Berry Petroleum Reports Second Quarter 2019 Results; Announces Quarterly Dividend
DALLAS, Aug. 07, 2019 (GLOBE NEWSWIRE) -- Berry Petroleum Corporation (NASDAQ: BRY) (“Berry” or the “Company”) today reported net income of $32 million or $0.39 per diluted share and adjusted net income of $20 million or $0.25 per diluted share for the second quarter of 2019. In addition, the Board approved a regular $0.12 per share dividend for the third quarter of 2019.
Highlights for the Quarter
- Adjusted EBITDA of $63 million and Unhedged Adjusted EBITDA of $66 million
- Received Aquifer Exemption for California Midway-Sunset field; no regulatory hurdles remain
- 1.0 million shares repurchased; 3.6 million cumulative or 4% of total outstanding
- Capital Expenditures of $57 million with approximately 92% directed to California oil development
- Current California oil production is up over 1,300 Bbl/day or 6.5% compared to June
- Layered on additional 2020 oil hedges; approximately 12,000 Bbl/Day at $65.70/Bbl Brent
- Full-year production and spending are on track; no changes to guidance
Trem Smith, Berry Petroleum board chair, chief executive officer and president stated, “Berry continues to generate significant intrinsic value for our shareholders. We are always focused on protecting and growing our base production. As planned, the ongoing development of our California oil assets has positioned us to realize considerable value growth through production increases for the remainder of 2019 and beyond. In planning for this robust second half growth, we drilled 210 wells in the first half of the year, of which 133 of them will begin to contribute to production in the second half of the year. As our 6.5% growth in current production indicates, some have already started to contribute. In fact, current California production has substantially increased compared to June and we expect to see this continue through the remainder of the year.”
“Since going public a year ago, Berry has declared $47 million in dividends; repurchased 4% of its shares and grown California production by 11% over the past twelve months. This has been done from our free cash flow. At Berry, we will continue to execute as promised, always managing to value and returning capital to shareholders as key components to our strategy.”
Second Quarter Results
Adjusted EBITDA, on an unhedged basis, was $66 million in the second quarter compared to $54 million in the first quarter. Relative to the first quarter, the second quarter had higher oil prices and lower operating expenses largely due to lower fuel costs, partially offset by higher taxes other than income taxes. Additionally, the decrease in Adjusted EBITDA, on a hedged basis, from $69 million in the first quarter compared to $63 million in the second quarter includes the impact of lower oil hedge settlements received and higher gas hedge settlement payments.
Actual production was 1% higher in the second quarter compared to the first quarter. Sales volumes, which includes the impact of inventory fluctuations, was 1% lower quarter-over-quarter, due to selling of inventory in the Rockies in the first quarter.
California oil prices before hedges for the second quarter averaged 93% of Brent, or $63.91/Bbl which were 8% higher than the $59.16/Bbl realized in the first quarter. Realized oil prices for the Company before hedges of $61.69/Bbl were 8% higher than the first quarter average of $56.88/Bbl.
For the second quarter, Operating Expenses ("OpEx") decreased to $20.38/Boe compared to $21.71/Boe in the first quarter. This decrease was largely driven by the price of natural gas we purchased for our steam operations during the second quarter, which decreased by $6.86/Boe, partially offset by settled gas hedge losses which increased by $2.93/Boe. OpEx consists of lease operating expenses ("LOE"), as well as expenses and third-party revenues from electricity generation, transportation and marketing activities and the effect of derivative settlements (received or paid) for gas purchases while excluding taxes other than income taxes.
General and administrative expenses were $16.2 million for the second quarter compared to $14.3 million for the first quarter. The second quarter was affected by higher non-cash stock compensation associated with the annual grant of stock awards in March. Adjusted general and administrative expenses were $4.92/Boe for the second quarter compared to $4.63/Boe for the first quarter primarily due to organizational growth and system enhancements.
Taxes, other than income taxes were $4.54/Boe for the second quarter compared to $3.23/Boe in the first quarter, due to higher greenhouse gas unit costs and the impact of severance tax refunds in the first quarter.
