Bonanza Creek Energy Announces Second Quarter 2018 Financial Results and Operational Update

DENVER, Aug. 08, 2018 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE: BCEI) (the "Company" or "Bonanza Creek") today announced its second quarter 2018 financial results and operating outlook and has posted an updated investor presentation on its corporate website.

Bonanza Creek delivered solid performance in the second quarter driven by strong production growth and lower capital spend. The Company is on track to grow Wattenberg production by approximately 25% year-over-year and 50% when comparing the fourth quarter of 2018 to the fourth quarter of 2017.

• Second quarter sales volumes averaged 18.0 MBoe per day including the negative effects of a prior-period adjustment of 0.6 Mboe per day related to non-operated wells
  
  
• Rapidly improving well performance yields over 1,000 economic drilling locations in Wattenberg
  
  
• Full year 2018 Wattenberg production guidance raised while lowering full year capex guidance
  
  
• Accretive Mid-Continent divestiture of $117 million⁽¹⁾ bolsters balance sheet, improves unit operating costs and focuses operations on highest returning opportunities
  
  
• Well head pressures effectively managed via Rocky Mountain Infrastructure's ("RMI") multiple third-party gas processing optionality
  
  
• Second quarter GAAP net income of $4.9 million, or $0.24 per diluted share; Adjusted net income⁽¹⁾ of $24.2 million, or $1.18 per diluted share
  
  
•  Adjusted EBITDAX⁽²⁾ of $34.8 million, 17% growth over first quarter 2018

⁽¹⁾ Effective date of February 1, 2018

⁽²⁾ Non-GAAP measures, see attached reconciliation schedules at the end of this release.

"Bonanza Creek delivered a solid quarter, marked by consistently improving operational and financial performance. We continue to be encouraged by the strong well performance across our Wattenberg position. Through a combination of improving well productivity from more recent completion designs, and attention to our base, we are able to raise our full year 2018 production guidance while lowering our full-year capex," said Eric Greager, President and CEO.

"As we look further into this year and next, we expect to see strong production growth, improving unit costs and increased operating cash flow as we accelerate our pace of development. Our balance sheet remains strong. We are well-funded to execute on our capital plan which provides for approximately 25% Rockies production growth in 2018 and greater than 50% growth in 2019."

Second Quarter 2018 Results

During the second quarter of 2018, the Company reported average daily sales of 18.0 MBoe per day, which was at the low end of the Company's guidance range of 18.0 – 18.6 MBoe per day. Otherwise strong production during the quarter was impacted by a negative adjustment of 0.6 MBoe per day related to our interest in several months of production from two outside-operated pads. If not for this adjustment, second quarter production would have been at the high-end of guidance. The Company's second quarter reported sales increased 7% sequentially as we continue to see strong well performance from the recent completion designs and consistently low wellhead gathering pressures on the Company's RMI system. As a result of these factors, we are raising our full-year production guidance, pro-forma for the Mid-Continent divestiture, as detailed below. Product mix for the second quarter of 2018 was 58% oil, 20% NGLs, and 22% residue natural gas.

Net revenue for the second quarter of 2018 was $71.9 million, compared to $44.1 million for the second quarter of 2017. The increase in second quarter 2018 net revenue compared to 2017 was primarily a result of increased production and improved commodity pricing.  Crude oil accounted for approximately 85% of total revenue. Differentials for the Company's Wattenberg oil production during the quarter averaged approximately $6.39 per barrel off of NYMEX WTI. Corporate average realized prices for the second quarter of 2018 are presented below.

