• Third quarter production volumes averaged 29.0 Mboe per day, compared to guidance of 28.6 Mboe per day
  
• Cash operating costs of $14.01 per boe, a 16% sequential decrease from the second quarter of 2015
  
• Adjusted EBITDAX⁽¹⁾ of $73.3 million; adjusted net loss⁽¹⁾ of $3.6 million, or $0.07 per diluted share
  
• Third quarter CAPEX of $88.3 million, a 46% sequential decrease from the second quarter; Company reiterates annual CAPEX of $420 million at the midpoint
  
• Entered into an agreement with a midstream partner to divest its Rocky Mountain Infrastructure subsidiary for total anticipated cash consideration of $255 million
  

(1) Non-GAAP measure, see attached Reconciliation Schedules.

DENVER, Nov. 05, 2015 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE: BCEI) today announces its third quarter 2015 financial and operating results, and also announces it has entered into an agreement to divest its Rocky Mountain Infrastructure subsidiary. The Company has posted a related investor presentation to its website at www.bonanzacrk.com and has scheduled a conference call to discuss these results on November 6, 2015 at 9:00 AM Mountain Time (11:00 AM Eastern Time). Dial-in information is included at the end of this release.

Richard Carty, President and Chief Executive Officer, commented, "The Company had an excellent quarter, with production volumes above our guidance, continuous improvement programs driving cash costs meaningfully lower, and improved production from redesigned well completions. Our operating teams have worked diligently throughout the year to target incremental productivity and efficiency gains, which are now being realized through lower field development costs and enhanced field-wide productivity. In addition, we announced today that we have entered into an agreement to sell our Rocky Mountain Infrastructure ("RMI") asset that was established in the second quarter, to a strategic midstream partner for total anticipated cash proceeds of $255 million. This is a big accomplishment, as it validates our value creation strategy for stockholders and provides significant additional liquidity for a Company of our size. Our sustainability and resilience have been further buttressed as total pro forma liquidity as of September 30, 2015, increases to $594 million. In addition to an enhanced liquidity position, the sale will provide drilling incentives in 2016 and 2017, and will refocus the Company's talent and capital toward a very productive pure upstream business model.  We look forward to a long-term relationship with our midstream partner, as we continue to develop the estimated 500 million barrels of equivalent resource on our contiguous 70,000 net acre position in the Wattenberg."

Third Quarter 2015 Results

For the third quarter of 2015, the Company reported average quarterly daily production of 29.0 Mboe per day, a 14% increase from the third quarter of 2014 (5% increase adjusted for estimated 3-stream volumes), and a 4% sequential increase from the second quarter of 2015. Product mix for the quarter was unchanged from the previous quarter at 59% oil, 17% NGLs, and 23% natural gas. 

Net revenue for the third quarter of 2015 was $72.1 million, compared to $156.4 million for the third quarter of  2014. Crude oil and liquids accounted for approximately 90% of total revenue. Average realized prices for the third quarter of 2015 are presented below.

Average Realized Prices
	For the Three Months Ended September 30, 2015
	Before Derivatives				After Derivatives
Oil (per Bbl)	$	38.87			$	62.75
Gas (per Mcf)	$	2.13			$	2.32
NGL (per Bbl)	$	7.91			$	7.91
BOE (Per BOE)	$	27.09			$	41.25

Cash operating costs for the quarter were $37.3 million, or $14.01 per boe, a 27% decrease from $19.27 per boe ($17.84 per boe adjusted for estimated three-stream volumes), in the third quarter of 2014, and a 16% sequential decrease from the second quarter of 2015. Cash operating costs for the quarter were lower as a result of reduced G&A and severance/ad valorem taxes. 

