DALLAS, Nov. 07, 2019 (GLOBE NEWSWIRE) -- Berry Corporation (NASDAQ: BRY) (“Berry” or the “Company”) today reported net income of $53 million or $0.65 per diluted share and adjusted net income of $33 million or $0.40 per diluted share for the third quarter of 2019. In addition, the Board approved a fourth quarter dividend of $0.12 per share, as it has done each quarter since becoming a public company in 2018.
Highlights for the Quarter
- Adjusted EBITDA of $84 million and Unhedged Adjusted EBITDA of $69 million
- Third quarter production of 29,600 BOE/D up 7.7% compared to second quarter
- Third quarter production mix 87% oil with September improving to 88% oil
- Capital Expenditures of $63 million with fourth quarter expected to be $35-$40 million
- Added to 2019 and 2020 oil hedges; more than 60% oil production covered for Q4 2019 and more than 50% for 2020
- Full-year production and spending are on track for mid-point of guidance
“It is clear from Berry’s strong third quarter production that our California oil assets respond to investment and the capital deployed during the first half of the year is now driving value. We expect Berry’s production for the year will be at the mid-point of our guidance, while spending will come in just under the mid-point of guidance,” stated Trem Smith, Berry Board Chair, Chief Executive Officer and President. “Since becoming a public company in 2018, we have grown production and consistently paid a substantial dividend within levered free cash flow. Our focus continues to be on responsible production while creating value for our shareholders through a combination of growth and return of capital. This year we expect to see double-digit production growth at about 12% company-wide, provide an attractive dividend yield, and buy back 4% of our stock. We are well positioned to continue this strategy in 2020 as we are well hedged for the remainder of 2019 and throughout 2020. In short, Berry is in a strong position to continue to create and deliver top-tier value in the market.”
Third Quarter Results
Adjusted EBITDA, on a hedged basis, increased to $84 million in the third quarter from $63 million in the second quarter. Results include the impact of higher production, lower oil prices, higher oil hedge settlements received and lower gas hedge settlement payments. Adjusted EBITDA, on an unhedged basis, was $69 million in the third quarter compared to $66 million in the second quarter.
Average daily production was 8% higher in the third quarter compared to the second quarter driven by our development capital spending in 2019. Our California production of 23.0 MBoe/d for the third quarter of 2019 was up 10% compared to the second quarter of 2019.
California oil prices before hedges for the third quarter averaged 95% of Brent, or $59.00/Bbl which were 8% lower than the $63.91/Bbl in the second quarter. The Company realized oil prices before hedges of $57.92/Bbl which was 6% lower than the second quarter average of $61.69/Bbl.
For the third quarter on an unhedged basis, Operating Expenses ("OpEx") decreased to $18.13 per Boe for the third quarter 2019 compared to $18.94 for the second quarter 2019. The decrease includes a net $0.47 per Boe benefit from higher seasonal electricity sales and a $0.44 per Boe reduction in lease operating expense.
Additionally, operating expenses, including hedge effects, decreased to $18.90 per Boe in the third quarter 2019 from $20.38 in the second quarter due to these same factors and a $0.67 per Boe decrease in gas hedge settlement payments.
OpEx consists of lease operating expenses ("LOE"), third-party revenues and expenses from electricity generation, transportation and marketing activities, as well as the effect of derivative settlements (received or paid) for gas purchases, and excludes taxes other than income taxes.
General and administrative expenses were $6.04 per Boe for the third quarter compared to $6.47 per Boe for the second quarter. Adjusted general and administrative expenses were $5.13 per Boe for the third quarter compared to $4.92 per Boe for the second quarter primarily due to insurance renewals and continued development and growth of our Corporate Affairs department and its activities.
“We have been building our capabilities and expertise in our Corporate Affairs department to support our participation in the regulatory, political and legislative processes primarily in California. Initial achievements are an outcome of the team’s ongoing efforts to partner with the state to responsibly deliver affordable energy to its citizens and become less reliant on foreign energy sources. As a result of this initiative, as well as our continuing efforts to improve our internal systems and comply with public company requirements, our full year adjusted G&A will be on the high side of guidance. A major focus in 2020 will be on reducing overall general and administrative expenses on a per Boe basis,” said Cary Baetz, Chief Financial Officer, Executive Vice President and Board Director.
