DALLAS, May 08, 2019 (GLOBE NEWSWIRE) -- Berry Petroleum Corporation (NASDAQ: BRY) (“Berry” or the “Company”) today reported a net loss of $34 million or $0.42 per diluted share and adjusted net income of $24 million or $0.30 per diluted share for the first quarter of 2019. In addition, the Board approved a regular $0.12 per share dividend for the second quarter of 2019.

Highlights for the Quarter

• Adjusted EBITDA of $69 million and Unhedged Adjusted EBITDA of $54 million
• 2.2 million shares repurchased; 2.6 million cumulative for $28 million or $10.69/share
• California oil price realizations of 93% of Brent pricing or $59.16/Bbl before hedging
• Capital Expenditures of $49 million with approximately 87% directed to California oil development
• Drilled 96 wells in the quarter, on track for approximately 400 wells to be drilled in 2019
• Full-year production and spending are on track

Trem Smith, Berry board chair, chief executive officer and president stated, “Berry continues to execute its 2019 development plan in line with our expectations, as our full-year production and spending are on track.  California is a unique energy market compared to the rest of the United States as it is a Brent-based and natural gas short market.  Being Brent-based is a big advantage for Berry but, as a natural gas consumer, the lack of natural gas storage can cause wide fluctuations in pricing.  We saw that impact in our first quarter as the western United States was cool and wet increasing the demand for natural gas and, as a result, increasing pricing and negatively impacting our results for the quarter.  However, these prices are incorporated in our annual guidance which is not changing.  In addition, to better manage the largest portion of our operating expenses (OpEx), energy costs, and provide better visibility into our simple financial model we have now hedged the majority of our gas needs for the next 18 months."

First Quarter Results

For the first quarter, Berry reported Adjusted EBITDA of $69 million, down $13 million from $82 million in the fourth quarter of 2018. Relative to the fourth quarter, the first quarter had lower oil prices, which were partially protected by our oil hedge, flat production and substantially higher fuel gas costs which impacted our OpEx. Adjusted EBITDA, on an unhedged basis, was $54 million in the first quarter compared to $73 million in the fourth quarter, impacted primarily by lower oil prices.

California oil prices before hedges for the first quarter averaged $59.16/Bbl which were 6% lower than the $62.65/Bbl realized in the fourth quarter. Realized oil prices for the Company before hedges of $56.88/Bbl were 8% lower than the fourth quarter average of $61.48.

For the first quarter, Operating Expenses ("OpEx") totaled $54 million or $21.71/Boe compared to $48 million or $18.77/Boe in the fourth quarter. The price of natural gas we purchased for our steam operations was unseasonably high in the first quarter, nearly $5 million higher than the prior quarter.  On a comparative basis, our first quarter OpEx was also negatively impacted from selling our East Texas natural gas assets in November, which had a lower cost on a per BOE basis compared to our other operations. 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 $14.3 million for the first quarter compared to $16.1 million for the fourth quarter of 2018. The improvement was due in large part to the fact that the fourth quarter was impacted by higher stock compensation associated with performance shares meeting target thresholds. Non-recurring restructuring and other costs continued to decline in the first quarter. Adjusted general and administrative expenses were $11.6 million or $4.63/Boe for the first quarter compared to $11.5 million or $4.49/Boe for the fourth quarter.

Taxes, other than income taxes were $8.1 million, or $3.23/Boe for the first quarter, compared to $7.8 million or $3.04/Boe in the fourth quarter.

Capital expenditures totaled $49 million for the first quarter compared to $53 million for the fourth quarter, in both periods largely focused on drilling in California.

Adjusted net income was $24 million for the first quarter compared to $35 million for the fourth quarter of 2018. The decrease was due to the same factors affecting Adjusted EBITDA, namely lower oil prices and higher fuel gas costs, as well as corporate tax rates which increased slightly from 23% in the fourth quarter of 2018 to 28% in the first quarter of 2019.

In April 2019, we completed our semi-annual RBL borrowing base redetermination, which was affirmed at $750 million.  We elected to keep our lenders’ commitment at $400 million.   At April 30 we had no borrowings, and availability of $391 million due to $9 million of outstanding letters of credit.  Our liquidity was $395 million including a cash balance of $4 million.

Dividend Announcement

On May 8, 2019 the Board declared a regular dividend for the second quarter at a rate of $0.12 per share on the Company’s outstanding common stock. This is the Company's fourth regular quarterly dividend, and the Company, subject to approval by the Board, intends to pay a similar dividend in future quarters.

The second quarter dividend is payable on July 15, 2019 to shareholders of record at the close of business on June 14, 2019.