During the third quarter, the Company underwent a workforce reorganization to better align its employee base and organization with tempered activity levels. The Company incurred a one-time charge of approximately $1.2 million related to severance and expects its general and administrative expense to be reduced by approximately $5.3 million annually as a result of this reorganization. Reported general and administrative expense for the quarter was $17.8 million, or $6.69, per boe, ($5.85 per boe adjusted for estimated 3-stream volumes), a 21% sequential decrease per barrel from the second quarter of 2015. Adjusting for the severance charge in the third quarter, total G&A expense was $6.24 per boe. Cash G&A expense for the quarter was $5.50 per boe or $5.05 per boe adjusted for the severance charge related to the reorganization, which was a 25% sequential reduction from the second quarter of 2015.

Severance and ad valorem taxes for the quarter were $2.4 million, which was a sequential decrease of approximately $2.0 million from the prior quarter due to a severance tax credit in the Company's  Rocky Mountain region.  

Depreciation, depletion and amortization for third quarter of 2015 was $58.6 million, or $22.01 per boe, an 18% decrease from $26.95 per boe ($24.97 per boe adjusted for estimated 3-stream volumes), in the third quarter 2014.

Total costs incurred for the third quarter of 2015 were $88.3 million, of which $10.5 million was related to RMI compared to total costs incurred of $164.0 million for the second quarter of 2015, of which $28.4 million was related to RMI.

Reported net loss for the third quarter of 2015 was $112.3 million, or $2.25 per diluted share, compared to net income of $48.8 million, or $1.18 per diluted share, for third quarter 2014. Adjusted net loss for third quarter 2015 was $3.6 million, or $0.07 per diluted share, compared to adjusted net income of $18.9 million, or $0.46 per diluted share for third quarter 2014.

Adjusted EBITDAX for third quarter 2015 was $73.3 million, a 33% decrease compared to $110.4 million for the third quarter 2014. The related decrease in realized price per BOE over the two periods was approximately 60%.

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.

Operations Update

Rocky Mountain Region – Wattenberg Horizontal Development

During the quarter, the Company tied 24 gross (20 net) horizontal wells into sales, consisting of 14 net standard reach laterals (SRLs) and 6 net extended reach laterals (XRLs).  All of the completed wells that were turned into sales during the quarter were operated by Bonanza Creek. For the full year 2015, the Company is on pace to complete and tie into sales approximately 89 gross (76 net) wells or approximately 94 net SRL equivalent wells in its Rocky Mountain region. For the third quarter, upstream capital costs incurred for the region were $65.4 million.

During the third quarter of 2015, production from the Rocky Mountain region averaged  23.7 Mboe/d, or 82% of total Company volumes. The production was comprised of 60% crude oil, 19% NGLs and 21% natural gas. On a 3-stream basis, sales volumes increased by 10% compared to the third quarter of 2014 and increased sequentially by 5% compared to the second quarter of 2015.

Rocky Mountain Region – Enhanced Capital Efficiency

The Company continues to drive efficiency gains in its operated program resulting in lower completed well costs. During the third quarter, the Company achieved well costs of $3.4 million for an SRL and $5.1 million for an XRL. After closing the RMI transaction, the Company expects to meet its goal of $3.0 million completed well costs for an SRL, an approximately 15%, or $500,000, reduction from well costs at the end of the second quarter of 2015. For XRL wells, the Company expects completed well costs of $4.5 million after the expected closing of the RMI transaction. During the quarter, the Company commissioned its centralized frac pond which allows water to be pumped to a completion job via flexible hose, eliminating the need for water to be trucked to completion locations. The remainder of well cost reductions come from the elimination of allocated midstream infrastructure costs which will no longer be incurred by Bonanza Creek upon the expected closing of its RMI transaction.

During the third quarter, Bonanza Creek released one of its two operated rigs due to reduced drilling times, which now average 5.9 days per SRL and 9.9 days for an XRL, an approximate 25% and 40% decrease in drill days from the beginning of 2015, respectively. Due to these drilling efficiencies, the Company expects to drill the same number of wells in 2015 as was originally contemplated with a lower average rig count.