Average Realized Prices (Before Derivatives)
	Three Months Ended June 30, 2018
Oil (per Bbl)	$63.67
Gas (per Mcf)	$2.13
NGL (per Bbl)	$19.05
Boe (Per Boe)	$43.57

Lease operating expenses ("LOE") for the second quarter of 2018 were $11.3 million, compared to $9.4 million in the second quarter of 2017.  LOE on a unit basis for the second quarter of 2018 increased by 6.6% to $6.90 per Boe from $6.47 per Boe in the second quarter of 2017. Gas plant and midstream expenses for the second quarter of 2018 were $3.2 million, compared to $2.6 million in the second quarter of 2017. On a unit basis, gas plant and midstream expenses increased 10% to $1.98 per Boe for the second quarter of 2018 from $1.80 per Boe in the second quarter of 2017. Unit operating costs were impacted by decisions to pull forward certain planned activities and to pursue high-returning maintenance opportunities. They were also impacted by some cost inflation and environmental compliance costs required by the air emissions consent order in the Wattenberg Field. The Company’s accelerated compressor replacement program is now largely complete and will continue to ensure Bonanza Creek’s product flows while helping to reduce future operating costs. Additional spending on the company’s base optimization efforts (e.g. pipeline pigging and well servicing) have helped improve base production volumes. Cost pressures due to a busier operating environment and air emissions compliance costs are expected to continue through 2018 and are reflected in our revised LOE, gas plant and midstream expense guidance.

Below is a breakout of the Company's regional operating expenses for the second quarter of 2018.

	Three Months Ended June 30, 2018
	Wattenberg								Mid-Continent								Total Company
	($M)				($/Boe)				($M)				($/Boe)				($M)				($/Boe)
Lease operating expense	$	8,247			$	6.01			$	3,069			$	11.45			$	11,316			$	6.90
Gas plant and midstream operating expense	$	2,181			$	1.59			$	1,066			$	3.98			$	3,247			$	1.98
Total	$	10,428			$	7.60			$	4,135			$	15.43			$	14,563			$	8.88

The Company's general and administrative ("G&A") expense was $9.9 million for the second quarter of 2018, which includes $2.2 million in stock compensation. This represents a 48% decrease from the second quarter of 2017. Cash G&A expense, which excludes stock compensation, was $7.7 million for the quarter and is tracking at the low-end of the Company's full year 2018 guidance.

Reported net income for the second quarter of 2018 was $4.9 million, or $0.24 per diluted share. Adjusted net income for the second quarter of 2018 was $24.2 million, or $1.18 per diluted share.

Adjusted EBITDAX for the second quarter of 2018 was $34.8 million.

Cash G&A, Adjusted net income, and Adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures.

The table below summarizes the Company's annual results as compared to previously provided guidance.

Guidance vs Actual Summary
	2Q18 Guidance		2Q18 Actual
Production (MBoe/d)	18.0 - 18.6		18.0
	Annual Guidance		YTD Actual
Lease operating expense ($/Boe)	$5.00 - $6.00		$6.92
Gas plant and midstream operating expense ($/Boe)	$1.40 - $1.80		$2.18
Cash G&A ($MM)*	$33 - $35		$16
Production taxes (% of pre-derivative realization)	7% - 8%		8%
CAPEX ($MM)	$280 - $320		$95
* Cash G&A guidance is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. Please refer to the non-GAAP disclosure at the end of this release for information regarding cash G&A.

Production, Capital, and Expense Outlook

The Company is updating its 2018 annual guidance to account for strong well performance in the Wattenberg and the sale of the Mid-Continent operations on August 6, 2018.  Third quarter 2018 production and operating expense guidance is also being provided for the full company and pro-forma for the sale of the Mid-Continent operations. Below is a table summarizing the Company's production, capital, and expense guidance for the remainder of 2018.

Guidance Summary
	Three Months Ended September 30, 2018 (Pro-forma)(1)	Three Months Ended September 30, 2018		Twelve Months Ended December 31, 2018
Production (MBoe/d)	16.6 - 17.2	17.4 - 18.0		17.4 - 18.0
LOE ($/Boe)	$4.40 - $4.80	$4.75 - $5.15		$5.50 - $5.90
Midstream expense ($/Boe)	$1.25 - $1.45	$1.45 - $1.65		$1.70 - $1.90
Recurring cash G&A* ($MM)				$32.5 - $33.5
Production taxes (% of pre-derivative realization)				7% - 8%
Total CAPEX ($MM)				$275 - $295
* Recurring Cash G&A is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A.
(1) Pro-forma is the Company estimate for the third quarter of 2018 excluding results from the Mid-Continent operations.