Capital expenditures totaled $57 million for the second quarter compared to $49 million for the first quarter and was largely focused on California drilling in both periods. The 2019 capital program was front-end loaded resulting in more wells drilled in the first half of the year than the amount expected to be drilled in the second half. The Company expects that a significant portion of the 210 wells drilled in the first six months of 2019 will generate robust growth in the last half of the year as they come online or realize the full effects of steam injection.
Net income for the second quarter 2019 was $32 million compared to a net loss of $34 million in the first quarter and this difference was largely driven by derivative mark-to-market changes. Adjusted net income was $20 million for the second quarter compared to $24 million for the first quarter of 2019. The decrease was due to the same factors affecting Adjusted EBITDA.
At July 31, our liquidity under our $400 million reserve-based revolver was $371 million as we had $9 million of outstanding letters of credit and borrowed $20 million on our revolver to fund monthly working capital fluctuations and the $11 million spent on share repurchases during the second quarter. The Company expects to have no revolver borrowings by year-end.
Dividend Announcement
On July 25, 2019 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. This is the Company's fifth regular quarterly dividend, 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, 2019 to shareholders of record at the close of business on September 13, 2019.
SEC Filing Announcement
On August 9, the Company expects to file a universal shelf registration statement on Form S-3 with the SEC. The Company currently has no plans for an offering. The Company also expects to file a post-effective amendment to the Form S-1 registration statement it maintains for certain stockholders who held the Company’s stock prior to the Company’s IPO. The amendment will convert the Form S-1 to the simpler Form S-3, which incorporates future filings by reference. The number of securities registered is not increasing.
Earnings Conference Call
The Company will host a conference call August 8, 2019 to discuss these results:
| Live Call Date: | Thursday, August 8, 2019 |
| Live Call Time: | 11:00 a.m. Eastern Time (8 a.m. Pacific Time) |
| Live Call Dial-in: | 877-491-5169 from the U.S. |
| 720-405-2254 from international locations | |
| Live Call Passcode: | 5797269 |
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, August 22, 2019 |
| Replay Dial-in: | 855-859-2056 from the U.S. |
| 404-537-3406 from international locations | |
| Replay Passcode: | 5797269 |
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 Corporation is a publicly-traded (NASDAQ:BRY) western United States independent upstream energy company with a focus on the conventional, long-lived oil reserves in the San Joaquin basin of California. More information can be found at the Company’s website at www.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,
- maintenance capital requirements,
- expected production and costs,
- reserves,
- hedging activities,
- return of capital,
- capital investments and other guidance.
Actual results may differ from expectations, sometimes materially, and reported results should not be considered an indication of future performance. Factors (but not all the factors) that could cause results to differ include:
- volatility of oil, natural gas and natural gas liquids (NGL) prices;
- our ability to obtain permits and otherwise to meet our proposed drilling schedule and to successfully drill wells that produce oil and natural gas in commercially viable quantities;
- price and availability of natural gas;
- changes in laws or regulations;
- our ability to use derivative instruments to manage commodity price risk;
- the impact of environmental, health and safety, and other governmental regulations, and of current or pending or future legislation;
- uncertainties associated with estimating proved reserves and related future cash flows;
- our ability to replace our reserves through exploration and development activities;
- timely and available drilling and completion equipment and crew availability and access to necessary resources for drilling, completing and operating well;
- our ability to make acquisitions and successfully integrate any acquired businesses; and
- other material risks that appear in the Risk Factors section of the prospectus filed with the SEC in connection with our initial public offering.
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
The financial information and certain other information presented have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables. In addition, certain percentages presented here reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers, or may not sum due to rounding.