The Company released results on a completion design test that increased sand loading by 50% to approximately 6 million pounds of sand for an SRL, or 1,500 pounds per lateral foot.  The test wells were completed in the third quarter of 2014 on the eastern side of the legacy acreage position and have over 300 days of production data.  After 300 days of production, the test wells performed approximately 20% better on a cumulative production basis and resulted in a 45% decrease in well payback period when compared to a similar well completed with 1,000 pounds of sand per lateral foot. The incremental cost of the additional sand is approximately $200,000. The Company plans to implement the increased sand completion design into the majority of its contemplated 2016 program.

During the third quarter, the Company continued to realize decreased downtime due to the completion of the Pronghorn gathering system and DCP Windmill pipeline. These two projects create flexibility and flow assurance, both on the Company's low pressure system as well as the DCP system. The subsequent lower, more consistent line pressures have resulted in a 50% decrease in measured production volatility on the Company's eastern acreage.

Differentials to WTI in the Wattenberg Field have decreased to an average of $9.11 per Bbl during the third quarter compared to $9.22 per Bbl during the second quarter of 2015.

Mid-Continent Region – Cotton Valley Development

During the third quarter of 2015, Bonanza Creek spud 8 gross (7 net) Cotton Valley wells, tied 7 gross (6 net) wells into sales and performed 14 gross (12 net) re-completions. For the third quarter, capital costs incurred for the region were $12.2 million.

The Mid-Continent region contributed 5.3 Mboe/d, or 18% of total Company net sales volumes for the third quarter of 2015, and was comprised of 52% crude oil, 16% NGLs and 32% natural gas. Sales volumes were down 11% compared to the third quarter of 2014 and unchanged from the second quarter of 2015.

Rocky Mountain Infrastructure Divestiture

Bonanza Creek has entered into a purchase agreement with Meritage Midstream Services IV, LLC ("Meritage Midstream") to divest its Rocky Mountain Infrastructure, LLC (RMI) subsidiary for total cash consideration of up to $255 million, of which $175 million is to be paid upon closing. An additional $80 million is to be paid over a two year period with $20 million to be paid in two equal installments with the first installment due upon the later of the drilling and completion of 40 standard reach lateral (SRL) equivalent wells or December 31, 2016 and the second installment due upon the drilling and completion of an additional 16 SRL equivalent wells. The remaining $60 million will be paid pro rata based on the number of SRL equivalent wells drilled and completed through 2017, such that the Company will be required to drill and complete 112 SRL equivalent wells in the next two years to receive the full $60 million, subject to certain deductions depending on well location and any previous dedications. The transaction is expected to close by December 31, 2015, but no later than January 31, 2016, subject to customary closing conditions. After closing this transaction, the Company expects completed SRL well costs will effectively decrease by approximately $300,000 per well by eliminating significant portions of allocated infrastructure in the Company's AFEs. This decrease is in addition to the aforementioned drilling incentive of approximately $535,000 per well. As a result of the sale, the Company expects a net increase to operating expense of approximately $2.00 – $2.25 per boe related to midstream throughput fees. As a part of the continued build-out of the midstream system, Meritage Midstream has agreed to build two new central production facilities (CPF) in 2016, one on the Company's northern area, and one on its legacy acreage. These two new-build CPFs will allow the Company to expand operations on its northern leasehold and reduce drill and complete costs on its legacy acreage by minimizing well site infrastructure.

Financial and Risk Management Update

Debt and Liquidity

Bonanza Creek has a $1.0 billion revolving credit facility, which was redetermined in October of 2015 with an approved borrowing base and commitment amount of $475 million. As of September 30, 2015, the Company had borrowings under its credit facility of $69.0 million, a letter of credit totaling $12.0 million, and cash totaling $25.3 million, resulting in total liquidity of $419.0 million under its redetermined commitment amount. After giving effect to the $175 million in initial proceeds from the RMI sale, pro forma liquidity as of September 30, 2015 is approximately $594 million. Bonanza Creek has two outstanding issues of unsecured high-yield bonds which consist of $500 million 6.75% senior notes due in 2021 and $300 million 5.75% senior notes due in 2023.  As of September 30, 2015, the Company was in compliance with all financial covenants, with a senior secured debt to EBITDAX ratio of 0.3x, an interest coverage ratio of 5.3x, and a current ratio of 2.6x.

