 2018 compared to the first quarter reflected higher oil prices, higher production and lower operating expenses, offset primarily by higher scheduled hedge settlements, and to a lesser degree increases in general and administrative expenses, taxes other than income taxes, depreciation, depletion and amortization and interest expense.
For the second quarter, Berry reported adjusted EBITDA, on an unhedged basis, of $78 million compared to $62 million in the first quarter. Adjusted EBITDA hedged in the second quarter was $50 million compared to $45 million for the first quarter.
Cary Baetz, chief financial officer said, “In the second quarter we restructured our hedge position to reflect current market pricing and to give the market better visibility into our cash flow generating capabilities. The original hedges were put in place last summer in association with our new credit facility. We used the proceeds of our initial public offering to pay down our reserve-based lending (“RBL”) revolver, which was used to fund a portion of the early hedge termination payments and the distribution we made to the preferred stockholders upon their conversion to common stock. We now have RBL capacity of $400 million with an ability to upsize to $575 million with lender approval. Our current liquidity is $424 million, including cash of $36 million.”
Improving global commodity prices resulted in second quarter California oil prices before hedges averaging $68.73/Bbl which were 10% higher than the $62.37/Bbl realized in the first quarter. Realized oil prices for the Company including the settled hedges were $53.22 and $52.74 per barrel in the second and first quarters, respectively.
Production for the second quarter of 2018 averaged 26,500 Boe/d compared to 26,180 Boe/d in the first quarter. Oil volumes averaged 21,100 barrels per day in the second quarter, natural gas averaged 28,000 Mcf per day and NGLs averaged 700 barrels per day. California provided 18,800 Boe/d in the second quarter, Utah provided 5,300 Boe/d and Colorado and Texas collectively provided 2,400 Boe/d.
For the second quarter, OpEx totaled $41 million or $16.89/BOE. OpEx consists of LOE, as well as expenses and third-party revenues from electricity generation, transportation and marketing activities and excludes taxes other than income taxes. In the second quarter, OpEx benefited from a $3 million reduction in LOE as compared to the first quarter due to lower fuel gas costs, lower well-servicing activity and increased oil inventory caused by the market disruptions in Utah. Electricity generation expenses were $1.5 million lower than the preceding quarter due to lower fuel gas costs and reduced cogeneration operating costs.
General and administrative expenses increased by $0.5 million, or 4%, to $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. For the three months ended June 30, 2018 and March 31, 2018, general and administrative expenses included non-recurring restructuring and other costs of $1.7 million and $2.0 million, respectively, and non-cash stock compensation costs of $1.3 million and $1.0 million, respectively.
Taxes, other than income taxes were $8.7 million, or $3.62/BOE for the second quarter, an increase of $0.5 million from the first quarter largely due to increased rates and usage of greenhouse gas allowances.
Capital expenditures totaled $39 million for the second quarter compared to $16 million for the first quarter. The Company ran a three-rig drilling program in California during the second quarter.
Full-Year 2018 Guidance
- Production between 27,000 to 30,000 BOEPD, approximately 80% oil
- OpEx ranging from $17.00 to $18.75 per BOE
- Taxes, other than income taxes, ranging from $3.25 to $3.50 per BOE
- Adjusted G&A ranging from $3.25 to $3.75 per BOE
Dividend Announcement
On August 21, 2018 the Board declared a regular dividend for the third quarter at a rate of $0.12 per share on the company’s outstanding common stock pro-rated for the period from and including July 25, 2018 through quarter end resulting in a payment of $0.09 per share. At the closing price of BRY stock on August 21, the implied dividend yield is 3.6%. This is the first regular quarterly dividend paid by the Company, and the Company, subject to approval by the Board, intends to pay a similar dividend in future quarters.
The third quarter dividend is payable on October 15, 2018 to shareholders of record at the close of business on September 15, 2018.
