• Production from enhanced completions is outperforming offset wells by ~40%
  
• Expecting ~15% reductions to annualized LOE and midstream operating expense
• Improved drilling cycle times with record spud-to-total depth of 3.4 days for a 4,100' lateral
• Third quarter production volumes averaged 15.8 MBoe per day

DENVER, Nov. 08, 2017 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company" or "Bonanza Creek") today announces its third quarter 2017 financial results and operating outlook and has posted an updated investor presentation on its corporate website.

Seth Bullock, Interim CEO commented, "Our third quarter operations program was very encouraging with great production results from our enhanced completions and record drill times on SRL wells drilled during the quarter. I am pleased to announce that initial results from our enhanced completion program are significantly out-pacing offset wells that used the previous completion design. These increased production results along with the significant structural cost reductions that have been identified and implemented this year are laying the ground work for a strong 2018. I am confident that this reorganized Company is successfully shaping a culture that pursues continuous improvement and maximizes returns for its shareholders."

Operational Highlights

Production Results from Enhanced Completions
At the end of the second quarter, the Company completed its first pad of four drilled uncompleted ("DUC") wells which utilized enhanced completion design. These 4,100-foot standard reach lateral ("SRL") wells were completed using approximately 2,000 pounds of sand per lateral foot, approximately 100-foot stage spacing, and enhanced recovery flow back. Initial results from these first four wells are very encouraging, with an approximate 40% increase in overall average production and an approximate 60% increase in average oil production through the first 120 days when compared to offsetting wells. The offsetting wells utilized the Company's previous standard design of approximately 1,000 pounds of sand per lateral foot and stage spacing of approximately 225 feet.

Drilling and Completion Activity
During the third quarter the Company's operated program drilled six gross and net wells (4 SRL and 2 XRL), and completed zero wells. The Company's non-operated program had one net completion during the third quarter. Newly drilled wells for the quarter included three wells on the Company's central legacy acreage, one well on its French Lake acreage, and two wells of an eight-well pad on its western legacy acreage. The Company's non-operated program had four gross, one net completion during the third quarter. Subsequent to the quarter, the Company finished drilling its 8-well pad and completed five wells on its central acreage positions, and completed its one French Lake well. The results from these wells along with the remaining 2017 program, which exclusively utilized an enhanced completion design, are expected during the first half of 2018 and will help to inform the Company's drilling and completion program into 2019. Year-to-date, the Company's operated drilling program has exceeded expectations with faster drill times. Spud-to-rig release times have decreased by approximately 20% when compared to the 2016 program, and are currently averaging less than six days for an SRL.

Wattenberg Gas Takeaway
Due to increased line pressures on the gathering system operated by the Company's primary gas processor, Bonanza Creek entered into a 15-year gas purchase agreement with Sterling Energy Investments, LLC, a nearby third-party gas processor, on September 1, 2017. The agreement will allow the Company to deliver approximately 6.5 MMcf per day of wet gas, or approximately 20% of the Company's third quarter 2017 Rocky Mountain gas production, into Sterling's system. A new pipeline and interconnect, constructed by Sterling, will provide an additional gas processing outlet for gas production from the Company via its Rocky Mountain Infrastructure (RMI) gas gathering system. Gas will begin flowing to Sterling during the first half of November 2017.  The Company is currently evaluating additional alternatives to minimize the potential of production headwinds from regional infrastructure constraints.

Third Quarter 2017 Results

During the third quarter of 2017, the Company reported average daily production of 15.8 MBoe per day, at the low end of the Company's guidance range of 15.8 – 16.2 MBoe per day. Production during the quarter was negatively affected by the aforementioned increased line pressures on a third-party regional gas gathering and processing system in addition to extended downtime from offset completion operations. The Company's third quarter production decreased by 25% when compared to the third quarter of 2016 due to minimal drilling and completion activity throughout 2016 and the first half of 2017. Product mix for the third quarter of 2017 was 52% oil, 21% NGLs, and 27% natural gas. 