Taxes, other than income taxes were $3.40 per Boe for the third quarter compared to $4.54 per Boe in the second quarter, due to lower market rates for greenhouse gas allowance requirements.
Capital expenditures totaled $63 million for the third quarter compared to $57 million for the second quarter and was largely focused on California drilling, as well as equipping and hydraulic stimulation of previously drilled wells.
Net income for the third quarter 2019 was $53 million compared to $32 million in the second quarter. This difference was largely driven by increased production and derivative gains that offset lower oil prices. Adjusted net income was $33 million for the third quarter, representing a 63% increase over the second quarter of 2019. The increase was generally attributable to the same factors impacting Adjusted EBITDA.
At September 30, 2019, funds available under our $400 million reserve-based revolver were $381 million with $9 million of outstanding letters of credit and borrowings of $10 million on our revolver in order to fund monthly working capital fluctuations and asset retirement payments during the third quarter. The Company expects to have little to no revolver borrowings by year-end.
“We are very pleased that our projected production for 2019 will be at the mid-point of our guidance, especially when taking into account that capital spending is expected to come in below the mid-point of the range. While our operating costs continue to improve, we expect operating expenses to be at the higher side of guidance for the year due to the unseasonably high gas prices experienced in the first quarter,” stated Baetz.
Dividend Announcement
On November 6, 2019 the Board declared a regular dividend for the fourth quarter at a rate of $0.12 per share on the Company’s outstanding common stock. This is the Company's sixth regular quarterly dividend, and the Company intends to pay a similar dividend in future quarters, subject to Board approval.
The fourth quarter dividend is payable on January 15, 2019 to shareholders of record at the close of business on December 13, 2019.
Earnings Conference Call
The Company will host a conference call November 7, 2019 to discuss these results:
| Live Call Date: | Thursday, November 7, 2019 |
| Live Call Time: | 5:00 p.m. Eastern Time (2 p.m. Pacific Time) |
| Live Call Dial-in: | 877-491-5169 from the U.S. |
| 720-405-2254 from international locations | |
| Live Call Passcode: | 2845519 |
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, November 21, 2019 |
| Replay Dial-in: | 855-859-2056 from the U.S. |
| 404-537-3406 from international locations | |
| Replay Passcode: | 2845519 |
A replay of the audio webcast will also be archived on the “Investors” section of Berry’s website at bry.com/investors. In addition, an investor presentation will be available on the Company’s website.
About Berry Petroleum
Berry 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.bry.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 and electricity;
- 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;
- catastrophic events; 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 | |||||||||||
| September 30, 2019 | June 30, 2019 | September 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 | $ | 141,250 | $ | 136,908 | $ | 147,004 | |||||
| Electricity sales | 7,460 | 5,364 | 14,268 | ||||||||
| Gains (losses) on oil derivatives | 45,509 | 27,276 | (18,994 | ) | |||||||
| Marketing revenues | 413 | 414 | 486 | ||||||||
| Other revenues | 40 | 104 | 183 | ||||||||
| Total revenues and other | 194,672 | 170,066 | 142,947 | ||||||||
| Expenses and other: | |||||||||||
| Lease operating expenses | 50,957 | 47,879 | 51,649 | ||||||||
| Electricity generation expenses | 3,781 | 3,164 | 6,130 | ||||||||
| Transportation expenses | 2,067 | 1,694 | 2,318 | ||||||||
| Marketing expenses | 398 | 421 | 437 | ||||||||
| General and administrative expenses | 16,434 | 16,158 | 13,429 | ||||||||
| Depreciation, depletion and amortization | 27,664 | 23,654 | 21,729 | ||||||||