Earnings Conference Call
The Company will host a conference call August 23, 2018 to discuss these results:
| Live Call Date: | Thursday, August 23, 2018 |
| Live Call Time: | 11:00 a.m. Eastern Time (8 a.m. Pacific Time) |
| Live Call Dial-in: | 877-491-5165 from the U.S. |
| 720-405-2253 from international locations | |
| Live Call Passcode: | 7998843 |
A live audio webcast will be available on the “Investors” section of Berry’s website at berrypetroleum.com/investors.
An audio replay will be available shortly after the broadcast:
| Replay Dates: | Through Thursday, September 6, 2018 |
| Replay Dial-in: | 855-859-2056 from the U.S. |
| 404-537-3406 from international locations | |
| Replay Passcode: | 7998843 |
A replay of the audio webcast will also be archived on the “Investors” section of Berry’s website at berrypetroleum.com/investors. In addition, an investor presentation will be available on the Company’s website.
About Berry Petroleum
Berry Petroleum is a publicly-traded (NASDAQ: BRY) California-based independent upstream energy company engaged primarily in the development and production of onshore conventional oil reserves located in the western United States. More information can be found at the Company’s website at berrypetroleum.com.
Forward Looking Statements
The information in this press release includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results 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,
- 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. Factors (but not necessarily all the factors) that could cause results to differ include:
- volatility of oil, natural gas and NGL prices;
- inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures and meet working capital requirements;
- price and availability of natural gas;
- 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 proposed drilling schedule and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
- effects of competition;
- our ability to make acquisitions and successfully integrate any acquired businesses; and
- other material risks that appear in the Risk Factors section of our Registration Statement on Form S-1.
You can typically identify forward-looking statements by words such as aim, anticipate, achievable, believe, continue, could, 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. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.
TABLES FOLLOWING
| SUMMARY OF RESULTS | Quarter Ended June 30 |
Quarter Ended Mar 31 |
Quarter Ended June 30 |
||||||
| ($ and shares in thousands, except per share amounts) | 2018 | 2018 | 2017 | ||||||
| Consolidated Statement of Operations Data: | |||||||||
| Revenues and other | |||||||||
| Oil, natural gas and natural gas liquids sales | $ | 137,385 | $ | 125,624 | $ | 101,884 | |||
| Electricity sales | 5,971 | 5,453 | 5,712 | ||||||
| (Losses) gains on oil and natural gas derivatives | (78,143 | ) | (34,644 | ) | 23,962 | ||||
| Marketing revenues | 518 | 785 | 809 | ||||||
| Other revenues | 251 | 66 | 2,355 | ||||||
| 65,982 | 97,284 | 134,722 | |||||||
| Expenses and other | |||||||||
| Lease operating expenses | 41,517 | 44,303 | 45,726 | ||||||
| Electricity generation expenses | 3,135 | 4,590 | 4,465 | ||||||
| Transportation expenses | 2,343 | 2,978 | 9,404 | ||||||
| Marketing expenses | 407 | 580 | 730 | ||||||
| General and administrative expenses | 12,482 | 11,985 | 22,257 | ||||||
| Depreciation, depletion and amortization | 21,859 | 18,429 | 20,549 | ||||||