Net revenue for the third quarter of 2017 was $45.2 million, compared to $49.3 million for the third quarter of 2016. Crude oil accounted for approximately 76% of total revenue. Differentials for the Company's Rocky Mountain oil production during the quarter averaged approximately $4.45 per Bbl off of NYMEX WTI. Corporate average realized prices for the third quarter of 2017 are presented below.

Average Realized Prices
	Three Months Ended September 30, 2017
Oil (per Bbl)	44.72
Gas (per Mcf)	2.33
NGL (per Bbl)	17.79
Boe (Per Boe)	30.85

Lease operating expense ("LOE") for the third quarter of 2017 was $9.6 million, or $6.63 per Boe, a 3% reduction in total LOE compared to $9.9 million or $5.13 per Boe in the third quarter of 2016. Per unit metrics increased year over year as a result of declining volumes. These metrics are expected to improve as cost reductions are implemented and production volumes stabilize and increase. Future expected LOE reductions from cost saving initiatives are discussed in the "Production, Capital, and Expense Outlook" section below.

Below is a breakout of the Company's regional LOE and gas plant and midstream operating expense for the third quarter of 2017.

	Three Months Ended September 30, 2017
	Rocky Mountain								Mid-Continent								Total Company
	($M)				($/Boe)				($M)				($/Boe)				($M)				($/Boe)
Lease operating expense	$	6,638			$	5.76			$	3,005			$	9.97			$	9,643			$	6.63
Gas plant and midstream operating expense	$	1,299			$	1.13			$	1,966			$	6.52			3,265				$	2.24
Total	$	7,937			$	6.89			$	4,971			$	16.49			$	12,908			$	8.87

The Company's general and administrative ("G&A") expense was $15.2 million for the third quarter of 2017, a 19% decrease from the third quarter of 2016. The decrease is primarily due to $5.9 million in advisory fees related to financial alternatives that were incurred in 2016.  The Company's recurring cash G&A for the third quarter was, $8.6 million, compared to $10.9 million in the third quarter of 2016. The 21% decrease in recurring cash G&A is due primarily to the cost reduction initiatives that were implemented since restructuring, including the previously announced reduction in force, which occurred in August of 2017.

Recurring cash G&A is a non-GAAP measure. Please refer to the reconciliation to GAAP general and administrative expense in the financial exhibits to this press release.

Production, Capital, and Expense Outlook

The Company is providing updated production, capital, and expense guidance for the remainder of the year. The Company is reducing its full-year production guidance by 4%, to a mid-point of 16.0 MBoe per day as a result of increased line pressures in the basin, and significant processing downtime expected in the fourth quarter. To mitigate these line pressure issues, the Company has secured an agreement with another third party gas processor in the basin, and is actively exploring additional options to alleviate these basin level bottlenecks that negatively impact production. Due to changes in activity timing, CAPEX guidance for the year has been lowered to a midpoint of $112 million compared to previous guidance of $125 million. As a part of its ongoing cost structure review, the Company has identified further savings to its LOE, which will be implemented throughout 2018. The Company expects to reduce its run-rate LOE and gas plant/midstream operating expense by approximately $8.0 to $9.0 million in total, or approximately 15% of their annualized third quarter amounts, by the beginning of 2019. These LOE savings along with the previously announced G&A savings are concrete examples of the Company's commitment to reducing its cost structure and increasing full-cycle returns.

 Below is a table summarizing the Company's production, capital, and expense guidance for the remainder of 2017.

Guidance Summary
	Three Months Ended December 31, 2017		Twelve Months Ended December 31, 2017
Production (MBoe/d)	13.8 – 14.2		15.7 – 15.9
LOE ($/Boe)			$6.50 – $7.00
Midstream expense ($/Boe)			$1.90 – $2.10
Cash G&A* ($MM)			$41 – $43
Production taxes (% of pre-derivative realization)			7% – 8%
Total CAPEX ($MM)			$108 – $115
* Cash G&A guidance assumes severance costs of $1.6 million in the third quarter of 2017 and non-recurring expenses of $5.4 million. 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 less certainty to the stock based compensation portion of GAAP G&A.