Commodity Derivatives Positions

The following table summarizes the Company's crude oil and natural gas commodity derivative positions as of September 30, 2015 and settling quarterly:

Settlement		Swap		Fixed		Collar		Average		Average		Average
Period		Volume		Price		Volume		Short Floor		Floor		Ceiling
Oil		Bbl/d		$		Bbl/d		$		$		$
Q4 2015		6,000		72.16		6,500				84.62		95.49
FY 2016						5,500		70.00		85.00		96.83
Gas		MMBtu/d		$		MMBtu/d		$		$		$
Q4 2015						15,000		3.50		4.00		4.75

As a result of lower operating expenses incurred year to date and drilling and completion activity that has been moved to later in the fourth quarter, the Company's annual guidance has been revised accordingly. The table below provides updated guidance for the fourth quarter and full year of 2015, along with third quarter and year to date performance compared to the Company's previously provided guidance:

Guidance Summary
	Actual (3Q15)				Previous Guidance (1)				Current Guidance
Quarterly Guidance
3Q15 Production	29.0					28.6
4Q15 Production									27.5 – 28.1
	Actual (YTD)				Previous Guidance (1)				Current Guidance
Annual Guidance
Production (Mboe/d)	28.2				27.8 – 29.0				28.0 – 28.2
LOE ($/boe)	$	7.85			$7.75 – $8.25				$7.75 – $8.00
Cash G&A ($/boe)	$	5.90			$5.75 – $6.25				$5.75 – $6.00
Production taxes (% of pre-derivative realization)	5.5		%			6	%			6	%
CAPEX (in millions)
E&P CAPEX	$	331
RMI CAPEX (2)	$	44
Total CAPEX (in millions)	$	375			$400 - $440				$410 – $430
(1) Guidance provided on July 27, 2015 in conjunction with the Company's second quarter 2015 earnings release
(2) Includes approximately $22.5 million of un-budgeted RMI CAPEX in second quarter of 2015.

2016 Outlook

As the Company prepares for 2016, it is focused on preserving balance sheet strength and maintaining significant liquidity to be deployed when cash recycle times reduce to acceptable levels. In the meantime, while commodity prices are low, the Company will continue to enhance capital efficiencies and move focus away from growing production volumes. Bonanza Creek remains flexible as it looks to 2016, and given the current environment, plans to enter 2017 with an undrawn revolver and cash on the balance sheet.  Upon entering into an agreement to divest RMI, the Company has a clearer outlook for 2016 by establishing a baseline of activity required to achieve its drilling incentive payments pursuant to the agreement. Below is a table of the expected 2016 impacts of the RMI transaction:

RMI Transaction Terms	Impact to Bonanza Creek
$175 million cash payment at closing	Pro forma liquidity at 9/30: $594 million Pro forma net debt to TTM EBITDAX at 9/30: 2.2x.
$20 million deferred cash payment	Initial $10 million earned upon drilling 40 wells, additional $10 million earned upon drilling 16 additional wells, payable on December 31, 2016, subject to certain adjustments.
$60 million drilling incentive	Drilling incentive of approximately $535,000 per well, earned by drilling 112 SRL equivalent wells over a 2-year period payable quarterly based on well production tie-backs.
Divest 100% of RMI	Decreases allocated well costs by ~$300,000 per well by eliminating midstream investment.
OPEX fee to continue build out and operation of the 3-phase midstream system	Increase of approximately $2.00 – $2.25 per BOE to operating expense.

Conference Call Information

Bonanza Creek will host a conference call to discuss these financial and operating results on November 6, 2015 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). A webcast of this event will be available on the Company's website at www.bonanzacrk.com, for one year after the event. Dial-in information for the conference call is included below.

Type	Phone Number	Passcode
Domestic Participant	877-311-3255	63868716
International Participant	916-582-3594	63868716
Replay	855-859-2056	63868716

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 Mountains 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 IRRs; future reserves; impacts of the Company's development plan and spacing and pattern wells; development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company's reorganization; the closing and impact of the RMI transaction; optimization of midstream capabilities; updated 2015 guidance and 2016 outlook. 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, 2014, filed on February 27, 2015, 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.