| Taxes, other than income | 8,715 | 8,256 | 10,249 | ||||||
| Losses (gains) on sale of assets and other, net | 123 | — | 5 | ||||||
| 90,581 | 91,121 | 113,385 | |||||||
| Other income and (expenses) | |||||||||
| Interest expense | (9,155 | ) | (7,796 | ) | (4,885 | ) | |||
| Other, net | (239 | ) | 27 | 2,916 | |||||
| (9,394 | ) | (7,769 | ) | (1,969 | ) | ||||
| Reorganization items, net | 456 | 8,955 | 713 | ||||||
| Income (loss) before income taxes | (33,537 | ) | 7,349 | 20,081 | |||||
| Income tax expense (benefit) | (5,476 | ) | 939 | 7,961 | |||||
| Net income (loss) | (28,061 | ) | 6,410 | 12,120 | |||||
| Dividends on Series A preferred stock | (5,650 | ) | (5,650 | ) | (5,404 | ) | |||
| Net income (loss) attributable to common stockholders | $ | (33,711 | ) | $ | 760 | $ | 6,716 | ||
| Net income (loss) per share attributable to common stockholders | |||||||||
| Basic | $ | (0.84 | ) | $ | 0.02 | $ | 0.17 | ||
| Diluted | $ | (0.84 | ) | $ | 0.02 | $ | 0.16 | ||
| Weighted-average common shares outstanding – basic (a) | 40,090 | 40,023 | 40,000 | ||||||
| Weighted-average common shares outstanding – diluted (a) | 40,090 | 40,248 | 75,845 | ||||||
| Adjusted net income (loss) | $ | 9,182 | $ | 9,384 | $ | (4,846 | ) | ||
| Adjusted EBITDA | $ | 50,018 | $ | 44,503 | $ | 42,416 | |||
| Adjusted EBITDA unhedged | $ | 78,279 | $ | 62,352 | $ | 37,691 | |||
| Levered free cash flow | $ | (3,983 | ) | $ | 15,325 | $ | 7,430 | ||
| Levered free cash flow unhedged | $ | 24,278 | $ | 33,174 | $ | 2,705 | |||
| Adjusted general and administrative expenses | $ | 9,508 | $ | 8,919 | $ | 5,411 | |||
| Effective Tax Rate | 16 | % | 13 | % | 40 | % | |||
| Cash Flow Data: | |||||||||
| Net cash (used in) provided by operating activities (b) | $ | (77,394 | ) | $ | 27,846 | $ | 20,703 | ||
| Net cash (used in) provided by investing activities | $ | (22,472 | ) | $ | (19,876 | ) | $ | (64,627 | ) |
| Net cash (used in) provided by financing activities | $ | 34,538 | $ | 11,928 | $ | 10,000 | |||
(a) Our weighted-average common shares outstanding will increase beginning in the third quarter of 2018 for additional shares from our initial public offering and preferred stock conversion.
(b) 2nd Quarter 2018 includes approximately $127 million paid to early terminate unsettled derivative contracts. The elective cancellation was effected to realign our hedging pricing with current market rates and move from NYMEX WTI to ICE Brent underlying. Had we not elected to cancel these derivative contracts our net cash provided by operating activities would have been approximately $50 million.
| Balance Sheet Data: | ||||||
| June 30, | December 31, | |||||
| ($ and shares in thousands) | 2018 | 2017 | ||||
| Total current assets | $ | 95,151 | $ | 137,524 | ||
| Total property, plant and equipment, net | $ | 1,397,919 | $ | 1,387,191 | ||
| Total current liabilities | $ | 144,327 | $ | 182,659 | ||
| Long-term debt | $ | 457,333 | $ | 379,000 | ||
| Total equity | $ | 808,496 | $ | 859,310 | ||
| Issued and Outstanding common stock shares as of (c) | $ | 33,088 | $ | 32,920 | ||
(c) Excludes 7,080,000 common stock shares reserved at Emergence for general unsecured creditors electing to settle claims in exchange for common shares. All claims have yet to be settled, however, management has been and continues negotiating with these creditors which may reduce the impact of dilution by 3 to 4 million shares.