SUMMARY OF RESULTS
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| ($ and shares in thousands, except per share amounts) | |||||||||||
| Statement of Operations Data: | |||||||||||
| Revenues and other: | |||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 136,908 | $ | 131,102 | $ | 137,385 | |||||
| Electricity sales | 5,364 | 9,729 | 5,971 | ||||||||
| Gains (losses) on oil derivatives | 27,276 | (65,239 | ) | (78,143 | ) | ||||||
| Marketing revenues | 414 | 830 | 518 | ||||||||
| Other revenues | 104 | 117 | 251 | ||||||||
| Total revenues and other | 170,066 | 76,539 | 65,982 | ||||||||
| Expenses and other: | |||||||||||
| Lease operating expenses | 47,879 | 57,928 | 41,517 | ||||||||
| Electricity generation expenses | 3,164 | 7,760 | 3,135 | ||||||||
| Transportation expenses | 1,694 | 2,173 | 2,343 | ||||||||
| Marketing expenses | 421 | 851 | 407 | ||||||||
| General and administrative expenses | 16,158 | 14,340 | 12,482 | ||||||||
| Depreciation, depletion and amortization | 23,654 | 24,585 | 21,859 | ||||||||
| Taxes, other than income taxes | 11,348 | 8,086 | 8,715 | ||||||||
| (Gains) losses on natural gas derivatives | 9,449 | (2,115 | ) | — | |||||||
| Other operating expenses | 3,119 | 1,245 | 123 | ||||||||
| Total expenses and other | 116,886 | 114,853 | 90,581 | ||||||||
| Other income (expenses): | |||||||||||
| Interest expense | (8,961 | ) | (8,805 | ) | (9,155 | ) | |||||
| Other, net | — | 154 | (239 | ) | |||||||
| Total other income (expenses) | (8,961 | ) | (8,651 | ) | (9,394 | ) | |||||
| Reorganization items, net | (26 | ) | (231 | ) | 456 | ||||||
| Income (loss) before income taxes | 44,193 | (47,196 | ) | (33,537 | ) | ||||||
| Income tax expense (benefit) | 12,221 | (13,098 | ) | (5,476 | ) | ||||||
| Net income (loss) | 31,972 | (34,098 | ) | (28,061 | ) | ||||||
| Series A preferred stock dividends | — | — | (5,650 | ) | |||||||
| Net income (loss) attributable to common stockholders | $ | 31,972 | $ | (34,098 | ) | $ | (33,711 | ) | |||
| Net income (loss) per share attributable to common stockholders | |||||||||||
| Basic | $ | 0.39 | $ | (0.42 | ) | $ | (0.94 | ) | |||
| Diluted | $ | 0.39 | $ | (0.42 | ) | $ | (0.94 | ) | |||
| Weighted-average common shares outstanding - basic | 81,519 | 81,765 | 35,873 | ||||||||
| Weighted-average common shares outstanding - diluted | 81,683 | 81,765 | 35,873 | ||||||||
| Adjusted net income (loss) | $ | 20,046 | $ | 24,264 | $ | 14,831 | |||||
| Adjusted EBITDA | $ | 62,756 | $ | 68,502 | $ | 50,018 | |||||
| Adjusted EBITDA unhedged | $ | 66,082 | $ | 53,598 | $ | 78,279 | |||||
| Levered free cash flow | $ | (12,560 | ) | $ | 526 | $ | (3,319 | ) | |||
| Levered free cash flow unhedged | $ | (9,234 | ) | $ | (14,378 | ) | $ | 24,942 | |||
| Adjusted general and administrative expenses | $ | 12,277 | $ | 11,587 | $ | 9,508 | |||||
| Effective Tax Rate | 28 | % | 28 | % | 16 | % | |||||
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| ($ in thousands) | |||||||||||
| Cash Flow Data: | |||||||||||
| Net cash provided by (used in) operating activities | $ | 71,362 | $ | 19,111 | $ | (77,394 | ) | ||||
| Net cash provided by (used in) investing activities | $ | (56,574 | ) | $ | (50,805 | ) | $ | (22,472 | ) | ||
| Net cash provided by (used in) financing activities | $ | (16,223 | ) | $ | (35,324 | ) | $ | 34,538 | |||
| June 30, 2019 | December 31, 2018 | ||||||
| ($ and shares in thousands) | |||||||
| Balance Sheet Data: | |||||||
| Total current assets | $ | 107,293 | $ | 229,022 | |||
| Total property, plant and equipment, net | $ | 1,526,004 | $ | 1,442,708 | |||
| Total current liabilities | $ | 134,519 | $ | 144,118 | |||
| Long-term debt | $ | 397,315 | $ | 391,786 | |||
| Total equity | $ | 952,316 | $ | 1,006,446 | |||
| Outstanding common stock shares as of | 80,973 | 81,202 | |||||
SUMMARY BY AREA
The following table shows a summary by area of our selected historical financial information and operating data for the periods indicated.