Financial Highlights

As of the end of the third quarter, the Company had liquidity of $223 million, which included cash on hand of $31 million and $192 million of borrowing capacity under its credit facility.  The Company has no outstanding term debt and its credit facility is undrawn. Based on the terms of the credit facility, the Company's next borrowing base redetermination will occur in April of 2018. The Company's balance sheet strength allows it to be flexible, patient and selective in its investment decisions, and the opportunity to participate in acquisition opportunities and the flexibility to objectively evaluate divestiture candidates.

Commodity Derivative Position
The Company's current hedge position is summarized in the table below and reflects additional hedges the Company entered into through October 27, 2017.

		Crude Oil (NYMEX WTI)						Natural Gas (NYMEX Henry Hub)
		Bbls/day			Weighted Avg. Price per Bbl			MMBtu/day			Weighted Avg. Price per MMBtu
4Q17
Swap		2,000			$51.86			—			—
Collar		2,000			$41.50/$51.00			2,600			$3.00/$3.30
1Q18
Swap		2,000			$51.61			6,000			$3.36
Collar		2,000			$42.00/$52.50			5,600			$2.75/$3.43
2Q18
Swap		2,000			$51.61			—			—
Collar		2,000			$42.00/$52.50			5,600			$2.75/$3.43
3Q18
Swap		2,000			$51.96			—			—
Collar		2,000			$43.00/$53.50			5,600			$2.75/$3.43
4Q18
Swap		2,000			$51.96			—			—
Collar		2,000			$43.00/$53.50			5,600			$2.75/$3.43
1Q19
Swap		—			—			—			—
Collar		2,000			$43.00/$54.53			2,600			$2.75/$3.40
2Q19
Swap		—			—			—			—
Collar		1,330			$44.01/$54.79			857			$2.75/$3.40

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on November 9, 2017 at 8:00 a.m. Mountain Time (10:00 a.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	7577527
Replay	855-859-2056	7577527

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 primarily in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations, and in southern Arkansas, focused on oily Cotton Valley sands. 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 2017 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, 2016, filed on March 16, 2017, 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:
James R. Edwards
Director - Investor Relations
720-440-6136
jedwards@bonanzacrk.com

Schedule 1: Statement of Operations

(in thousands, expect for per share amounts, unaudited)

	Successor					Predecessor
	Three Months Ended September 30, 2017					Three Months Ended September 30, 2016
Operating net revenues:
Oil and gas sales	$	45,232				$	49,325
Operating expenses:
Lease operating expense	9,643					9,893
Gas plant and midstream operating expense	3,265					2,874
Severance and ad valorem taxes	2,434					4,100
Depreciation, depletion and amortization	7,350					27,296
Abandonment and impairment of unproved properties	—					7,682
Unused commitments	—					1,688
General and administrative (including $2,646 and $1,863, respectively, of stock-based compensation)	15,181					18,671
Total operating expenses	37,873					72,204
Income (loss) from operations	7,359					(22,879		)
Other income (expense):
Derivative gain (loss)	(2,762		)			2,206
Interest expense	(265		)			(15,142		)
Other income (loss)	(4		)			913
Total other expense	(3,031		)			(12,023		)
Income (loss) from operations before taxes	4,328					(34,902		)
Income tax benefit (expense)	—					—
Net income (loss)	$	4,328				$	(34,902	)
Comprehensive income (loss)	$	4,328				$	(34,902	)
Basic net income (loss) per common share	$	0.21				$	(0.71	)
Diluted net income (loss) per common share	$	0.21				$	(0.71	)
Basic weighted-average common shares outstanding	20,439					49,324
Diluted weighted-average common shares outstanding	20,447					49,324

• The Predecessor Company followed the two-class method when computing the basic and diluted 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.
  