| COMMODITY PRICING |
Quarter Ended June 30 |
Quarter Ended Mar 31 |
Quarter Ended June 30 |
|||||||
| 2018 | 2018 |
2017 | ||||||||
| Realized Prices | ||||||||||
| Oil without hedge ($/Bbl) | $ | 67.93 | $ | 62.14 | $ | 44.27 | ||||
| Effects of scheduled derivative settlements ($/Bbl) | $ | (14.71 | ) | $ | (9.40 | ) | $ | 2.70 | ||
| Oil with hedge ($/Bbl) | $ | 53.22 | $ | 52.74 | $ | 46.97 | ||||
| Natural gas ($/Mcf) | $ | 2.12 | $ | 2.64 | $ | 2.74 | ||||
| NGLs ($/Bbl) | $ | 24.38 | $ | 25.56 | $ | 22.72 | ||||
| Index Prices | ||||||||||
| Brent oil ($/Bbl) | $ | 74.87 | $ | 67.16 | $ | 50.90 | ||||
| WTI oil ($/Bbl) | $ | 67.76 | $ | 62.87 | $ | 48.28 | ||||
| Henry Hub natural gas ($/Mcf) | $ | 2.80 | $ | 3.00 | $ | 3.18 | ||||
CURRENT HEDGING SUMMARY
| 3rd Quarter | 4th Quarter | Fiscal Year | Fiscal Year | |||||||||
| 2018 | 2018 | 2019 | 2020 | |||||||||
| Sold Oil Calls (ICE Brent): | ||||||||||||
| Hedge oil volume (MBbls) | 186 | — | — | — | ||||||||
| Weighted average price ($/Bbl) | $ | 81.67 | $ | — | $ | — | $ | — | ||||
| Purchased Put Option (ICE Brent): | ||||||||||||
| Hedge oil volume (MBbls) | — | — | 2,835 | 455 | ||||||||
| Weighted average price ($/Bbl) | $ | — | $ | — | $ | 65.00 | $ | 65.00 | ||||
| Fixed Price Swaps (ICE Brent): | ||||||||||||
| Hedge oil volume (MBbls) | 966 | 966 | 900 | — | ||||||||
| Weighted average price ($/Bbl) | $ | 75.13 | $ | 75.13 | $ | 75.66 | $ | — | ||||
| Oil basis differential positions: | ||||||||||||
| ICE Brent – NYMEX WTI basis swaps | ||||||||||||
| Hedge oil volume (MBbls) | 92 | 92 | 183 | — | ||||||||
| Weighted average price ($/Bbl) | $ | 1.29 | $ | 1.29 | $ | 1.29 | $ | — | ||||
OPERATING EXPENSES
| Quarter Ended June 30 |
Quarter Ended Mar 31 |
Quarter Ended June 30 |
|||||||
| ($ in thousands except per MBOE amounts) | 2018 | 2018 | 2017 | ||||||
| Lease operating expenses | $ | 41,517 | $ | 44,303 | $ | 45,726 | |||
| Electricity generation expenses | $ | 3,135 | $ | 4,590 | $ | 4,465 | |||
| Electricity sales (a) | $ | (5,971 | ) | $ | (5,453 | ) | $ | (5,712 | ) |
| Transportation expenses | $ | 2,343 | $ | 2,978 | $ | 9,404 | |||
| Transportation sales (a) | $ | (251 | ) | $ | — | $ | — | ||
| Marketing expenses | $ | 407 | $ | 580 | $ | 730 | |||
| Marketing revenues (a) | $ | (518 | ) | $ | (785 | ) | $ | (809 | ) |
| Total operating expenses (a) | $ | 40,662 | $ | 46,213 | $ | 53,804 | |||
| Lease operating expenses ($/MBOE) | $ | 17.24 | $ | 18.80 | $ | 14.62 | |||
| Electricity generation expenses ($/MBOE) | $ | 1.30 | $ | 1.94 | $ | 1.43 | |||
| Electricity sales ($/MBOE) | $ | (2.48 | ) | $ | (2.31 | ) | $ | (1.83 | ) |
| Transportation expenses ($/MBOE) | $ | 0.97 | $ | 1.26 | $ | 3.01 | |||
| Transportation sales ($/MBOE) | $ | (0.09 | ) | $ | — | $ | — | ||
| Marketing expenses ($/MBOE) | $ | 0.17 | $ | 0.25 | $ | 0.23 | |||
| Marketing revenues ($/MBOE) | $ | (0.22 | ) | $ | (0.33 | ) | $ | (0.26 | ) |
| Total operating expenses ($/MBOE) | $ | 16.89 | $ | 19.61 | $ | 17.20 | |||
| Total MBOE | 2,408 | 2,356 | 3,128 | ||||||
(a) 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”, relates to water and other liquids that we transport on our systems on behalf of third parties.