Operational Highlights

During the second quarter of 2018, the Company spud 12 gross (8.1 net) operated wells, ten of which were extended reach lateral ("XRL") wells, and completed 11 gross (11.0 net) operated wells, six of which were XRL wells.

The Company continues to be encouraged by its eight-well F26 pad on its western legacy acreage. These eight standard reach lateral ("SRL") wells have average cumulative production of 18.3 MBoe per 1,000 feet of lateral after 178 days of production. Additionally, the Company has finished completing and turned to production all eight XRL wells in the French Lake area. While two of the wells are currently hindered by mechanical issues, the Company is very pleased with the early results of the remaining six XRLs with results meeting or exceeding expectations.

The Company has provided updated production results for these wells in its August Investor Presentation, which is available on the Company's website.

The Company continued to benefit from multiple delivery points on the RMI system in the second quarter, including the Sterling interconnect which came online in the fourth quarter 2017. This delivery point flexibility, combined with consistent low line pressures on RMI, helped ensure minimal production curtailments. The Company entered into a new agreement with Cureton Front Range LLC (“Cureton”) whereby Cureton will gather and process gas from the Company’s northern acreage.  In addition to gathering and processing services, the new agreement provides flow assurance by adding 15 MMcf per day of firm gas processing capacity for up to twenty-five years. The Company also secured three years of downstream residue transportation from Cureton in order to support upcoming production needs. This improves the Company’s flexibility to manage system pressures across its Wattenberg position and provides the backbone infrastructure system to allow development of the northern acreage.

Upon completing the 2018 resource assessment and as a result of rapidly improving well performance, the Company has identified over 1,000 economic SRL equivalent locations in its Wattenberg position.

Financial Highlights

As of the end of the second quarter, the Company had liquidity of $153.7 million, which included cash on hand of $22.0 million and $131.7 million of borrowing capacity under its credit facility.  Pro forma for the Mid-Continent divestiture which closed on August 6, 2018, the Company had $256.6 million in liquidity.  The balance sheet strength and Wattenberg inventory provide the company with a strong position from which to deliver disciplined, return-oriented growth.

Commodity Derivative Position

The Company's current hedge position is summarized in the table below and reflects additional hedges the Company entered into through August 8, 2018. Subsequent to quarter-end, the Company entered into natural gas basis swaps between NYMEX Henry Hub price and the Colorado Interstate Gas (CIG) Rockies Natural Gas price, the index on which the majority of the Company's natural gas is sold.

		Crude Oil (NYMEX WTI)					Natural Gas (NYMEX Henry Hub)			Natural Gas (NYMEX Henry Hub)
		Bbls/day		Weighted Avg. Price per Bbl			MMBtu/day		Weighted Avg. Price per MMBTU	MMBtu/day		Weighted Avg. Basis Differential to NYMEX Henry Hub Price per MMBtu
3Q18
Cashless Collar		2,000		$43.00/$53.50			13,600		$2.75/$3.32	—		—
Swap		5,000		$57.87			—		—	—		—
Basis Swap		—		—			—		—	8,354		$0.67
4Q18
Cashless Collar		2,000		$43.00/$53.50			12,600		$2.75/$3.35	—		—
Swap		5,000		$58.07			—		—	—		—
Basis Swap		—		—			—		—	12,600		$0.67
1Q19
Cashless Collar		2,000		$43.00/$54.53			7,600		$2.75/$3.22	—		—
Swap		5,000		$59.33			—		—	—		—
Basis Swap		—		—			—		—	7,600		$0.67
2Q19
Cashless Collar		3,330		$51.81/$64.23			2,505		$2.75/$3.22	—		—
Swap		4,500		$58.32			—		—	—		—
3Q19
Swap		3,000		$55.00			—		—	—		—
4Q19
Swap		3,000		$55.00			—		—	—		—

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on August 9, 2018 at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Time). A webcast of the live event, as well as a replay, will be available on the Investor Relations section of the Company’s website at www.bonanzacrk.com. Dial-in information for the conference call is included below.