Earnings Conference Call

The Company will host a conference call May 9, 2019 to discuss these results:

Live Call Date:	Thursday, May 9, 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:	5569905

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, May 23, 2019
Replay Dial-in:	855-859-2056 from the U.S.
	404-537-3406 from international locations
Replay Passcode:	5569905

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.

Contact

Contact: Berry Petroleum Corporation
Todd Crabtree - Manager, Investor Relations
(661) 616-3811
ir@bry.com 

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
	March 31, 2019				December 31, 2018				March 31, 2018
	($ and shares in thousands, except per share amounts)
Statement of Operations Data:
Revenues and other:
Oil, natural gas and natural gas liquids sales	$	131,102			$	142,861			$	125,624
Electricity sales	9,729				9,517				5,453
Gains (losses) on oil derivatives	(65,239		)		127,160				(34,644		)
Marketing revenues	830				534				785
Other revenues	117				274				66
Total revenues and other	76,539				280,346				97,284
Expenses and other:
Lease operating expenses	57,928				51,308				44,303
Electricity generation expenses	7,760				6,764				4,590
Transportation expenses	2,173				2,220				2,978
Marketing expenses	851				716				580
General and administrative expenses	14,340				16,130				11,985
Depreciation, depletion and amortization	24,585				24,253				18,429
Taxes, other than income taxes	8,086				7,829				8,256
(Gains) losses on natural gas derivatives	(2,115		)		(4,477		)		—
(Gains) losses on sale of assets and other, net	1,245				(3,269		)		—
Total expenses and other	114,853				101,474				91,121
Other income (expenses):
Interest expense	(8,805		)		(8,820		)		(7,796		)
Other, net	154				108				27
Total other income (expenses)	(8,651		)		(8,712		)		(7,769		)
Reorganization items, net	(231		)		1,498				8,955
Income (loss) before income taxes	(47,196		)		171,658				7,349
Income tax expense (benefit)	(13,098		)		39,890				939
Net income (loss)	(34,098		)		131,768				6,410
Series A preferred stock dividends	—				—				(5,650		)
Net income (loss) attributable to common stockholders	$	(34,098	)		$	131,768			$	760
Net income (loss) per share attributable to common stockholders
Basic	$	(0.42	)		$	1.56			$	0.02
Diluted	$	(0.42	)		$	1.56			$	0.02
Weighted-average common shares outstanding - basic	81,765				84,367				38,602
Weighted-average common shares outstanding - diluted	81,765				84,592				38,827
Adjusted net income (loss)	$	24,264			$	34,809			$	15,034
Adjusted EBITDA	$	68,502			$	81,669			$	44,503
Adjusted EBITDA unhedged	$	53,598			$	72,990			$	62,352
Levered free cash flow	$	526			$	9,531			$	15,325
Levered free cash flow unhedged	$	(14,378	)		$	852			$	33,174
Adjusted general and administrative expenses	$	11,587			$	11,533			$	8,919
Effective Tax Rate	28		%		23		%		13		%
	Three Months Ended
	March 31, 2019				December 31, 2018				March 31, 2018
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities	$	19,111			$	95,767			$	27,592
Net cash provided by (used in) investing activities	$	(50,805	)		$	(36,694	)		$	(19,876	)
Net cash provided by (used in) financing activities	$	(35,324	)		$	(14,306	)		$	12,185

 

	March 31, 2019				December 31, 2018
	($ and shares in thousands)
Balance Sheet Data:
Total current assets	$	97,802			$	229,022
Total property, plant and equipment, net	$	1,469,127			$	1,442,708
Total current liabilities	$	114,630			$	144,118
Long-term debt	$	391,947			$	391,786
Total equity	$	939,129			$	1,006,446
Outstanding common stock shares as of	81,879				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
	March 31, 2019				March 31, 2018				March 31, 2019				March 31, 2018
($ in thousands, except prices)
Oil, natural gas and natural gas liquids sales	$	111,896			$	105,544			$	19,206			$	18,715
Operating income(a)	$	37,357			$	47,258			$	4,779			$	3,445
Depreciation, depletion, and amortization (DD&A)	$	21,342			$	14,905			$	3,244			$	3,031
Average daily production (MBoe/d)	21.0				18.8				6.8				6.6
Production (oil% of total)	100		%		100		%		46		%		35		%
Realized sales prices:
Oil (per Bbl)	$	59.16			$	62.37			$	41.38			$	60.29
NGLs (per Bbl)	$	—			$	—			$	24.42			$	26.46
Gas (per Mcf)	$	—			$	—			$	3.77			$	2.58
Capital expenditures	$	42,509			$	15,301			$	5,313			$	378