PRODUCTION STATISTICS
| Quarter Ended June 30 |
Quarter Ended Mar 31 |
Quarter Ended June 30 |
||||
| Net Oil, Natural Gas and NGLs Production Per Day | 2018 | 2018 | 2017 | |||
| Oil (MBbl/d) | ||||||
| California | 18.8 | 18.8 | 16.3 | |||
| Hugoton basin | — | — | — | |||
| Uinta basin | 2.3 | 2.3 | 2.9 | |||
| Piceance basin | — | — | — | |||
| East Texas | — | — | — | |||
| 21.1 | 21.1 | 19.2 | ||||
| Natural gas (MMcf/d) | ||||||
| California | — | — | — | |||
| Hugoton basin | — | — | 35.5 | |||
| Uinta basin | 13.8 | 13.4 | 16.9 | |||
| Piceance basin | 9.4 | 9.3 | 14.9 | |||
| East Texas | 4.8 | 4.9 | 5.8 | |||
| 28.0 | 27.6 | 73.1 | ||||
| NGLs (MBbl/d) | ||||||
| California | — | — | — | |||
| Hugoton basin | — | — | 2.7 | |||
| Uinta basin | 0.7 | 0.5 | 0.2 | |||
| Piceance basin | — | — | — | |||
| East Texas | — | — | — | |||
| 0.7 | 0.5 | 2.9 | ||||
| Total Production (MBOE/d) (a) | 26.5 | 26.2 | 34.4 | |||
(a) Natural gas volumes have been converted to BOE based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the year ended December 31, 2017, the average prices of ICE (Brent) oil and NYMEX Henry Hub natural gas were $54.82 per Bbl and $3.11 per Mcf, respectively, resulting in an oil-to-gas ratio of over 17 to 1.
CAPITAL EXPENDITURES ACCRUAL BASIS
| Quarter Ended June 30 |
Quarter Ended March 31 |
Quarter Ended June 30 |
|||||||
| (in thousands) | 2018 | 2018 | 2017 | ||||||
| Capital expenditures- accrual basis | $ | 39,196 | $ | 15,732 | $ | 24,697 | |||
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
Adjusted Net Income (Loss) and Adjusted EBITDA are not measures of net income (loss), Levered Free Cash Flow is not a measure of cash flow and Adjusted General and Administrative Expenses is not a measure of general and administrative expenses, in all cases, as determined by GAAP. Adjusted Net Income (Loss), Adjusted EBITDA, Levered Free Cash Flow and Adjusted General and Administrative Expenses are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted Net Income (Loss) as net income (loss) 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 costs and the income tax expense or benefit of these adjustments using the Company’s 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; asset 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. 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.
Adjusted Net Income (Loss) excludes the impact of unusual, out-of-period and infrequent items affecting earning that vary widely and unpredictably, including non-cash items such as derivatives gains and losses. This measure is used by management when comparing results period over period. Adjusted EBITDA is the primary financial measurement that our management uses to analyze and monitor the operating performance of our business. Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. Levered Free Cash Flow reflects our financial flexibility; and we use it to plan our internal growth capital expenditures. Levered Free Cash Flow is our primary metric used in planning capital allocation for maintenance and internal growth opportunities as well as hedging needs and serves as a measure for assessing our financial performance and measuring our ability to generate excess cash from our operations after servicing indebtedness. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively compare our performance from period to period. We exclude the items listed above from general and administrative expenses in arriving at Adjusted General and Administrative Expenses because these amounts can vary widely and unpredictably in nature, timing, amount and frequency and stock compensation expense is non-cash in nature.
While Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged and Adjusted General and Administrative Expenses are non-GAAP measures, the amounts included in the calculations of Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged and Adjusted General and Administrative Expenses were computed in accordance with GAAP. These measures are provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP and Adjusted General and Administrative Expenses should not be considered as an alternative to, or more meaningful than, general and administrative expenses as determined in accordance with GAAP. Our computations of Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged and Adjusted General and Administrative Expenses may not be comparable to other similarly titled measures used by other companies. Adjusted Net Income (Loss), Adjusted EBITDA, Adjusted EBITDA Unhedged, Levered Free Cash Flow, Levered Free Cash Flow Unhedged and Adjusted General and Administrative Expenses should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of the GAAP financial measure of net income (loss) attributable to common stockholders to the non-GAAP financial measure of Adjusted Net Income (Loss).
| Quarter Ended June 30 |
Quarter Ended Mar 31 |
Quarter Ended June 30 |
|||||||
| ($ thousands, except per share amounts) | 2018 | 2018 | 2017 | ||||||
| Net income (loss) attributable to common stockholders | $ | (33,711 | ) | $ | 760 | $ | 6,716 | ||
| Add (Subtract): | |||||||||
| Losses (gains) on oil and natural gas derivatives | 78,143 | 34,644 | (23,962 | ) | |||||
| Net cash received (paid) for scheduled derivative settlements | (28,261 | ) | (17,849 | ) | 4,725 | ||||
| Losses (gains) on sale of assets and other, net | 123 | — | 5 | ||||||
| Non-recurring restructuring and other costs | 1,714 | 2,047 | 16,846 | ||||||
| Reorganization items, net | (456 | ) | (8,955 | ) | (713 | ) | |||
| 51,263 | 9,887 | (3,099 | ) | ||||||
| Income tax (expense) benefit of adjustments at effective tax rate | (8,370 | ) | (1,263 | ) | 1,229 | ||||
| Adjusted net income (loss) | $ | 9,182 | $ | 9,384 | $ | 4,846 | |||
ADJUSTED EBITDA AND ADJUSTED EBITDA UNHEDGED
The following tables present a reconciliation of the GAAP financial measures of net income (loss) and net cash (used in) provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA Unhedged.
| Quarter Ended June 30 |
Quarter Ended Mar 31 |
Quarter Ended June 30 |
|||||||
| ($ thousands) | 2018 | 2018 | 2017 | ||||||
| Net income (loss) | $ | (28,061 | ) | $ | 6,410 | $ | 12,120 | ||
| Add (Subtract): | |||||||||
| Depreciation, depletion, amortization and accretion | 21,859 | 18,429 | 20,549 | ||||||
| Interest expense | 9,155 | 7,796 | 4,885 | ||||||
| Income tax expense (benefit) | (5,476 | ) | 939 | 7,961 | |||||
| Losses (gains) on oil and natural gas derivatives | 78,143 | 34,644 | (23,962 | ) | |||||
| Net cash received (paid) for scheduled derivative settlements | (28,261 | ) | (17,849 | ) | 4,725 | ||||
| Losses (gains) on sale of assets and other, net | 123 | — | 5 | ||||||
| Stock compensation expense | 1,278 | 1,042 | — | ||||||
| Non-recurring restructuring and other costs | 1,714 | 2,047 | 16,846 | ||||||
| Reorganization items, net | (456 | ) | (8,955 | ) | (713 | ) | |||
| Adjusted EBITDA | $ | 50,018 | $ | 44,503 | $ | 42,416 | |||
| Net cash (received) paid for scheduled derivative settlements | 28,261 | 17,849 | (4,725 | ) | |||||