| California (San Joaquin and Ventura basins) | Rockies (Uinta and Piceance basins) | ||||||||||||||||||||||
| Three Months Ended | Three Months Ended | ||||||||||||||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | June 30, 2019 | March 31, 2019 | June 30, 2018 | ||||||||||||||||||
| ($ in thousands, except prices) | |||||||||||||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 120,917 | $ | 111,896 | $ | 117,288 | $ | 15,991 | $ | 19,206 | $ | 20,097 | |||||||||||
| Operating income(a) | $ | 47,809 | $ | 37,357 | $ | 60,014 | $ | 954 | $ | 4,779 | $ | 4,858 | |||||||||||
| Depreciation, depletion, and amortization (DD&A) | $ | 20,460 | $ | 21,342 | $ | 18,001 | $ | 3,194 | $ | 3,244 | $ | 3,140 | |||||||||||
| Average daily production (MBoe/d) | 20.8 | 21.0 | 18.8 | 6.6 | 6.8 | 7.7 | |||||||||||||||||
| Production (oil % of total) | 100 | % | 100 | % | 100 | % | 41 | % | 46 | % | 30 | % | |||||||||||
| Realized sales prices: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 63.91 | $ | 59.16 | $ | 68.72 | $ | 44.92 | $ | 41.38 | $ | 61.64 | |||||||||||
| NGLs (per Bbl) | $ | — | $ | — | $ | — | $ | 16.86 | $ | 24.42 | $ | 24.38 | |||||||||||
| Gas (per Mcf) | $ | — | $ | — | $ | — | $ | 2.16 | $ | 3.77 | $ | 2.12 | |||||||||||
| Capital expenditures | $ | 52,374 | $ | 42,509 | $ | 34,537 | $ | 1,443 | $ | 5,313 | $ | 3,735 | |||||||||||
__________
(a) Operating income comprises oil, natural gas and NGL sales, offset by operating expenses, general and administrative expenses, DD&A, and taxes, other than income taxes.
COMMODITY PRICING
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| Realized Sales Prices (weighted-average) | |||||||||||
| Oil without hedge ($/Bbl) | $ | 61.69 | $ | 56.88 | $ | 67.93 | |||||
| Effects of scheduled derivative settlements ($/Bbl) | $ | 0.13 | $ | 5.15 | $ | (14.71 | ) | ||||
| Oil with hedge ($/Bbl) | $ | 61.82 | $ | 62.03 | $ | 53.22 | |||||
| Natural gas ($/Mcf) | $ | 2.16 | $ | 3.83 | $ | 2.12 | |||||
| NGLs ($/Bbl) | $ | 16.86 | $ | 24.35 | $ | 24.38 | |||||
| Index Prices | |||||||||||
| Brent oil ($/Bbl) | $ | 68.47 | $ | 63.83 | $ | 74.97 | |||||
| WTI oil ($/Bbl) | $ | 59.86 | $ | 54.87 | $ | 67.85 | |||||
| Kern, Delivered natural gas ($/MMBtu)(a) | $ | 2.07 | $ | 5.03 | $ | 2.23 | |||||
__________
(a) Kern Delivered Index is the relevant index used for gas purchases in California.
CURRENT HEDGING SUMMARY
As of June 30, 2019, we had the following crude oil production and gas purchases hedges, with no changes through July 31, 2019.