| Taxes, other than income taxes | 9,249 | 11,348 | 8,317 | ||||||||
| Losses (gains) on natural gas derivatives | 3,008 | 9,449 | (1,879 | ) | |||||||
| Other operating (income) expenses | (550 | ) | 3,119 | 400 | |||||||
| Total expenses and other | 113,008 | 116,886 | 102,530 | ||||||||
| Other income (expenses): | |||||||||||
| Interest expense | (8,597 | ) | (8,961 | ) | (9,877 | ) | |||||
| Other, net | (77 | ) | — | 347 | |||||||
| Total other expenses | (8,674 | ) | (8,961 | ) | (9,530 | ) | |||||
| Reorganization items, net | (170 | ) | (26 | ) | 13,781 | ||||||
| Income before income taxes | 72,820 | 44,193 | 44,668 | ||||||||
| Income tax expense | 20,171 | 12,221 | 7,683 | ||||||||
| Net income | 52,649 | 31,972 | 36,985 | ||||||||
| Series A preferred stock dividends | — | — | (86,642 | ) | |||||||
| Net income (loss) attributable to common stockholders | $ | 52,649 | $ | 31,972 | $ | (49,657 | ) | ||||
| Net income (loss) per share attributable to common stockholders | |||||||||||
| Basic | $ | 0.65 | $ | 0.39 | $ | (0.70 | ) | ||||
| Diluted | $ | 0.65 | $ | 0.39 | $ | (0.70 | ) | ||||
| Weighted-average common shares outstanding - basic | 80,982 | 81,519 | 70,940 | ||||||||
| Weighted-average common shares outstanding - diluted | 81,051 | 81,683 | 70,940 | ||||||||
| Adjusted net income | $ | 32,760 | $ | 20,046 | $ | 40,529 | |||||
| Adjusted EBITDA | $ | 83,931 | $ | 62,756 | $ | 81,736 | |||||
| Adjusted EBITDA unhedged | $ | 68,778 | $ | 66,082 | $ | 82,788 | |||||
| Levered free cash flow | $ | 2,126 | $ | (12,560 | ) | $ | 24,185 | ||||
| Levered free cash flow unhedged | $ | (13,027 | ) | $ | (9,234 | ) | $ | 25,237 | |||
| Adjusted general and administrative expenses | $ | 13,940 | $ | 12,277 | $ | 10,706 | |||||
| Effective Tax Rate | 28 | % | 28 | % | 17 | % | |||||
| Three Months Ended | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| ($ in thousands) | |||||||||||
| Cash Flow Data: | |||||||||||
| Net cash provided by operating activities | $ | 65,320 | $ | 71,362 | $ | 56,880 | |||||
| Net cash used in investing activities | $ | (60,285 | ) | $ | (56,574 | ) | $ | (40,028 | ) | ||
| Net cash used in financing activities | $ | (5,262 | ) | $ | (16,223 | ) | $ | (16,250 | ) | ||
| September 30, 2019 | December 31, 2018 | ||||||
| ($ and shares in thousands) | |||||||
| Balance Sheet Data: | |||||||
| Total current assets | $ | 130,037 | $ | 229,022 | |||
| Total property, plant and equipment, net | $ | 1,607,810 | $ | 1,442,708 | |||
| Total current liabilities | $ | 148,894 | $ | 144,118 | |||
| Long-term debt | $ | 402,290 | $ | 391,786 | |||
| Total equity | $ | 997,344 | $ | 1,006,446 | |||
| Outstanding common stock shares as of | 80,997 | 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 | ||||||||||||||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | September 30, 2019 | June 30, 2019 | September 30, 2018 | ||||||||||||||||||
| ($ in thousands, except prices) | |||||||||||||||||||||||
| Oil, natural gas and natural gas liquids sales | $ | 124,540 | $ | 120,917 | $ | 124,007 | $ | 16,711 | $ | 15,991 | $ | 22,998 | |||||||||||
| Operating income(a) | $ | 49,185 | $ | 47,809 | $ | 62,791 | $ | 1,241 | $ | 954 | $ | 7,176 | |||||||||||
| Depreciation, depletion, and amortization (DD&A) | $ | 24,360 | $ | 20,460 | $ | 17,908 | $ | 3,303 | $ | 3,194 | $ | 3,268 | |||||||||||
| Average daily production (MBoe/d) | 23.0 | 20.8 | 19.5 | 6.6 | 6.6 | 7.9 | |||||||||||||||||
| Production (oil % of total) | 100 | % | 100 | % | 100 | % | 41 | % | 41 | % | 35 | % | |||||||||||
| Realized sales prices: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 59.00 | $ | 63.91 | $ | 69.13 | $ | 48.82 | $ | 44.92 | $ | 57.45 | |||||||||||
| NGLs (per Bbl) | $ | — | $ | — | $ | — | $ | 12.10 | $ | 16.86 | $ | 37.75 | |||||||||||
| Gas (per Mcf) | $ | — | $ | — | $ | — | $ | 2.12 | $ | 2.16 | $ | 2.55 | |||||||||||
| Capital expenditures(b) | $ | 59,076 | $ | 52,374 | $ | 35,124 | $ | 2,064 | $ | 1,443 | $ | 2,624 | |||||||||||
__________
(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.