  

	Successor					Predecessor			Predecessor
	April 29, 2017 through September 30, 2017					January 1, 2017 through April 28, 2017			Nine Months Ended September 30, 2016
Operating net revenues:
Oil and gas sales	$	73,346				$	68,589		$	148,029
Operating expenses:
Lease operating expense	15,796					13,128			33,928
Gas plant and midstream operating expense	5,027					3,541			10,198
Severance and ad valorem taxes	4,842					5,671			11,531
Exploration	359					3,699			943
Depreciation, depletion and amortization	12,186					28,065			84,602
Impairment of oil and gas properties	—					—			10,000
Abandonment and impairment of unproved properties	—					—			24,463
Unused commitments	—					993			3,460
General and administrative (including $10,595,
$2,116 and $7,249, respectively, of stock-based compensation)	31,320					15,092			49,591
Total operating expenses	69,530					70,189			228,716
Income (loss) from operations	3,816					(1,600		)	(80,687		)
Other income (expense):
Derivative loss	(2,762		)			—			(11,724		)
Interest expense	(460		)			(5,656		)	(46,216		)
Reorganization items, net	—					8,808			—
Gain on termination fee	—					—			6,000
Other income	154					1,108			1,011
Total other income (expense)	(3,068		)			4,260			(50,929		)
Income (loss) from operations before taxes	748					2,660			(131,616		)
Income tax benefit (expense)	—					—			—
Net income (loss)	$	748				$	2,660		$	(131,616	)
Comprehensive income (loss)	$	748				$	2,660		$	(131,616	)
Basic net income (loss) per common share	$	0.04				$	0.05		$	(2.67	)
Diluted net income (loss) per common share	$	0.04				$	0.05		$	(2.67	)
Basic weighted-average common shares outstanding	20,410					49,559			49,244
Diluted weighted-average common shares outstanding	20,438					50,971			49,244

• The Predecessor Company followed the two-class method when computing the basic and diluted 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.
  
  

Schedule 2: Statement of Cash Flows
(in thousands, unaudited)

	Successor					Predecessor
	Three Months Ended September 30, 2017					Three Months Ended September 30, 2016
Cash flows from operating activities:
Net income (loss)	$	4,328				$	(34,902	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	7,350					27,296
Abandonment and impairment of unproved properties	—					7,682
Well abandonment costs and dry hole expense	10					(61		)
Stock-based compensation	2,646					1,865
Amortization of deferred financing costs and debt premium	—					426
Derivative (gain) loss	2,762					(2,206		)
Derivative cash settlements	—					4,348
Other	2					1,923
Changes in current assets and liabilities:
Accounts receivable	(8,447		)			6,027
Prepaid expenses and other assets	(350		)			301
Accounts payable and accrued liabilities	7,428					5,205
Settlement of asset retirement obligations	(477		)			(398		)
Net cash provided by operating activities	15,252					17,506
Cash flows from investing activities:
Acquisition of oil and gas properties	(92		)			(103		)
Exploration and development of oil and gas properties	(37,442		)			(4,738		)
Increase in restricted cash	(10		)			(5,172		)
Additions to property and equipment - non oil and gas	(506		)			(145		)
Net cash used in investing activities	(38,050		)			(10,158		)
Cash flows from financing activities:
Payments to credit facility	—					(44,000		)
Payment of employee tax withholdings in exchange for the return of common stock	(318		)			(10		)
Deferred financing costs	—					(79		)
Net cash used in financing activities	(318		)			(44,089		)
Net change in cash and cash equivalents	(23,116		)			(36,741		)
Cash and cash equivalents:
Beginning of period	54,212					170,171
End of period	$	31,096				$	133,430