Schedule 1: Statement of Operations
(in thousands, expect for per share amounts, unaudited)
	Three Months Ended September 30,								Nine Months Ended September 30,
	2015				2014				2015				2014
Operating net revenues:
Oil and gas sales	$	72,149			$	156,371			$	235,647			$	435,448
Operating expenses:
Lease operating expense	20,236				18,217				60,395				53,316
Severance and ad valorem taxes	2,411				15,334				13,055				42,347
Exploration	6,979				3,291				13,225				4,470
Depreciation, depletion and amortization	58,635				63,241				187,564				158,489
Impairment of oil and gas properties	166,780				—				166,780				—
Abandonment and impairment of unproved properties	1,630				—				21,627				—
General and administrative (including $3,164, $3,162, $10,951, and $17,312, respectively, of stock compensation)	17,818				14,814				56,292				63,075
Total operating expenses	274,489				114,897				518,938				321,697
Income (loss) from operations	(202,340		)		41,474				(283,291		)		113,751
Other income (expense):
Derivative gain	37,894				50,846				51,272				14,761
Interest expense	(14,073		)		(13,228		)		(42,779		)		(31,997		)
Other income (loss)	(2,077		)		181				(1,929		)		397
Total other income (expense)	21,744				37,799				6,564				(16,839		)
Income (loss) from continuing operations before taxes	(180,596		)		79,273				(276,727		)		96,912
Income tax benefit (expense)	68,297				(30,419		)		104,843				(37,216		)
Income (loss) from continuing operations	$	(112,299	)		$	48,854			(171,884		)		$	59,696
Discontinued operations:
Loss from operations associated with oil and gas properties held for sale	—				—				—				(85		)
Gain (loss) on sale of oil and gas properties	—				(117		)		—				6,213
Income tax benefit (expense)	—				45				—				(2,353		)
Gain (loss) from discontinued operations	—				(72		)		—				3,775
Net income (loss)	$	(112,299	)		$	48,782			$	(171,884	)		$	63,471
Basic income (loss) per share:
Income (loss) from continuing operations	$	(2.25	)		$	1.18			$	(3.56	)		$	1.47
Income from discontinued operations	$	—			$	—			$	—			$	0.09
Net income (loss) per common share	$	(2.25	)		$	1.18			$	(3.56	)		$	1.56
Diluted income (loss) per share:
Income (loss) from continuing operations	(2.25		)		$	1.18			(3.56		)		$	1.46
Income from discontinued operations	—				$	—			—				$	0.09
Net income (loss) per common share	(2.25		)		$	1.18			(3.56		)		$	1.55
Basic weighted-average common shares outstanding	48,962				40,556				47,485				39,958
Diluted weighted-average common shares outstanding	48,962				40,708				47,485				40,105

• The Company follows the two-class method when computing the basic and diluted income (loss) per share, which allocates earnings between common shareholders and participating securities. Please refer to Note 10 – Earnings per Share in the Form 10-Q, for a detailed calculation.