| Adjusted EBITDA unhedged | $ | 78,279 | $ | 62,352 | $ | 37,691 | |||
| Net cash (used in) provided by operating activities | (77,394 | ) | 27,846 | 20,703 | |||||
| Add (Subtract): | |||||||||
| Cash interest payments | 644 | 2,654 | 4,860 | ||||||
| Cash income tax payments | — | — | 1,168 | ||||||
| Cash reorganization item payments (receipts) | 1,047 | 305 | (1,384 | ) | |||||
| Non-recurring restructuring and other costs | 1,714 | 2,047 | 16,846 | ||||||
| Derivative early termination payment | 126,949 | — | — | ||||||
| Other changes in operating assets and liabilities | (2,942 | ) | 11,651 | 223 | |||||
| Adjusted EBITDA | $ | 50,018 | $ | 44,503 | $ | 42,416 | |||
| Net cash (received) paid for scheduled derivative settlements | 28,261 | 17,849 | (4,725 | ) | |||||
| Adjusted EBITDA unhedged | $ | 78,279 | $ | 62,352 | $ | 37,691 | |||
LEVERED FREE CASH FLOW
Levered free cash flow reflects our financial flexibility; and we use it to plan our internal growth capital expenditures. We define levered free cash flow as Adjusted EBITDA less capital expenditures, interest expense, and dividends. Levered free cash flow is our primary metric used in planning capital allocation for maintenance and internal growth opportunities as well as hedging needs and serves as a measure for assessing our financial performance and measuring our ability to generate excess cash from our operations after servicing indebtedness.
| Quarter Ended June 30 |
Quarter Ended Mar 30 |
Quarter Ended June 30 |
|||||||
| ($ thousands) | 2018 | 2018 | 2017 | ||||||
| Adjusted EBITDA | $ | 50,018 | $ | 44,503 | $ | 42,416 | |||
| Add (Subtract): | |||||||||
| Capital expenditures- accrual basis | (39,196 | ) | (15,732 | ) | (24,697 | ) | |||
| Interest expense | (9,155 | ) | (7,796 | ) | (4,885 | ) | |||
| Dividends | (5,650 | ) | (5,650 | ) | (5,404 | ) | |||
| Levered free cash flow | $ | (3,983 | ) | $ | 15,325 | $ | 7,430 | ||
| Net cash (received) paid for scheduled derivative settlements | 28,261 | 17,849 | (4,725 | ) | |||||
| Levered free cash flow unhedged | $ | 24,278 | $ | 33,174 | $ | 2,705 | |||
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES
The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measures of Adjusted general and administrative expenses.
| Quarter Ended June 30 |
Quarter Ended Mar 31 |
Quarter Ended June 30 |
|||||||
| ($ in thousands except per MBOE amounts) | 2018 | 2018 | 2017 | ||||||
| General and administrative expenses | $ | 12,482 | $ | 11,985 | $ | 22,257 | |||
| Subtract: | |||||||||
| Non-recurring restructuring and other costs | (1,714 | ) | (2,047 | ) | (16,846 | ) | |||
| Non-cash stock compensation expense | (1,260 | ) | (1,019 | ) | — | ||||
| Adjusted general and administrative expenses | $ | 9,508 | $ | 8,919 | $ | 5,411 | |||
| General and administrative expenses ($/MBOE) | $ | 5.18 | $ | 5.09 | $ | 7.11 | |||
| Subtract: | |||||||||
| Non-recurring restructuring and other costs ($/MBOE) | $ | (0.71 | ) | $ | (0.87 | ) | $ | (5.39 | ) |
| Non-cash stock compensation expense ($/MBOE) | $ | (0.52 | ) | $ | (0.43 | ) | $ | 0.00 | |
| Adjusted general and administrative expenses ($/MBOE) | $ | 3.94 | $ | 3.79 | $ | 1.72 | |||
| Total MBOE | 2,408 | 2,356 | 3,128 | ||||||
Contact Contact: Berry Petroleum Corporation Todd Crabtree - Manager, Investor Relations (661) 616-3811
Share This:
Trump Is Scaring Republicans Away From Saving the Planet