Type	Phone Number	Passcode
Live Participant	877-793-4362	3289067
Replay	855-859-2056	3289067

About Bonanza Creek Energy, Inc.

Bonanza Creek Energy, Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company’s assets and operations are concentrated in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations. The Company’s common shares are listed for trading on the NYSE under the symbol: “BCEI.” For more information about the Company, please visit www.bonanzacrk.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include statements regarding development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company's reorganization; and updated 2018 guidance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2017, filed on March 15, 2018, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

For further information, please contact:
Doug Atkinson
Senior Manager, Investor Relations
720-225-6690
datkinson@bonanzacrk.com

Schedule 1: Statements of Operations
(in thousands, expect for per share amounts, unaudited)
	Successor									Predecessor
	Three Months Ended June 30, 2018				April 29, 2017 through June 30, 2017					April 1, 2017 through April 28, 2017
Operating net revenues:
Oil and gas sales	$	71,872			$	28,114				$	16,030
Operating expenses:
Lease operating expense	11,316				6,153					3,203
Gas plant and midstream operating expense	3,247				1,762					836
Gathering, transportation and processing	1,660				—					—
Severance and ad valorem taxes	6,071				2,408					1,352
Exploration	221				359					292
Depreciation, depletion and amortization	9,564				4,836					6,853
Abandonment and impairment of unproved properties(1)	2,477				—					—
General and administrative (including $2,184, $7,949 and $391, respectively, of stock-based compensation)	9,917				16,139					2,998
Total operating expenses	44,473				31,657					15,534
Income (loss) from operations	27,399				(3,543		)			496
Other income (expense):
Derivative loss	(22,012		)		—					—
Interest expense	(805		)		(195		)			(1,088		)
Reorganization items, net	—				—					97,811
Other income (expense)	277				158					(283		)
Total other income (expense)	(22,540		)		(37		)			96,440
Income (loss) from operations before taxes	4,859				(3,580		)			96,936
Income tax benefit (expense)	—				—					—
Net income (loss)	$	4,859			$	(3,580	)			$	96,936
Comprehensive income (loss)	$	4,859			$	(3,580	)			$	96,936
Basic net income (loss) per common share	$	0.24			$	(0.18	)			$	1.88
Diluted net income (loss) per common share	$	0.24			$	(0.18	)			$	1.85
Basic weighted-average common shares outstanding	20,488				20,369					49,902
Diluted weighted-average common shares outstanding	20,603				20,369					50,486

Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
(1) The Company incurred impairment charges relating to the standard amortization of unproved properties within the Wattenberg Field during the Current Successor quarter.   

	Successor									Predecessor
	Six Months Ended June 30, 2018				April 29, 2017 through June 30, 2017					January 1, 2017 through April 28, 2017
Operating net revenues:
Oil and gas sales	$	136,064			$	28,114				$	68,589
Operating expenses:
Lease operating expense	21,775				6,153					13,128
Gas plant and midstream operating expense	6,860				1,762					3,541
Gathering, transportation and processing	3,998				—					—
Severance and ad valorem taxes	11,303				2,408					5,671
Exploration	250				359					3,699
Depreciation, depletion and amortization	17,072				4,836					28,065
Abandonment and impairment of unproved properties(1)	4,979				—					—
Unused commitments	21				—					993
General and administrative (including $3,192, $7,949 and $2,116, respectively, of stock-based compensation)	19,451				16,139					15,092
Total operating expenses	85,709				31,657					70,189
Income (loss) from operations	50,355				(3,543		)			(1,600		)
Other income (expense):
Derivative loss	(30,754		)		—					—
Interest expense	(1,162		)		(195		)			(5,656		)
Reorganization items, net	—				—					8,808
Other income	290				158					1,108
Total other income (expense)	(31,626		)		(37		)			4,260
Income (loss) from operations before taxes	18,729				(3,580		)			2,660
Income tax benefit (expense)	—				—					—
Net income (loss)	$	18,729			$	(3,580	)			$	2,660
Comprehensive income (loss)	$	18,729			$	(3,580	)			$	2,660
Basic net income (loss) per common share	$	0.91			$	(0.18	)			$	0.05
Diluted net income (loss) per common share	$	0.91			$	(0.18	)			$	0.05
Basic weighted-average common shares outstanding	20,471				20,369					49,559
Diluted weighted-average common shares outstanding	20,538				20,369					50,971

Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
(1) The Company incurred impairment charges relating to non-core leases expiring and the standard amortization of unproved properties within the Wattenberg Field during the Current Successor Period.

Schedule 2: Statements of Cash Flows
(in thousands, unaudited)
	Successor				Successor					Predecessor
	Three Months Ended June 30, 2018				April 29, 2017 through June 30, 2017					April 1, 2017 through April 28, 2017
Cash flows from operating activities:
Net income (loss)	$	4,859			$	(3,580	)			$	96,936
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	9,564				4,836					6,853
Non-cash reorganization items	—				—					(101,501		)
Abandonment and impairment of unproved properties	2,477				—					—
Well abandonment costs and dry hole expense	—				64					230
Stock-based compensation	2,184				7,949					391
Amortization of deferred financing costs and debt premium	—				—					374
Derivative loss	22,012				—					—
Derivative cash settlements	(7,310		)		—					—
Other	—				5					(365		)
Changes in current assets and liabilities:
Accounts receivable	(4,618		)		6,420					(2,826		)
Prepaid expenses and other assets	(2,467		)		270					1,499
Accounts payable and accrued liabilities	(323		)		(19,338		)			(36,972		)
Settlement of asset retirement obligations	(132		)		(459		)			(155		)
Net cash provided by (used in) operating activities	26,246				(3,833		)			(35,536		)
Cash flows from investing activities:
Acquisition of oil and gas properties	(1,197		)		(4,982		)			(6		)
Exploration and development of oil and gas properties	(53,818		)		(4,913		)			(1,698		)
Proceeds from sale of oil and gas properties	—				—					—
Additions to property and equipment - non oil and gas	(177		)		(161		)			(253		)
Net cash used in investing activities	(55,192		)		(10,056		)			(1,957		)
Cash flows from financing activities:
Proceeds from credit facility	45,000				—					—
Payments to credit facility	—				—					(191,667		)
Proceeds from sale of common stock	—				—					207,500
Proceeds from exercise of stock options	968				—					—
Payment of employee tax withholdings in exchange for the return of common stock	(794		)		(2,080		)			(92		)
Net cash provided by (used in) financing activities	45,174				(2,080		)			15,741
Net change in cash, cash equivalents and restricted cash	16,228				(15,969		)			(21,752		)
Cash, cash equivalents and restricted cash:
Beginning of period	5,840				68,406					90,158
End of period	$	22,068			$	52,437				$	68,406