(b) Excludes corporate capital expenditures.
COMMODITY PRICING
| Three Months Ended | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| Realized Sales Prices (weighted-average) | |||||||||||
| Oil without hedge ($/Bbl) | $ | 57.92 | $ | 61.69 | $ | 67.67 | |||||
| Effects of scheduled derivative settlements ($/Bbl) | $ | 7.31 | $ | 0.13 | $ | (0.44 | ) | ||||
| Oil with hedge ($/Bbl) | $ | 65.23 | $ | 61.82 | $ | 67.23 | |||||
| Natural gas ($/Mcf) | $ | 2.12 | $ | 2.16 | $ | 2.55 | |||||
| NGLs ($/Bbl) | $ | 12.10 | $ | 16.86 | $ | 37.75 | |||||
| Index Prices | |||||||||||
| Brent oil ($/Bbl) | $ | 62.03 | $ | 68.47 | $ | 75.84 | |||||
| WTI oil ($/Bbl) | $ | 56.33 | $ | 59.86 | $ | 69.60 | |||||
| Kern, Delivered natural gas ($/MMBtu)(a) | $ | 2.50 | $ | 2.07 | $ | 4.12 | |||||
__________
(a) Kern, Delivered Index is the relevant index used for gas purchases in California.
CURRENT HEDGING SUMMARY
As of September 30, 2019, we had the following crude oil production and gas purchases hedges, with no changes through October 31, 2019.
| Q4 2019 | FY 2020 | FY 2021 | |||||||||
| Fixed Price Oil Swaps (Brent): | |||||||||||
| Hedged volume (MBbls) | 1,656 | 5,856 | 730 | ||||||||
| Weighted average price ($/Bbl) | $ | 70.20 | $ | 64.25 | $ | 58.50 | |||||
| Fixed Price Oil Swaps (WTI): | |||||||||||
| Hedged volume (MBbls) | 92 | 121 | — | ||||||||
| Weighted average price ($/Bbl) | $ | 61.75 | $ | 61.75 | $ | — | |||||
| Oil basis differential swaps (Brent-WTI basis swaps): | |||||||||||
| Hedged volume (MBbls) | 46 | — | — | ||||||||
| Weighted average price ($/Bbl) | $ | (1.29 | ) | $ | — | $ | — | ||||
| Sold Oil Call Options (Brent): | |||||||||||
| Hedged volume (MBbls) | 92 | — | — | ||||||||
| Weighted average price ($/Bbl) | $ | 81.00 | $ | — | $ | — | |||||
| Fixed Price Gas Purchase Swaps (Kern, Delivered): | |||||||||||
| Hedged volume (MMBtu) | 4,905,000 | 17,385,000 | 900,000 | ||||||||
| Weighted average price ($/MMBtu) | $ | 2.90 | $ | 2.88 | $ | 2.50 | |||||
| Fixed Price Gas Purchase Swaps (SoCal Citygate): | |||||||||||
| Hedged volume (MMBtu) | 460,000 | 1,525,000 | — | ||||||||
| Weighted average price ($/MMBtu) | $ | 3.80 | $ | 3.80 | $ | — | |||||
OPERATING EXPENSES
| Three Months Ended | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| ($ in thousands except per Boe amounts) | |||||||||||
| Lease operating expenses | $ | 50,957 | $ | 47,879 | $ | 51,649 | |||||
| Electricity generation expenses | 3,781 | 3,164 | 6,130 | ||||||||
| Electricity sales(a) | (7,460 | ) | (5,364 | ) | (14,268 | ) | |||||
| Transportation expenses | 2,067 | 1,694 | 2,318 | ||||||||
| Transportation sales(a) | (40 | ) | (104 | ) | (183 | ) | |||||
| Marketing expenses | 398 | 421 | 437 | ||||||||
| Marketing revenues(a) | (413 | ) | (414 | ) | (486 | ) | |||||
| Derivative settlements paid for gas purchases(a) | 2,088 | 3,593 | — | ||||||||
| Total operating expenses(a) | $ | 51,378 | $ | 50,869 | $ | 45,597 | |||||
| Lease operating expenses ($/Boe) | $ | 18.74 | $ | 19.18 | $ | 20.50 | |||||
| Electricity generation expenses ($/Boe) | 1.39 | 1.27 | 2.43 | ||||||||
| Electricity sales ($/Boe) | (2.74 | ) | (2.15 | ) | (5.66 | ) | |||||
| Transportation expenses ($/Boe) | 0.76 | 0.68 | 0.92 | ||||||||
| Transportation sales ($/Boe) | (0.01 | ) | (0.04 | ) | (0.07 | ) | |||||
| Marketing expenses ($/Boe) | 0.15 | 0.17 | 0.17 | ||||||||
| Marketing revenues ($/Boe) | (0.15 | ) | (0.17 | ) | (0.19 | ) | |||||
| Derivative settlements paid for gas purchases ($/Boe) | 0.77 | 1.44 | — | ||||||||
| Total operating expenses ($/Boe) | $ | 18.90 | $ | 20.38 | $ | 18.10 | |||||
| Total unhedged operating expenses ($/Boe)(b) | $ | 18.13 | $ | 18.94 | $ | 18.10 | |||||
| Total MBoe | 2,719 | 2,497 | 2,520 | ||||||||
__________
(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.