| Q3 2019 | Q4 2019 | FY 2020 | |||||||||
| Sold Oil Call Options (Brent): | |||||||||||
| Hedged volume (MBbls) | 92 | 92 | — | ||||||||
| Weighted average price ($/Bbl) | $ | 81.00 | $ | 81.00 | $ | — | |||||
| Purchased Oil Put Options (Brent): | |||||||||||
| Hedged volume (MBbls) | 460 | 460 | — | ||||||||
| Weighted-average price ($/Bbl) | $ | 50.00 | $ | 50.00 | $ | — | |||||
| Fixed Price Oil Swaps (Brent): | |||||||||||
| Hedged volume (MBbls) | 1,472 | 1,380 | 4,392 | ||||||||
| Weighted average price ($/Bbl) | $ | 72.64 | $ | 72.21 | $ | 65.70 | |||||
| Fixed Price Oil Swaps (WTI): | |||||||||||
| Hedged volume (MBbls) | 92 | 92 | 121 | ||||||||
| Weighted average price ($/Bbl) | $ | 61.75 | $ | 61.75 | $ | 61.75 | |||||
| Oil basis differential positions (Brent-WTI basis swaps): | |||||||||||
| Hedged volume (MBbls) | 46 | 46 | — | ||||||||
| Weighted average price ($/Bbl) | $ | (1.29 | ) | $ | (1.29 | ) | $ | — | |||
| Fixed Price Gas Purchase Swaps (Kern, Delivered): | |||||||||||
| Hedged volume (MMBtu) | 4,600,000 | 4,295,000 | 13,725,000 | ||||||||
| Weighted average price ($/MMBtu) | $ | 2.91 | $ | 2.95 | $ | 2.98 | |||||
| Fixed Price Gas Purchase Swaps (SoCal Citygate): | |||||||||||
| Hedged volume (MMBtu) | 460,000 | 460,000 | 1,525,000 | ||||||||
| Weighted average price ($/MMBtu) | $ | 3.80 | $ | 3.80 | $ | 3.80 | |||||
OPERATING EXPENSES
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| ($ in thousands except per Boe amounts) | |||||||||||
| Lease operating expenses | $ | 47,879 | $ | 57,928 | $ | 41,517 | |||||
| Electricity generation expenses | 3,164 | 7,760 | 3,135 | ||||||||
| Electricity sales(a) | (5,364 | ) | (9,729 | ) | (5,971 | ) | |||||
| Transportation expenses | 1,694 | 2,173 | 2,343 | ||||||||
| Transportation sales(a) | (104 | ) | (117 | ) | (251 | ) | |||||
| Marketing expenses | 421 | 851 | 407 | ||||||||
| Marketing revenues(a) | (414 | ) | (830 | ) | (518 | ) | |||||
| Derivative settlements (received) paid for gas purchases(a) | 3,593 | (3,724 | ) | — | |||||||
| Total operating expenses(a) | $ | 50,869 | $ | 54,312 | $ | 40,662 | |||||
| Lease operating expenses ($/Boe) | $ | 19.18 | $ | 23.16 | $ | 17.24 | |||||
| Electricity generation expenses ($/Boe) | 1.27 | 3.10 | $ | 1.30 | |||||||
| Electricity sales ($/Boe) | (2.15 | ) | (3.89 | ) | $ | (2.48 | ) | ||||
| Transportation expenses ($/Boe) | 0.68 | 0.87 | $ | 0.97 | |||||||
| Transportation sales ($/Boe) | (0.04 | ) | (0.05 | ) | (0.09 | ) | |||||
| Marketing expenses ($/Boe) | 0.17 | 0.34 | $ | 0.17 | |||||||
| Marketing revenues ($/Boe) | (0.17 | ) | (0.33 | ) | $ | (0.22 | ) | ||||
| Derivative settlements (received) paid for gas purchases ($/Boe) | 1.44 | (1.49 | ) | — | |||||||
| Total operating expenses ($/Boe) | $ | 20.38 | $ | 21.71 | $ | 16.89 | |||||
| Total MBoe | 2,497 | 2,501 | 2,408 | ||||||||
__________
(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
| Three Months Ended | |||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||
| Net Oil, Natural Gas and NGLs Production Per Day(a): | |||||
| Oil (MBbl/d) | |||||
| California | 20.8 | 21.0 | 18.8 | ||
| Rockies | 2.7 | 3.1 | 2.3 | ||
| East Texas(c) | — | — | — | ||
| Total oil | 23.5 | 24.1 | 21.1 | ||
| Natural gas (MMcf/d) | |||||
| California | — | — | — | ||
| Rockies | 20.8 | 19.5 | 23.2 | ||
| East Texas(c) | — | — | 4.8 | ||
| Total natural gas | 20.8 | 19.5 | 28.0 | ||
| NGLs (MBbl/d) | |||||
| California | — | — | — | ||
| Rockies | 0.4 | 0.4 | 0.7 | ||
| East Texas(c) | — | — | — | ||
| Total NGLs | 0.4 | 0.4 | 0.7 | ||
| Total Production (MBoe/d)(b) | 27.4 | 27.8 | 26.5 | ||
__________
(a) Production represents volumes sold during the period.