	Successor									Predecessor
	Six Months Ended June 30, 2018				April 29, 2017 through June 30, 2017					January 1, 2017 through April 28, 2017
Cash flows from operating activities:
Net income (loss)	$	18,729			$	(3,580	)			$	2,660
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	17,072				4,836					28,065
Non-cash reorganization items	—				—					(44,160		)
Abandonment and impairment of unproved properties	4,979				—					—
Well abandonment costs and dry hole expense	—				64					2,931
Stock-based compensation	3,192				7,949					2,116
Amortization of deferred financing costs and debt premium	—				—					374
Derivative loss	30,754				—					—
Derivative cash settlements	(11,622		)		—					—
Other	172				5					18
Changes in current assets and liabilities:
Accounts receivable	(20,376		)		6,420					(6,640		)
Prepaid expenses and other assets	935				270					963
Accounts payable and accrued liabilities	(889		)		(19,338		)			(5,880		)
Settlement of asset retirement obligations	(797		)		(459		)			(331		)
Net cash provided by (used in) operating activities	42,149				(3,833		)			(19,884		)
Cash flows from investing activities:
Acquisition of oil and gas properties	(1,295		)		(4,982		)			(445		)
Exploration and development of oil and gas properties	(91,482		)		(4,913		)			(5,123		)
Proceeds from sale of oil and gas properties	20				—					—
Additions to property and equipment - non oil and gas	(280		)		(161		)			(454		)
Net cash used in investing activities	(93,037		)		(10,056		)			(6,022		)
Cash flows from financing activities:
Proceeds from credit facility	60,000				—					—
Payments to credit facility	—				—					(191,667		)
Proceeds from sale of common stock	—				—					207,500
Proceeds from exercise of stock options	968				—					—
Payment of employee tax withholdings in exchange for the return of common stock	(794		)		(2,080		)			(427		)
Net cash provided by (used in) financing activities	60,174				(2,080		)			15,406
Net change in cash, cash equivalents and restricted cash	9,286				(15,969		)			(10,500		)
Cash, cash equivalents and restricted cash:
Beginning of period	12,782				68,406					78,906
End of period	$	22,068			$	52,437				$	68,406

Schedule 3: Condensed Consolidated Balance Sheets
	Successor
	June 30, 2018				December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	21,989			$	12,711
Accounts receivable:
Oil and gas sales	38,830				28,549
Joint interest and other	13,926				3,831
Prepaid expenses and other	5,620				6,555
Inventory of oilfield equipment	1,434				1,019
Derivative assets	39				488
Total current assets	81,838				53,153
Property and equipment (successful efforts method):
Proved properties	552,858				555,341
Less: accumulated depreciation, depletion and amortization	(29,703		)		(17,032		)
Total proved properties, net	523,155				538,309
Unproved properties	179,735				183,843
Wells in progress	52,747				47,224
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $2,583 in 2018	82,328				—
Other property and equipment, net of accumulated depreciation of $2,722 in 2018 and $2,224 in 2017	4,488				4,706
Total property and equipment, net	842,453				774,082
Long-term derivative assets	—				6
Other noncurrent assets	3,151				3,130
Total assets	$	927,442			$	830,371
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	50,242			$	62,129
Oil and gas revenue distribution payable	20,355				15,667
Derivative liability	28,416				11,423
Total current liabilities	99,013				89,219
Long-term liabilities:
Credit facility	60,000				—
Ad valorem taxes	19,803				11,584
Long-term derivative liability	4,657				2,972
Asset retirement obligations for oil and gas properties	28,154				38,262
Asset retirement obligations for oil and gas properties held for sale	5,386				—
Total liabilities	217,013				142,037
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding	—				—
Common stock, $.01 par value, 225,000,000 shares authorized, 20,534,799 and 20,453,549 issued and outstanding in 2018 and 2017, respectively	4,286				4,286
Additional paid-in capital	692,434				689,068
Retained earnings (deficit)	13,709				(5,020		)
Total stockholders’ equity	710,429				688,334
Total liabilities and stockholders’ equity	$	927,442			$	830,371

Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)
	Three Months Ended June 30,								Six Months Ended June 30,
	2018				2017				2018				2017
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains	8,866				6,189				8,575				6,690
Mid-Continent	1,600				1,845				1,633				1,889
Total	10,466				8,034				10,208				8,579
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$	63.05			$	43.94			$	60.15			$	45.94
Mid-Continent	$	67.12			$	47.69			$	64.69			$	49.65
Composite	$	63.67			$	44.80			$	60.87			$	46.76
Composite (after derivatives)	$	55.99			$	44.80			$	54.47			$	46.76
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains	3,126				3,046				2,772				3,167
Mid-Continent	441				452				444				471
Total	3,567				3,498				3,216				3,638
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$	17.06			$	16.10			$	19.34			$	15.90
Mid-Continent	$	33.13			$	20.84			$	30.92			$	23.32
Composite	$	19.05			$	16.71			$	20.94			$	16.86
Composite (after derivatives)	$	19.05			$	16.71			$	20.94			$	16.86
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains	18,511				20,144				18,385				20,786
Mid-Continent	5,421				6,067				5,444				6,249
Total	23,932				26,211				23,829				27,035
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$	1.96			$	2.18			$	2.29			$	2.29
Mid-Continent	$	2.70			$	3.06			$	2.98			$	3.15
Composite	$	2.13			$	2.38			$	2.45			$	2.49
Composite (after derivatives)	$	2.13			$	2.38			$	2.50			$	2.49
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains	15,077				12,592				14,412				13,322
Mid-Continent	2,945				3,308				2,985				3,402
Total	18,022				15,900				17,397				16,724
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$	43.02			$	28.98			$	42.43			$	30.43
Mid-Continent	$	46.40			$	35.05			$	45.43			$	36.60
Composite	$	43.57			$	30.24			$	42.95			$	31.68
Composite (after derivatives)	$	39.11			$	30.24			$	39.26			$	31.68
Total Sales Volumes (MBoe)	1,640.0				1,446.9				3,148.8				3,026.9

Schedule 5: Per unit operating margins
(unaudited)
	Three Months Ended June 30,											Six Months Ended June 30,
	2018				2017				Percent Change			2018				2017				Percent Change
Production
Oil (MBbl)	952				731				30	%		1,848				1,553				19	%
Gas (MMcf)	2,178				2,385				(9	)%		4,313				4,893				(12	)%
NGL (MBbl)	325				318				2	%		582				659				(12	)%
Equivalent (MBoe)	1,640				1,447				13	%		3,149				3,027				4	%
Realized pricing (before derivatives)
Oil ($/Bbl)	$	63.67			$	44.80			42	%		$	60.87			$	46.76			30	%
Gas ($/Mcf)	$	2.13			$	2.38			(11	)%		$	2.45			$	2.49			(2	)%
NGL ($/Bbl)	$	19.05			$	16.71			14	%		$	20.94			$	16.86			24	%
Equivalent ($/Boe)	$	43.57			$	30.24			44	%		$	42.95			$	31.68			36	%
Per Unit Costs ($/Boe)
Realized price equivalent (before derivatives)	$	43.57			$	30.24			44	%		$	42.95			$	31.68			36	%
Lease operating expense	6.90				6.47				7	%		6.92				6.37				9	%
Gathering, transportation and processing	1.01				—				—	%		1.27				—				—	%
Gas plant and midstream operating expense	1.98				1.80				10	%		2.18				1.75				25	%
Severance and ad valorem	3.70				2.60				42	%		3.59				2.67				34	%
Cash general and administrative	4.72				7.46				(37	)%		5.16				6.99				(26	)%
Total cash operating costs	$	18.31			$	18.33			—	%		$	19.12			$	17.78			8	%
Cash operating margin (before derivatives)	$	25.26			$	11.91			112	%		$	23.83			$	13.90			71	%
Derivative cash settlements	(4.46		)		—				—	%		(3.69		)		—				—	%
Cash operating margin (after derivatives)	$	20.80			$	11.91			75	%		$	20.14			$	13.90			45	%
Non-cash items
Non-cash general and administrative	$	1.33			$	5.76			(77	)%		$	1.01			$	3.33			(70	)%

Schedule 6: Adjusted Net Income
(in thousands, except per share amounts, unaudited)

Adjusted net income is a supplemental non-GAAP financial measure that is used by management to present recurring profitability that is more comparable between periods by excluding items that are non-recurring in nature or items which are not easily estimable. Management believes adjusted net income provides external users of the Company's consolidated financial statements such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. The Company defines adjusted net income as net income after adjusting first for (1) the impact of certain non-cash items and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on a tax rate that approximates the Company's effective tax rate in each period. Adjusted net income is not a measure of net income as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of adjusted net income.