	Successor					Predecessor			Predecessor
	April 29, 2017 through September 30, 2017					January 1, 2017 through April 28, 2017			Nine Months Ended September 30, 2016
Cash flows from operating activities:
Net income (loss)	$	748				$	2,660		$	(131,616	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	12,186					28,065			84,602
Non-cash reorganization items	—					(44,160		)	—
Impairment of oil and gas properties	—					—			10,000
Abandonment and impairment of unproved properties	—					—			24,463
Well abandonment costs and dry hole expense	74					2,931			905
Stock-based compensation	10,595					2,116			7,249
Amortization of deferred financing costs and debt premium	—					374			2,705
Derivative loss	2,762					—			11,724
Derivative cash settlements	—					—			15,749
Other	7					18			127
Changes in current assets and liabilities:
Accounts receivable	(2,027		)			(6,640		)	29,442
Prepaid expenses and other assets	(80		)			963			(1,047		)
Accounts payable and accrued liabilities	(11,910		)			(5,880		)	(23,252		)
Settlement of asset retirement obligations	(936		)			(331		)	(473		)
Net cash (used in) provided by operating activities	11,419					(19,884		)	30,578
Cash flows from investing activities:
Acquisition of oil and gas properties	(5,074		)			(445		)	(919		)
Exploration and development of oil and gas properties	(42,355		)			(5,123		)	(47,491		)
Payments of contractual obligation	—					—			(12,000		)
(Increase) decrease in restricted cash	(12		)			118			(7,707		)
Additions to property and equipment - non oil and gas	(667		)			(454		)	(106		)
Net cash used in investing activities	(48,108		)			(5,904		)	(68,223		)
Cash flows from financing activities:
Proceeds from credit facility	—					—			209,000
Payments to credit facility	—					(191,667		)	(58,667		)
Proceeds from sale of common stock	—					207,500			—
Payment of employee tax withholdings in exchange for the return of common stock	(2,398		)			(427		)	(283		)
Deferred financing costs	—					—			(316		)
Net cash (used in) provided by financing activities	(2,398		)			15,406			149,734
Net change in cash and cash equivalents	(39,087		)			(10,382		)	112,089
Cash and cash equivalents:
Beginning of period	70,183					80,565			21,341
End of period	$	31,096				$	70,183		$	133,430

Schedule 3: Condensed Consolidated Balance Sheets

(in thousands, unaudited)	Successor					Predecessor
	September 30, 2017					December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	31,096				$	80,565
Accounts receivable:
Oil and gas sales	25,443					14,479
Joint interest and other	4,488					6,784
Prepaid expenses and other	5,032					5,915
Inventory of oilfield equipment	3,270					4,685
Derivative assets	48					—
Total current assets	69,377					112,428
Property and equipment (successful efforts method):
Proved properties	508,955					2,525,587
Less: accumulated depreciation, depletion and amortization	(10,771		)			(1,694,483		)
Total proved properties, net	498,184					831,104
Unproved properties	183,534					163,369
Wells in progress	44,049					18,250
Other property and equipment, net of accumulated depreciation of $560 in 2017 and $11,206 in 2016	6,163					6,245
Total property and equipment, net	731,930					1,018,968
Long-term derivative assets	6					—
Other noncurrent assets	2,750					3,082
Total assets	$	804,063				$	1,134,478
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	50,848				$	61,328
Oil and gas revenue distribution payable	19,828					23,773
Derivative liability	2,044					—
Revolving credit facility - current portion	—					191,667
Senior Notes - current portion	—					793,698
Total current liabilities	72,720					1,070,466
Long-term liabilities:
Ad valorem taxes	8,531					14,118
Derivative liability	772					—
Asset retirement obligations for oil and gas properties	28,973					30,833
Total liabilities	110,996					1,115,417
Stockholders’ equity:
Predecessor preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding as of December 31, 2016	—					—
Predecessor common stock, $.001 par value, 225,000,000 shares authorized,  49,660,683 issued and outstanding as of December 31, 2016	—					49
Successor preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding as of September 30, 2017	—					—
Successor common stock, $.01 par value, 225,000,000 shares authorized, 20,453,444 issued and outstanding as of September 30, 2017	4,286					—
Additional paid-in capital	688,033					814,990
Accumulated earnings (deficit)	748					(795,978		)
Total stockholders’ equity	693,067					19,061
Total liabilities and stockholders’ equity	$	804,063				$	1,134,478

Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)

	Three Months Ended September 30,								Nine Months Ended September 30,
	2017				2016				2017				2016
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains	6,447				8,845				6,632				10,403
Mid-Continent	1,816				2,152				1,871				2,286
Total	8,263				10,997				8,503				12,689
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$	43.90			$	35.64			$	45.27			$	32.01
Mid-Continent	$	47.63			$	44.33			$	49.00			$	41.64
Composite	$	44.72			$	37.35			$	46.09			$	33.75
Composite (after derivatives)	$	44.72			$	41.64			$	46.09			$	38.27
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains	2,842				3,916				3,069				3,702
Mid-Continent	463				607				470				667
Total	3,305				4,523				3,539				4,369
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$	16.31			$	9.77			$	16.03			$	11.08
Mid-Continent	$	26.88			$	17.44			$	24.51			$	15.38
Composite	$	17.79			$	10.80			$	17.16			$	11.73
Composite (after derivatives)	$	17.79			$	10.80			$	17.16			$	11.73
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains	19,459				25,536				20,414				27,202
Mid-Continent	5,982				7,141				6,182				7,478
Total	25,441				32,677				26,596				34,680
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$	2.12			$	1.98			$	2.24			$	1.39
Mid-Continent	$	3.02			$	2.93			$	3.11			$	2.33
Composite	$	2.33			$	2.18			$	2.44			$	1.59
Composite (after derivatives)	$	2.33			$	2.18			$	2.44			$	1.59
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains	12,532				17,017				13,104				18,639
Mid-Continent	3,276				3,949				3,372				4,199
Total	15,808				20,966				16,476				22,838
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$	29.58			$	23.74			$	30.15			$	22.10
Mid-Continent	$	35.71			$	32.13			$	36.30			$	29.26
Composite	$	30.85			$	25.32			$	31.41			$	23.41
Composite (after derivatives)	$	30.85			$	27.57			$	31.41			$	25.93
Total Sales Volumes (MBoe)	1,454.4				1,928.9				4,481.3				6,257.5

Schedule 5: Per unit operating margins
(unaudited)

	Three Months Ended September 30,											Nine Months Ended September 30,
	2017				2016				Percent Change			2017				2016				Percent Change
Production
Oil (MBbl)	760				1,012				(25	)%		2,313				3,477				(33	)%
Gas (MMcf)	2,341				3,006				(22	)%		7,234				9,502				(24	)%
NGL (MBbl)	304				416				(27	)%		963				1,197				(20	)%
Equivalent (MBoe)	1,454				1,929				(25	)%		4,481				6,258				(28	)%
Realized pricing (before derivatives)
Oil ($/Bbl)	$	44.72			$	37.35			20	%		$	46.09			$	33.75			37	%
Gas ($/Mcf)	$	2.33			$	2.18			7	%		$	2.44			$	1.59			53	%
NGL ($/Bbl)	$	17.79			$	10.80			65	%		$	17.16			$	11.73			46	%
Equivalent ($/Boe)	$	30.85			$	25.32			22	%		$	31.41			$	23.41			34	%
Per Unit Costs ($/Boe)
Realized price (before derivatives)	$	30.85			$	25.32			22	%		$	31.41			$	23.41			34	%
Lease operating expense	6.63				5.13				29	%		6.45				5.42				19	%
Gas plant and midstream operating expense	2.24				1.49				50	%		1.91				1.63				17	%
Severance and ad valorem	1.67				2.13				(22	)%		2.35				1.84				28	%
Cash general and administrative	8.62				8.71				(1	)%		7.52				6.77				11	%
Total cash operating costs	$	19.16			$	17.46			10	%		$	18.23			$	15.66			16	%
Cash operating margin (before derivatives)	$	11.69			$	7.86			49	%		$	13.18			$	7.75			70	%
Derivative cash settlements	—				2.25				(100	)%		—				2.52				(100	)%
Cash operating margin (after derivatives)	$	11.69			$	10.11			16	%		$	13.18			$	10.27			28	%
Non-cash items
Non-cash general and administrative	$	1.82			$	0.97			88	%		$	2.84			$	1.16			145	%

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

Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines adjusted net loss as net loss 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 loss 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 (loss) to the non-GAAP financial measure of adjusted net loss.