Schedule 2: Statement of Cash Flows
(in thousands, unaudited)
	Three Months Ended September 30,								Nine Months Ended September 30,
	2015				2014				2015				2014
Cash flows from operating activities:
Net income (loss)	$	(112,299	)		$	48,782			$	(171,884	)		$	63,471
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	58,635				63,241				187,564				158,557
Deferred income taxes	(69,051		)		30,274				(105,595		)		39,369
Impairment of oil and gas properties	166,780				—				166,780				—
Abandonment and impairment of unproved properties	1,630				—				21,627				—
Dry hole expense	1,948				—				7,628				—
Stock-based compensation	3,164				3,162				10,951				17,312
Amortization of deferred financing costs and debt premium	466				490				1,692				1,032
Accretion of contractual obligation for land acquisition	116				190				814				571
Derivative gain	(37,894		)		(50,846		)		(51,272		)		(14,761		)
Gain on sale of oil and gas properties	—				117				—				(6,213		)
Other	328				2				283				(12		)
Changes in current assets and liabilities:
Accounts receivable	9,934				8,548				28,253				(23,837		)
Prepaid expenses and other assets	2,342				289				994				(2,286		)
Accounts payable and accrued liabilities	11,149				14,019				(11,905		)		43,133
Settlement of asset retirement obligations	(259		)		(275		)		(778		)		(374		)
Net cash provided by operating activities	36,989				117,993				85,152				275,962
Cash flows from investing activities:
Acquisition of oil and gas properties	(1,688		)		(175,792		)		(13,602		)		(178,883		)
Proceeds from sale of oil and gas properties	—				—				—				6,000
Payments of contractual obligation	(12,000		)		(12,000		)		(12,000		)		(12,000		)
Exploration and development of oil and gas properties	(78,025		)		(172,696		)		(361,018		)		(448,586		)
Natural gas plant capital expenditures	—				(10		)		(113		)		(281		)
Derivative cash settlements	37,717				(994		)		88,372				(9,136		)
(Increase) decrease in restricted cash	2,926				8,218				2,926				(3,062		)
Additions to property and equipment - non oil and gas	(1,741		)		(1,462		)		(2,390		)		(5,451		)
Net cash used in investing activities	(52,811		)		(354,736		)		(297,825		)		(651,399		)
Cash flows from financing activities:
Proceeds from credit facility	28,000				230,000				115,000				230,000
Payments to credit facility	(2,000		)		(230,000		)		(79,000		)		(230,000		)
Proceeds from sale of common stock	—				—				209,300				—
Offering costs related to sale of common stock	(13		)		—				(6,620		)		—
Proceeds from sale of Senior Notes	—				300,000				—				300,000
Offering costs related to sale of Senior Notes	(6		)		(6,590		)		(99		)		(6,867		)
Payment of employee tax withholdings in exchange for the return of common stock	(145		)		(553		)		(2,593		)		(5,319		)
Deferred financing costs	(28		)		(51		)		(573		)		(341		)
Net cash provided by financing activities	25,808				292,806				235,415				287,473
Net change in cash and cash equivalents	9,986				56,063				22,742				(87,964		)
Cash and cash equivalents:
Beginning of period	15,340				36,555				2,584				180,582
End of period	$	25,326			$	92,618			$	25,326			$	92,618

Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)
	September 30,				December 31,
	2015				2014
ASSETS
Current assets	169,128				208,475
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $482,496 in 2015 and $- in 2014	362,922				—
Total property and equipment, net	1,386,286				1,756,477
Other assets	25,345				41,137
Total Assets	$	1,943,681			$	2,006,089
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities	192,509				198,447
Long-term debt	875,699				840,619
Deferred income taxes	60,072				165,667
Other long-term liabilities	35,851				61,285
Total Liabilities	1,164,131				1,266,018
Stockholders' Equity	779,550				740,071
Total Liabilities and Stockholders' Equity	$	1,943,681			$	2,006,089

Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)
	Three Months Ended
	September 30,
		2015					3-Stream 2014 (1)		2-Stream 2014
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains		14,083					13,606		13,606
Mid-Continent		2,774					2,965		2,965
Total		16,857					16,571		16,571
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$	37.45							$	83.81
Mid-Continent		45.89							94.79
Composite (before derivatives)	$	38.84							$	85.77
Composite (after derivatives)	$	62.75							84.74
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains		4,409					3,483		56
Mid-Continent		862					1079		1079
Total		5,271					4,562		1135
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$	8.01							$	23.08
Mid-Continent		7.37							50.38
Composite (before derivatives)	$	7.90							$	49.04
Composite (after derivatives)	$	7.91								49.04
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains		30,914					26,822		35,214
Mid-Continent		10,022					11,581		11,581
Total		40,936					38,403		46,795
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$	1.79							$	4.98
Mid-Continent		2.88							4.08
Composite (before derivatives)	$	2.06							$	4.76
Composite (after derivatives)	$	2.32								4.89
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains		23,645					21,559		19,531
Mid-Continent		5,306					5,974		5,974
Total		28,951					27,533		25,505
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$	26.14							$	67.44
Mid-Continent		30.64							64.05
Composite (before derivatives)	$	27.09							$	66.64
Composite (after derivatives)	$	41.25								66.22
Total Sales Volumes (MBoe)		2,663.5					2,533.0		2,346.4