(b) Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the three months ended June 30, 2019, the average prices of Brent oil and Henry Hub natural gas were $68.47 per Bbl and $2.57 per MMBtu, respectively, resulting in an oil-to-gas ratio of approximately 4 to 1 on an energy equivalent basis.
(c) On November 30, 2018, we sold our non-core gas-producing properties and related assets located in the East Texas basin.
CAPITAL EXPENDITURES (ACCRUAL BASIS)
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| (in thousands) | |||||||||||
| Capital expenditures (accrual basis) | $ | 56,645 | $ | 49,099 | $ | 38,531 | |||||
NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS
Adjusted EBITDA 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, Adjusted Net Income (Loss) and Levered Free Cash Flow are supplemental non-GAAP financial measures used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies.
We define Adjusted EBITDA as earnings before interest expense; income taxes; depreciation, depletion, and amortization; derivative gains or losses net of cash received or paid for scheduled derivative settlements; impairments; stock compensation expense; and other unusual, out-of-period and infrequent items, including restructuring costs and reorganization items. We define Levered Free Cash Flow as Adjusted EBITDA less capital expenditures, interest expense and dividends.
Our management believes Adjusted EBITDA provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and the investment community. The measure also allows our management to more effectively evaluate our operating performance and compare the results between periods without regard to our financing methods or capital structure. Levered Free Cash Flow is used by management as a primary metric to plan capital allocation 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.
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) 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 costs and reorganization items and the income tax expense or benefit of these adjustments using our effective tax rate.
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 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 restructuring and other non-recurring costs and non-cash stock compensation expense. 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. 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 General and Administrative Expenses may not be comparable to other similarly titled measures of other companies.
ADJUSTED NET INCOME (LOSS)
The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted Net Income (Loss).
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| ($ thousands, except per share amounts) | |||||||||||
| Net income (loss) | $ | 31,972 | $ | (34,098 | ) | $ | (28,061 | ) | |||
| Add (Subtract): | |||||||||||
| (Gains) losses on oil and natural gas derivatives | (17,827 | ) | 63,124 | 78,143 | |||||||
| Net cash received (paid) for scheduled derivative settlements | (3,326 | ) | 14,904 | (28,261 | ) | ||||||
| Other operating expenses | 3,119 | 1,245 | 123 | ||||||||
| Restructuring and other non-recurring costs | 1,513 | 1,329 | 1,714 | ||||||||
| Reorganization items, net | 26 | 231 | (456 | ) | |||||||
| Total additions, net | (16,495 | ) | 80,833 | 51,263 | |||||||
| Income tax (expense) benefit of adjustments at effective tax rate | 4,569 | (22,471 | ) | (8,371 | ) | ||||||
| Adjusted net income (loss) | $ | 20,046 | $ | 24,264 | $ | 14,831 | |||||
| Basic EPS on adjusted income | $ | 0.25 | $ | 0.30 | $ | 0.41 | |||||
| Diluted EPS on adjusted net income | $ | 0.25 | $ | 0.30 | $ | 0.20 | |||||
| Weighted average shares outstanding - basic | 81,519 | 81,765 | 35,873 | ||||||||
| Weighted average shares outstanding - diluted | 81,683 | 81,973 | 73,588 | ||||||||
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) by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Adjusted EBITDA Unhedged.