		Three Months Ended June 30,								Six Months Ended June 30,
		2018				2017				2018				2017
Net income (loss)		$	4,859			$	93,356			$	18,729			$	(920	)
Adjustments to net income:
Derivative loss		22,012				—				30,754				—
Derivative cash settlements		(7,310		)		—				(11,622		)		—
Abandonment and impairment of unproved properties		2,477				—				4,979				—
Exploratory dry hole expense		—				294				—				2,995
Unused commitments		—				—				21				993
Stock-based compensation (1)		2,184				8,340				3,192				10,065
Reorganization items, net		—				(97,811		)		—				(8,808		)
Pre-petition advisory fees (1)		—				—				—				683
Post-petition restructuring fees (1)		—				1,422				—				1,422
Total adjustments before taxes		19,363				(87,755		)		27,324				7,350
Income tax effect		—				—				—				—
Total adjustments after taxes		$	19,363			$	(87,755	)		$	27,324			$	7,350
Adjusted net income		$	24,222			$	5,601			$	46,053			$	6,430
Adjusted net income per diluted share (2)		$	1.18			$	0.27			$	2.24			$	0.32
Diluted weighted-average common shares outstanding (2)		20,603				20,369				20,538				20,369
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.
(2) For the three- and six-month periods ended June 30, 2017, the Company used the Successor's diluted weighted average share count to calculate adjusted net income per diluted share.

Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management to provide a metric of the Company's ability to internally generate funds for exploration and development of oil and gas properties. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes adjusted EBITDAX provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income (loss) or cash flows as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

		Three Months Ended June 30,								Six Months Ended June 30,
		2018				2017				2018				2017
Net income (loss)		$	4,859			$	93,356			$	18,729			$	(920	)
Exploration		221				651				250				4,058
Depreciation, depletion and amortization		9,564				11,689				17,072				32,901
Abandonment and impairment of unproved properties		2,477				—				4,979				—
Unused commitments		—				—				21				993
Stock-based compensation (1)		2,184				8,340				3,192				10,065
Interest expense		805				1,283				1,162				5,851
Derivative loss		22,012				—				30,754				—
Derivative cash settlements		(7,310		)		—				(11,622		)		—
Pre-petition advisory fees (1)		—				—				—				683
Post-petition restructuring fees (1)		—				1,422				—				1,422
Reorganization items, net		—				(97,811		)		—				(8,808		)
Adjusted EBITDAX		$	34,812			$	18,930			$	64,537			$	46,245
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.

Schedule 8: Cash G&A
(in thousands, unaudited)

Cash G&A is a supplemental non-GAAP financial measure that is used by management to provide only the cash portion of its G&A expense, which can be used to evaluate cost management and operating efficiency on a comparable basis from period to period. Management believes cash G&A provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines cash G&A as GAAP general and administrative expense exclusive of the Company's stock based compensation and one-time charges, such as severance costs and advisor fees. The Company refers to cash G&A to provide typical cash G&A costs that are planned for in a given period. Cash G&A is not a fully inclusive measure of general and administrative expense as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of general and administrative expense to the non-GAAP financial measure of cash G&A.

		Three Months Ended June 30,								Six Months Ended June 30,
		2018				2017				2018				2017
General and administrative		$	9,917			$	19,137			$	19,451			$	31,231
Stock-based compensation		(2,184		)		(8,340		)		(3,192		)		(10,065		)
Cash G&A		$	7,733			$	10,797			$	16,259			$	21,166
Post-petition restructuring fees		—				(1,422		)		—				(1,422		)
Other non-recurring expense		—				(184		)		—				(184		)
Recurring Cash G&A		$	7,733			$	9,191			$	16,259			$	19,560