	(1	)	Third quarter 2014 sales volumes in the Rocky Mountain region adjusted to reflect estimated 3-stream volumes to provide appropriate comparison to current 3-stream reporting convention.  See Schedule 7 for estimates of Rocky Mountain region 3-stream sales volumes by quarter for 2014.

Schedule 5: Per unit operating margins
(unaudited)
	For the Three Months Ended September 30,															For the Three Months Ended September 30,
		2015					2014 2-Stream						Percent Change				2015					2014 3-Stream(1)						Percent Change
Production
Oil (MBbl)	1,550.8						1,524.5						2	%		1,550.8						1,524.5						2	%
Gas (MMcf)	3,766.0						4,305.1						(13	)%		3,766.0						3,533						7	%
NGL (MBbl)	485.0						104.4						365	%		485.0						419.7						16	%
Equivalent (MBoe)	2,663.5						2,346.4						14	%		2,663.5						2,533.0						5	%
Realized pricing (before derivatives)
Oil ($/Bbl)	$		38.87				$		85.78				(55	)%
Gas ($/Mcf)	2.13						4.76						(55	)%
NGL ($/Bbl)	7.91						49.03						(84	)%
Equivalent ($/Boe)	$		27.09				$		66.64				(59	)%
Per Unit Costs ($/BOE)
Realized price (before derivatives)	$		27.09				66.64						(59	)%
LOE	7.60						7.76						(2	)%		7.60						7.19						6	%
Severance and Ad Valorem	0.91						6.54						(86	)%		0.91						6.05						(85	)%
Cash General and Administrative	$	5.50					$	4.97					11	%		$	5.50					$	4.60					20	%
Total cash operating costs	$		14.01				$		19.27				(27	)%		$		14.01				$		17.84				(21	)%
Cash operating margin (before derivatives)	$		13.08				$		47.37				(72	)%
Derivative Cash Settlements	$	14.16					(0.42			)			(3,471	)%
Cash operating margin (after derivatives)	$	27.24					46.95						(42	)%
Non-cash items
Depreciation Depletion and Amortization	22.01						26.95						(18	)%		22.01						24.97						(12	)%
Non-cash General and Administrative	$	1.19					$	1.34					(11	)%		$	1.19					$	1.25					(5	)%

	(1	)	Volumes and prices are adjusted to reflect estimated 3-stream volumes to provide appropriate comparison to current 3-stream reporting convention.  See Schedule 8 for estimated Rocky Mountain region 3-stream sales volumes by quarter for 2014.

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 and external users of the Company's consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines adjusted net income as net income after adjusting first for (1) the impact of certain non-cash items, including unrealized gains and losses on unsettled derivative instruments, impairment of oil and gas properties, other similar non-cash charges and one-time transactions and then (2) the non-cash and one time items' impact on taxes based on a tax rate of 38.3% for the three and nine-month periods ended September 30, 2015, and a tax rate of 38.5% for the three and nine-month periods ended September 30, 2014. These rates approximate 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 provides a reconciliation of net income (loss) (GAAP) to adjusted net income (loss) (non-GAAP):
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2015				2014				2015				2014
Net income (loss)		$	(112,299	)		$	48,782			$	(171,884	)		$	63,471
Adjustments to net income (loss):
Derivative gain		(37,894		)		(50,846		)		(51,272		)		(14,761		)
Derivative cash settlements		37,717				(994		)		88,372				(9,136		)
(Gain) loss on sale of oil and gas properties		—				117				—				(6,213		)
Impairment of proved properties		166,780				—				166,780				—
Abandonment and impairment of unproved properties		1,630				—				21,627				—
Exploratory dry hole		1,948				—				7,628				—
Stock-based compensation		3,164				3,162				10,951				17,312
Severance costs (1)		1,155				—				1,155				—
Litigation settlement (2)		1,638				—				1,638				—
Total adjustments before taxes		$	176,138			(48,561		)		246,879				(12,798		)
Income tax effect		(67,461		)		18,696				(94,555		)		4,927
Total adjustments after taxes		$	108,677			(29,865		)		152,324				(7,871		)
Adjusted net income (loss)		$	(3,622	)		$	18,917			$	(19,560	)		$	55,600
Adjusted net income (loss) per diluted share		$	(0.07	)		$	0.46			$	(0.41	)		$	1.39
Diluted weighted-average common shares outstanding		48,962				40,708				47,485				40,105
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) Included as a portion of other income (loss) on the consolidated statement of operations.