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| ($ thousands) | |||||||||||
| Net income (loss) | $ | 31,972 | $ | (34,098 | ) | $ | (28,061 | ) | |||
| Add (Subtract): | |||||||||||
| Interest expense | 8,961 | 8,805 | 9,155 | ||||||||
| Income tax expense (benefit) | 12,221 | (13,098 | ) | (5,476 | ) | ||||||
| Depreciation, depletion and amortization | 23,654 | 24,585 | 21,859 | ||||||||
| Derivative (gain) loss | (17,827 | ) | 63,124 | 78,143 | |||||||
| Net cash received (paid) for scheduled derivative settlements | (3,326 | ) | 14,904 | (28,261 | ) | ||||||
| Other operating expense | 3,119 | 1,245 | 123 | ||||||||
| Stock compensation expense | 2,443 | 1,475 | 1,278 | ||||||||
| Restructuring and other non-recurring costs | 1,513 | 1,329 | 1,714 | ||||||||
| Reorganization items, net | 26 | 231 | (456 | ) | |||||||
| Adjusted EBITDA | $ | 62,756 | $ | 68,502 | $ | 50,018 | |||||
| Net cash (received) paid for scheduled derivative settlements | 3,326 | (14,904 | ) | 28,261 | |||||||
| Adjusted EBITDA unhedged | $ | 66,082 | $ | 53,598 | $ | 78,279 | |||||
| Net cash provided (used) by operating activities(1) | 71,362 | 19,111 | (77,394 | ) | |||||||
| Add (Subtract): | |||||||||||
| Cash interest payments | 1,272 | 14,000 | 644 | ||||||||
| Cash reorganization item (receipts) payments | — | — | 1,047 | ||||||||
| Restructuring and other non-recurring costs | 1,513 | 1,329 | 1,714 | ||||||||
| Derivative early termination payment | — | — | 126,949 | ||||||||
| Other changes in operating assets and liabilities | (11,391 | ) | 34,063 | (2,942 | ) | ||||||
| Adjusted EBITDA | $ | 62,756 | $ | 68,502 | $ | 50,018 | |||||
| Net cash (received) paid for scheduled derivative settlements | 3,326 | (14,904 | ) | 28,261 | |||||||
| Adjusted EBITDA unhedged | $ | 66,082 | $ | 53,598 | $ | 78,279 | |||||
__________
(1) The three months ended March 31, 2019 included $37 million of annual or semi-annual payments that occur in the first quarter each year such as semi-annual interest and certain annual royalty payments and other accrued liabilities.
LEVERED FREE CASH FLOW
The following table presents a reconciliation of Adjusted EBITDA to the non–GAAP measures of Levered free cash flow. The reconciliation of Adjusted EBITDA is presented above.
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| ($ thousands) | |||||||||||
| Adjusted EBITDA | $ | 62,756 | $ | 68,502 | $ | 50,018 | |||||
| Subtract: | |||||||||||
| Capital expenditures - accrual basis | (56,645 | ) | (49,099 | ) | (38,531 | ) | |||||
| Interest expense | (8,961 | ) | (8,805 | ) | (9,155 | ) | |||||
| Cash dividends declared | (9,710 | ) | (10,072 | ) | (5,651 | ) | |||||
| Levered free cash flow | $ | (12,560 | ) | $ | 526 | $ | (3,319 | ) | |||
| Net cash (received) paid for scheduled derivative settlements | 3,326 | (14,904 | ) | 28,261 | |||||||
| Levered free cash flow unhedged | $ | (9,234 | ) | $ | (14,378 | ) | $ | 24,942 | |||
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES
The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measures of Adjusted general and administrative expenses.
| Three Months Ended | |||||||||||
| June 30, 2019 | March 31, 2019 | June 30, 2018 | |||||||||
| ($ in thousands except per MBoe amounts) | |||||||||||
| General and administrative expenses | $ | 16,158 | $ | 14,340 | $ | 12,482 | |||||
| Subtract: | |||||||||||
| Restructuring and other non-recurring costs | (1,513 | ) | (1,329 | ) | (1,714 | ) | |||||
| Non-cash stock compensation expense (G&A portion) | (2,368 | ) | (1,424 | ) | (1,260 | ) | |||||
| Adjusted general and administrative expenses | $ | 12,277 | $ | 11,587 | $ | 9,508 | |||||
| General and administrative expenses ($/MBoe) | $ | 6.47 | $ | 5.73 | $ | 5.18 | |||||
| Subtract: | |||||||||||
| Restructuring and other non-recurring costs ($/MBoe) | (0.61 | ) | (0.53 | ) | (0.71 | ) | |||||
| Non-cash stock compensation expense ($/MBoe) | (0.95 | ) | (0.57 | ) | (0.52 | ) | |||||
| Adjusted general and administrative expenses ($/MBoe) | $ | 4.92 | $ | 4.63 | $ | 3.95 | |||||
| Total MBoe | 2,497 | 2,501 | 2,408 | ||||||||
Contact: Berry Petroleum Corporation Todd Crabtree - Manager, Investor Relations (661) 616-3811 ir@bry.com