__________

(a)    Operating income includes 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
	March 31, 2019				December 31, 2018				March 31, 2018
Realized Sales Prices (weighted-average)
Oil without hedge ($/Bbl)	$	56.88			$	61.48			$	62.14
Effects of scheduled derivative settlements ($/Bbl)	$	5.15			$	2.88			$	(9.40	)
Oil with hedge ($/Bbl)	$	62.03			$	64.36			$	52.74
Natural gas ($/Mcf)	$	3.83			$	3.86			$	2.64
NGLs ($/Bbl)	$	24.35			$	20.39			$	25.56
Index Prices
Brent oil ($/Bbl)	$	63.83			$	68.08			$	67.16
WTI oil ($/Bbl)	$	54.87			$	58.81			$	62.87
Henry Hub natural gas ($/MMBtu)	$	2.92			$	3.64			$	3.00

 

 CURRENT HEDGING SUMMARY

As of April 30, 2019, our positions were as follows:

	Q2 2019				Q3 2019				Q4 2019				FY 2020
Oil Calls Options (Brent):
Hedged volume (MBbls)	180				92				92				—
Weighted average price ($/Bbl)	$	70.00			$	81.00			$	81.00			$	—
Oil Put Options (Brent):
Hedged volume (MBbls)	1,092				460				460				—
Weighted-average price ($/Bbl)	$	60.00			$	50.00			$	50.00			$	—
Fixed Price Oil Swaps (Brent)
Hedged volume (MBbls)	881				1,380				1,380				2,928
Weighted average price ($/Bbl)	$	73.86			$	72.70			$	72.21			$	67.66
Fixed Price Oil Swaps (WTI):
Hedged volume (MBbls)	61				92				92				121
Weighted average price ($/Bbl)	$	61.75			$	61.75			$	61.75			$	61.75
Oil basis differential positions (Brent-WTI basis swaps):
Hedged volume (MBbls)	46				46				46				—
Weighted average price ($/Bbl)	$	(1.29	)		$	(1.29	)		$	(1.29	)		$	—
Fixed Price Gas Purchase Swaps (Kern, Delivered):
Hedged volume (MMBtu)	4,255,000				4,600,000				3,685,000				10,675,000
Weighted average price ($/MMBtu)	$	2.81			$	2.91			$	2.97			$	3.01
Fixed Price Gas Purchase Swaps (SoCal Citygate):
Hedged volume (MMBtu)	305,000				460,000				460,000				2,290,000
Weighted average price ($/MMBtu)	$	3.80			$	3.80			$	3.80			$	3.80

 

OPERATING EXPENSES

	Three Months Ended
	March 31, 2019				December 31, 2018				March 31, 2018
	($ in thousands except per Boe amounts)
Lease operating expenses	$	57,928			$	51,308			$	44,303
Electricity generation expenses	7,760				6,764				4,590
Electricity sales(a)	(9,729		)		(9,517		)		(5,453		)
Transportation expenses	2,173				2,220				2,978
Transportation sales(a)	(117		)		(274		)		(66		)
Marketing expenses	851				716				580
Marketing revenues(a)	(830		)		(534		)		(785		)
Derivative settlements (received) paid for gas purchases(a)	(3,724		)		(2,407		)		—
Total operating expenses(a)	$	54,312			$	48,276			$	46,147
Lease operating expenses ($/Boe)	$	23.16			$	19.96			$	18.80
Electricity generation expenses ($/Boe)	3.10				2.63				$	1.94
Electricity sales ($/Boe)	(3.89		)		(3.70		)		$	(2.31	)
Transportation expenses ($/Boe)	0.87				0.86				$	1.26
Transportation sales ($/Boe)	(0.05		)		(0.11		)		—
Marketing expenses ($/Boe)	0.34				0.28				$	0.25
Marketing revenues ($/Boe)	(0.33		)		(0.21		)		$	(0.33	)
Derivative settlements (received) paid for gas purchases ($/Boe)	(1.49		)		(0.94		)		—
Total operating expenses ($/Boe)	$	21.71			$	18.77			$	19.61
Total MBoe	2,501				2,571				2,356

__________

(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
	March 31, 2019			December 31, 2018			March 31, 2018
Net Oil, Natural Gas and NGLs Production Per Day(a):
Oil (MBbl/d)
California	21.0			21.7			18.8
Rockies	3.1			2.0			2.3
East Texas(c)	—			—			—
Total oil	24.1			23.7			21.1
Natural gas (MMcf/d)
California	—			—			—
Rockies	19.5			19.3			22.7
East Texas(c)	—			2.8			4.9
Total natural gas	19.5			22.1			27.6
NGLs (MBbl/d)
California	—			—			—
Rockies	0.4			0.6			0.5
East Texas(c)	—			—			—
Total NGLs	0.4			0.6			0.5
Total Production (MBoe/d)(b)	27.8			28.0			26.2