Schedule 7: Adjusted EBITDAX
(in thousands, except per share amounts, 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 GAAP financial measures of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2015				2014				2015				2014
Net Income (loss)		$	(112,299	)		$	48,782			$	(171,884	)		$	63,471
Exploration		6,979				3,291				13,225				4,470
Depreciation, depletion and amortization		58,635				63,241				187,564				158,557
Impairment of proved properties		166,780				—				166,780				—
Abandonment and impairment of unproved properties		1,630				—				21,627				—
Stock-based Compensation		3,164				3,162				10,951				17,312
Severance costs (1)		1,155				—				1,155				—
Litigation settlement (2)		1,638				—				1,638				—
(Gain) loss on sale of oil and Gas properties		—				117				—				(6,213		)
Interest expense		14,073				13,228				42,779				31,997
Derivative (gain) loss		(37,894		)		(50,846		)		(51,272		)		(14,761		)
Derivative cash settlements		37,717				(994		)		88,372				(9,136		)
Income tax (benefit) expense		(68,297		)		30,374				(104,843		)		39,569
Adjusted EBITDAX		$	73,281			$	110,355			$	206,092			$	285,266
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) Included as a portion of other income (loss) on the consolidated statement of operations.

Schedule 8: Estimated 2014 3-Stream Sales Volumes
The following estimates are based on internal BCEI calculations which convert previously reported 2-stream sales volumes in the Rocky Mountain region to 3-stream commodity mix.  No assurances can be provided to the accuracy of these figures as they are based on a variety of assumptions related, but not limited, to wet gas shrink and NGL yields.
	Three Months Ended						Twelve Months Ended
	March 31, 2014	June 30, 2014	September 30, 2014	December 31, 2014			December 31, 2014
Rocky Mountains
Oil (Bbl/d)	9,987	12,163	13,606	13,520			12,332
NGLs (Bbl/d)	2,417	2,886	3,483	3,430			3,058
Natural Gas (Mcf/d)	18,614	22,229	26,822	26,417			23,551
Total Equivalent (Boe/d)	15,506	18,754	21,559	21,353			19,315
Total Equivalent (MBoe)	1,395.6	1,706.6	1,983.4	1,964.5			7,050.0
Mid-Continent
Oil (Bbl/d)	2,949	2,962	2,965	3,367			3,062
NGLs (Bbl/d)	1,006	919	1,079	1,154			1,040
Natural Gas (Mcf/d)	9,887	11,445	11,581	12,106			11,261
Total Equivalent (Boe/d)	5,602	5,788	5,974	6,538			5,978
Total Equivalent (MBoe)	504.2	526.7	549.6	601.5			2,182.0
Total Company
Oil (Bbl/d)	12,936	15,125	16,571	16,887			15,394
NGLs (Bbl/d)	3,423	3,805	4,562	4,584			4,098
Natural Gas (Mcf/d)	28,501	33,674	38,403	38,523			34,812
Total Equivalent (Boe/d)	21,108	24,542	27,533	27,891			25,293
Total Equivalent (MBoe)	1,899.7	2,233.3	2,533.0	2,566.0			9,231.9