(b) Total unhedged operating expenses equals total operating expenses less the derivatives settlements paid for gas purchases.
PRODUCTION STATISTICS
| Three Months Ended | |||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||
| Net Oil, Natural Gas and NGLs Production Per Day(a): | |||||
| Oil (MBbl/d) | |||||
| California | 23.0 | 20.8 | 19.5 | ||
| Rockies | 2.7 | 2.7 | 2.8 | ||
| East Texas(c) | — | — | — | ||
| Total oil | 25.7 | 23.5 | 22.3 | ||
| Natural gas (MMcf/d) | |||||
| California | — | — | — | ||
| Rockies | 20.9 | 20.8 | 23.1 | ||
| East Texas(c) | — | — | 4.1 | ||
| Total natural gas | 20.9 | 20.8 | 27.4 | ||
| NGLs (MBbl/d) | |||||
| California | — | — | — | ||
| Rockies | 0.4 | 0.4 | 0.5 | ||
| East Texas(c) | — | — | — | ||
| Total NGLs | 0.4 | 0.4 | 0.5 | ||
| Total Production (MBoe/d)(b) | 29.6 | 27.4 | 27.4 | ||
__________
(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 September 30, 2019, the average prices of Brent oil and Henry Hub natural gas were $62.03 per Bbl and $2.38 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 | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| (in thousands) | |||||||||||
| Capital expenditures (accrual basis) | $ | 63,488 | $ | 56,645 | $ | 40,243 | |||||
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 | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| ($ thousands, except per share amounts) | |||||||||||
| Net income | $ | 52,649 | $ | 31,972 | $ | 36,985 | |||||
| Add (Subtract): | |||||||||||
| (Gains) losses on oil and natural gas derivatives | (42,501 | ) | (17,827 | ) | 17,115 | ||||||
| Net cash received (paid) for scheduled derivative settlements | 15,153 | (3,326 | ) | (1,052 | ) | ||||||
| Other operating (income) expenses | (550 | ) | 3,119 | 400 | |||||||
| Restructuring and other non-recurring costs | 219 | 1,513 | 1,598 | ||||||||
| Reorganization items, net | 170 | 26 | (13,781 | ) | |||||||
| Total (subtractions) additions, net | (27,509 | ) | (16,495 | ) | 4,280 | ||||||
| Income tax benefit (expense) of adjustments at effective tax rate | 7,620 | 4,569 | (736 | ) | |||||||
| Adjusted net income | $ | 32,760 | $ | 20,046 | $ | 40,529 | |||||
| Basic EPS on adjusted income | $ | 0.40 | $ | 0.25 | $ | 0.57 | |||||
| Diluted EPS on adjusted net income | $ | 0.40 | $ | 0.25 | $ | 0.48 | |||||
| Weighted average shares outstanding - basic | 80,982 | 81,519 | 70,940 | ||||||||
| Weighted average shares outstanding - diluted | 81,051 | 81,683 | 84,487 | ||||||||
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 | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| ($ thousands) | |||||||||||
| Net income | $ | 52,649 | $ | 31,972 | $ | 36,985 | |||||
| Add (Subtract): | |||||||||||
| Interest expense | 8,597 | 8,961 | 9,877 | ||||||||
| Income tax expense | 20,171 | 12,221 | 7,683 | ||||||||
| Depreciation, depletion and amortization | 27,664 | 23,654 | 21,729 | ||||||||
| Derivative (gain) loss | (42,501 | ) | (17,827 | ) | 17,115 | ||||||
| Net cash received (paid) for scheduled derivative settlements | 15,153 | (3,326 | ) | (1,052 | ) | ||||||
| Other operating (income) expense | (550 | ) | 3,119 | 400 | |||||||