__________

(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 quarter ended March 31, 2019, the average prices of Brent oil and Henry Hub natural gas were $63.83 per Bbl and $2.92 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
	March 31, 2019				December 31, 2018				March 31, 2018
	(in thousands)
Capital expenditures (accrual basis)	$	49,099			$	53,326			$	15,732

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 non-recurring restructuring and other costs and non-cash stock compensation expense. Management believes Adjusted General and Administrative Expenses is useful because it allows us to more effectively 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
	March 31, 2019				December 31, 2018				March 31, 2018
	($ thousands, except per share amounts)
Net income (loss)	$	(34,098	)		$	131,768			$	6,410
Add (Subtract):
(Gains) losses on oil and natural gas derivatives	63,124				(131,637		)		34,644
Net cash received (paid) for scheduled derivative settlements	14,904				8,679				(17,849		)
(Gains) losses on sale of assets and other, net	1,245				(3,269		)		—
Non-recurring restructuring and other costs	1,329				1,414				2,047
Reorganization items, net	231				(1,498		)		(8,955		)
Total additions, net	80,833				(126,311		)		9,887
Income tax (expense) benefit of adjustments at effective tax rate	(22,471		)		29,352				(1,263		)
Adjusted net income (loss)	$	24,264			$	34,809			$	15,034
Basic EPS on adjusted income	$	0.30			$	0.41			$	0.39
Diluted EPS on adjusted net income	$	0.30			$	0.41			$	0.20
Weighted average shares outstanding - basic	81,765				84,367				38,602
Weighted average shares outstanding - diluted	81,973				84,592				74,672

 

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
	March 31, 2019				December 31, 2018				March 31, 2018
	($ thousands)
Net income (loss)	$	(34,098	)		$	131,768			$	6,410
Add (Subtract):
Interest expense	8,805				8,820				7,796
Income tax expense (benefit)	(13,098		)		39,890				939
Depreciation, depletion and amortization	24,585				24,253				18,429
Derivative (gain) loss	63,124				(131,637		)		34,644
Net cash received (paid) for scheduled derivative settlements	14,904				8,679				(17,849		)
(Gain) loss on sale of assets and other	1,245				(3,269		)		—
Stock compensation expense	1,475				3,249				1,042
Non-recurring restructuring and other costs	1,329				1,414				2,047
Reorganization items, net	231				(1,498		)		(8,955		)
Adjusted EBITDA	$	68,502			$	81,669			$	44,503
Net cash (received) paid for scheduled derivative settlements	(14,904		)		(8,679		)		17,849
Adjusted EBITDA unhedged	$	53,598			$	72,990			$	62,352
Net cash provided (used) by operating activities(1)	19,111				95,767				27,592
Add (Subtract):
Cash interest payments	14,000				562				2,654
Cash income tax payments	—				(1,901		)		—
Cash reorganization item (receipts) payments	—				(174		)		468
Non-recurring restructuring and other costs	1,329				1,414				2,047
Other changes in operating assets and liabilities	34,063				(13,998		)		11,742
Adjusted EBITDA	$	68,502			$	81,669			$	44,503
Net cash (received) paid for scheduled derivative settlements	(14,904		)		(8,679		)		17,849
Adjusted EBITDA unhedged	$	53,598			$	72,990			$	62,352

__________

(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
	March 31, 2019				December 31, 2018				March 31, 2018
	($ thousands)
Adjusted EBITDA	$	68,502			$	81,669			$	44,503
Subtract:
Capital expenditures - accrual basis	(49,099		)		(53,326		)		(15,732		)
Interest expense	(8,805		)		(8,820		)		(7,796		)
Cash dividends declared	(10,072		)		(9,992		)		(5,650		)
Levered free cash flow	$	526			$	9,531			$	15,325
Net cash (received) paid for scheduled derivative settlements	(14,904		)		(8,679		)		17,849
Levered free cash flow unhedged	$	(14,378	)		$	852			$	33,174

 

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
	March 31, 2019				December 31, 2018				March 31, 2018
	($ in thousands except per MBoe amounts)
General and administrative expenses	$	14,340			$	16,130			$	11,985
Subtract:
Non-recurring restructuring and other costs	(1,329		)		(1,414		)		(2,047		)
Non-cash stock compensation expense	(1,424		)		(3,183		)		(1,019		)
Adjusted general and administrative expenses	$	11,587			$	11,533			$	8,919
General and administrative expenses ($/MBoe)	$	5.73			$	6.27			$	5.09
Subtract:
Non-recurring restructuring and other costs ($/MBoe)	(0.53		)		(0.55		)		(0.87		)
Non-cash stock compensation expense ($/MBoe)	(0.57		)		(1.24		)		(0.43		)
Adjusted general and administrative expenses ($/MBoe)	$	4.63			$	4.49			$	3.79
Total MBoe	2,501				2,571				2,356