		Three Months Ended September 30,										Nine Months Ended September 30,
		2017					2016					2017				2016
Net Income (Loss)		$	4,328				$	(34,902	)			$	3,408			$	(131,616	)
Adjustments to Net Income (Loss):
Derivative loss		2,762					(2,206		)			2,762				11,724
Derivative cash settlements		—					4,348					—				15,749
Gain on termination fee		—					—					—				(6,000		)
Impairment of proved properties		—					—					—				10,000
Abandonment and impairment of unproved properties		—					7,682					—				24,463
Exploratory dry hole expense		10					(61		)			3,005				905
Stock-based compensation (1)		2,646					1,865					12,711				7,249
Advisor fees related to financial alternatives (1)		—					5,918					—				5,918
Severance costs (1)		1,605					—					1,605				2,162
Reorganization items		—					—					(8,808		)		—
Pre-petition advisory fees (1)		—					—					683				—
Post-petition restructuring fees (1)		2,317					—					3,740				—
Total adjustments before taxes		9,340					17,546					15,698				72,170
Income tax effect		—					—					—				—
Total adjustments after taxes		$	9,340				$	17,546				$	15,698			$	72,170
Adjusted net income (loss)		$	13,668				$	(17,356	)			$	19,106			$	(59,446	)
Adjusted net income (loss) per diluted share (2)		$	0.67				$	(0.35	)			$	0.93			$	(1.21	)
Diluted weighted-average common shares outstanding (2)		20,447					49,324					20,438				49,244
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) For the nine-month period ended September 30, 2017, the Company used the Successor's diluted weighted average share count to calculated 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 and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. 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 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 September 30,								Nine Months Ended September 30,
		2017				2016				2017				2016
Net Income (loss)		$	4,328			$	(34,902	)		$	3,408			$	(131,616	)
Exploration		—				—				4,058				943
Depreciation, depletion and amortization		7,350				27,296				40,251				84,602
Impairment of proved properties		—				—				—				10,000
Abandonment and impairment of unproved properties		—				7,682				—				24,463
Stock-based compensation		2,646				1,865				12,711				7,249
Severance costs (1)		1,605				—				1,605				2,162
Advisor fees related to financial alternatives (1)		—				5,918				—				5,918
Gain on termination fee		—				—				—				(6,000		)
Interest expense		265				15,142				6,116				46,216
Derivative (gain) loss		2,762				(2,206		)		2,762				11,724
Derivative cash settlements		—				4,348				—				15,749
Pre-petition advisory fees (1)		—				—				683				—
Post-petition restructuring fees (1)		2,317				—				3,740				—
Reorganization items		—				—				(8,808		)		—
Income tax benefit		—				—				—				—
Adjusted EBITDAX		$	21,273			$	25,143			$	66,526			$	71,410
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.

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

Recurring cash G&A is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines recurring cash G&A as GAAP G&A after adjusting for the impact of non-cash stock compensation expense and non-recurring items.

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

		Three Months Ended September 30,
		2017				2016
General and Administrative		$	15,181			$	18,671
Stock-based compensation		(2,646		)		(1,863		)
Cash G&A		$	12,535			$	16,808
Advisor fees related to financial alternatives		—				(5,918		)
Post-petition restructuring fees		(2,317		)		—
Severance payments		(1,605		)		—
Recurring Cash G&A		$	8,613			$	10,890

 

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