| Stock compensation expense | 2,360 | 2,443 | 1,182 | ||||||||
| Restructuring and other non-recurring costs | 219 | 1,513 | 1,598 | ||||||||
| Reorganization items, net | 170 | 26 | (13,781 | ) | |||||||
| Adjusted EBITDA | $ | 83,931 | $ | 62,756 | $ | 81,736 | |||||
| Net cash (received) paid for scheduled derivative settlements | (15,153 | ) | 3,326 | 1,052 | |||||||
| Adjusted EBITDA unhedged | $ | 68,778 | $ | 66,082 | $ | 82,788 | |||||
| Net cash provided by operating activities | $ | 65,320 | $ | 71,362 | $ | 56,880 | |||||
| Add (Subtract): | |||||||||||
| Cash interest payments | 14,864 | 1,272 | 15,902 | ||||||||
| Cash reorganization item receipts | — | — | (345 | ) | |||||||
| Restructuring and other non-recurring costs | 219 | 1,513 | 1,598 | ||||||||
| Other changes in operating assets and liabilities | 3,528 | (11,391 | ) | 7,701 | |||||||
| Adjusted EBITDA | $ | 83,931 | $ | 62,756 | $ | 81,736 | |||||
| Net cash (received) paid for scheduled derivative settlements | (15,153 | ) | 3,326 | 1,052 | |||||||
| Adjusted EBITDA unhedged | $ | 68,778 | $ | 66,082 | $ | 82,788 | |||||
LEVERED FREE CASH FLOW
The following table presents a reconciliation of Adjusted EBITDA to the non–GAAP measures of Levered free cash flow. The reconciliation of Adjusted EBITDA is presented above.
| Three Months Ended | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| ($ thousands) | |||||||||||
| Adjusted EBITDA | $ | 83,931 | $ | 62,756 | $ | 81,736 | |||||
| Subtract: | |||||||||||
| Capital expenditures - accrual basis | (63,488 | ) | (56,645 | ) | (40,243 | ) | |||||
| Interest expense | (8,597 | ) | (8,961 | ) | (9,877 | ) | |||||
| Cash dividends declared | (9,720 | ) | (9,710 | ) | (7,431 | ) | |||||
| Levered free cash flow | $ | 2,126 | $ | (12,560 | ) | $ | 24,185 | ||||
| Net cash (received) paid for scheduled derivative settlements | (15,153 | ) | 3,326 | 1,052 | |||||||
| Levered free cash flow unhedged | $ | (13,027 | ) | $ | (9,234 | ) | $ | 25,237 | |||
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES
The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses to the non-GAAP financial measures of Adjusted general and administrative expenses.
| Three Months Ended | |||||||||||
| September 30, 2019 | June 30, 2019 | September 30, 2018 | |||||||||
| ($ in thousands except per MBoe amounts) | |||||||||||
| General and administrative expenses | $ | 16,434 | $ | 16,158 | $ | 13,429 | |||||
| Subtract: | |||||||||||
| Restructuring and other non-recurring costs | (219 | ) | (1,513 | ) | (1,598 | ) | |||||
| Non-cash stock compensation expense (G&A portion) | (2,275 | ) | (2,368 | ) | (1,125 | ) | |||||
| Adjusted general and administrative expenses | $ | 13,940 | $ | 12,277 | $ | 10,706 | |||||
| General and administrative expenses ($/MBoe) | $ | 6.04 | $ | 6.47 | $ | 5.33 | |||||
| Subtract: | |||||||||||
| Restructuring and other non-recurring costs ($/MBoe) | (0.08 | ) | (0.61 | ) | (0.63 | ) | |||||
| Non-cash stock compensation expense ($/MBoe) | (0.84 | ) | (0.95 | ) | (0.45 | ) | |||||
| Adjusted general and administrative expenses ($/MBoe) | $ | 5.13 | $ | 4.92 | $ | 4.25 | |||||
| Total MBoe | 2,719 | 2,497 | 2,520 | ||||||||