Bonanza Creek Energy Announces Second Quarter 2014 Operational and Financial Results

DENVER, August 7, 2014 - Bonanza Creek Energy, Inc. BCEI today reported its second quarter 2014 operating and financial results.

Key highlights for second quarter 2014, as compared to results from continuing operations for second quarter 2013⁽¹⁾, include:

• 69% increase in sales volumes to 22,849 Boe/d; 70% crude oil and liquids
• 79% increase in revenue to $151.7 million
• 75% increase in adjusted net income⁽²⁾ to $18.9 million, or $0.48 per share
  • Adjusted net income⁽²⁾ of $20.7 million, or $0.52 per share, when executive departure costs are excluded
• 75% increase in adjusted EBITDAX⁽²⁾ to $94.5 million
  • Adjusted EBITDAX⁽²⁾ of $97.4 million when executive departure costs are excluded

(1) Bonanza Creek began the divestiture process of its California properties in second quarter 2012 and sold its remaining property, the Midway Sunset Field, on March 21, 2014. Under generally accepted accounting principles, the results of operations for second quarter 2013 are presented as continuing operations.
 
(2) Non-GAAP measure, see attached Reconciliation Schedules.

Operational highlights for second quarter 2014 include:

• 40-acre spaced Niobrara B bench pad incorporating two wells with 28-stage fracs declined only 3% to 463 Boe/d after 60 days of initial production and all four wells are performing above the Company's target type curve
• Codell step-out well targeting six feet of net pay thickness initial 30-day production rate of 426 Boe/d
• Three extended reach laterals drilled and completed successfully; initial 30-day production rates were 809 Boe/d for a 9,000' lateral in the Niobrara B bench, 600 Boe/d for a 9,000' lateral in the Niobrara C bench and 746 Boe/d for a 7,500' lateral in the Codell

Marvin Chronister, Bonanza Creek's Interim President and Chief Executive Officer, commented, "Second quarter's results reflect Bonanza Creek's unwavering focus on execution and operational excellence. Production and the pace of drilling and completions are right on plan. Furthermore, as a result of our catalyst testing program in the Wattenberg Field we are becoming increasingly confident in 40-acre spacing, optimal lateral lengths and well configuration, and the primary recoveries achievable in the Niobrara and Codell. With over 70,000 largely contiguous net acres in the Wattenberg Field we are well positioned for top tier production growth far into the future."

Second Quarter 2014 Financial Results

Average realized prices for second quarter 2014, before the effect of commodity derivatives, were $92.60 per Bbl of oil, $5.34 per Mcf of natural gas and $51.89 per Bbl of NGLs, compared to $89.41 per Bbl of oil, $4.47 per Mcf of natural gas and $49.03 per Bbl of NGLs for second quarter 2013.

Net revenue for second quarter 2014 was $151.7 million, compared to $84.5 million for second quarter 2013. Crude oil and liquids revenue accounted for approximately 87% of total revenue.

Lease operating expense ("LOE") for second quarter 2014 was $18.0 million, or $8.67 per Boe, compared to $12.9 million, or $10.50 per Boe, for second quarter 2013.

General and administrative expense ("G&A") for second quarter 2014 was $24.5 million, or $11.81 per Boe, compared to $13.3 million, or $10.82 per Boe, for second quarter 2013. Cash G&A⁽²⁾ was $17.1 million, or $8.27 per Boe, compared to $10.6 million, or $8.63 per Boe, for second quarter 2013. G&A was impacted by executive departure costs of approximately $6.6 million, of which $2.9 million was cash. Not including departure costs, cash G&A for second quarter 2014 was $14.3 million, or $6.86 per Boe.

Severance and ad valorem taxes for second quarter 2014 were $16.3 million, or $7.82 per Boe, compared to $5.4 million, or $4.36 per Boe, for second quarter 2013. Colorado has higher severance and ad valorem tax rates than Arkansas and contributed a greater percentage of production for second quarter 2014 when compared to the same period in 2013. In addition, our increase in new production during 2013 in the Wattenberg Field resulted in a higher than expected lag in the amount of ad valorem tax credits eligible for deduction against severance taxes generated in the current year because ad valorem taxes are not eligible for deduction in the year a well is completed.

Net income for second quarter 2014 was $1.2 million, or $0.03 per diluted share, compared to $14.7 million, or $0.36 per diluted share for second quarter 2013. Adjusted net income⁽²⁾ for second quarter 2014 was $18.9 million, or $0.48 per diluted share, compared to adjusted net income of $10.8 million, or $0.27 per diluted share for second quarter 2013. Excluding cash severance costs associated with executive departures resulted in adjusted net income during the quarter of approximately $20.7 million, or $0.52 per diluted share.

Operations Update

During second quarter 2014, the Company achieved an average production rate of 22,849 Boe/d, comprised of 66% crude oil, 4% NGLs, and 30% natural gas.

Rocky Mountain Region - Wattenberg Horizontal Development

The Rocky Mountain region contributed 17,061 Boe/d, or 75% of total Company net sales volumes for the quarter, comprised of 71% crude oil and 29% liquids-rich natural gas. Approximately 95% of second quarter sales volumes were from horizontal wells. Sales volumes increased by approximately 104% over second quarter 2013.

During the quarter, the Company spud 32 gross (28.7 net) wells and placed 38 gross (31.9 net) operated wells into sales.

Catalyst Drilling Program

The Company's four well pad spaced at 40-acres in the Niobrara B bench, in which the two internal wells were completed with 28 stages, reported a four well average initial 60-day production rate of 463 Boe/d, only a 3% decline compared to the average initial 30-day production rate of 477 Boe/d. All four wells are currently tracking above the Company's 313 MBoe target type curve. The Company plans to drill a five well pad, completed with 28-stages per well, testing 40-acre spacing in the Niobrara B and C benches in the third quarter.

The Company completed its most eastern Codell well to date and reported an initial 30-day production rate of 426 Boe/d. The Codell well was drilled and completed in an area with just six feet of net pay that meets a 10% porosity threshold. The Company plans to drill a second eastern step-out well in the fourth quarter 2014. No current 3P inventory or reserves are associated with Codell net pay thickness of less than eight feet.

The Company successfully drilled and completed two 9,000' laterals in the Niobrara B and C benches and one 7,500' lateral in the Codell. The Niobrara B bench well achieved an average 30-day production rate of 809 Boe/d, the Niobrara C bench well reported an average 30-day production rate of 600 Boe/d and average 60-day rate of 592 Boe/d, while the 7,500' Codell lateral averaged 746 Boe/d and 679 Boe/d over its first 30 and 60 days of production, respectively. The Company plans to drill a total of 11 medium and extended reach laterals in 2014.

Midstream Update

A recent Federal Energy Regulatory Commission ruling indirectly voided the Company's privately negotiated agreement with a midstream partner to secure up to 18,000 Bbl/d (gross) through 2020 on the White Cliffs pipeline. As a part of the ruling, the FERC mandated that a new open season be conducted on the uncommitted volumes associated with the expansion project slated to come on line in late August. The Company will continue to seek firm transportation opportunities to bring its crude oil volumes to market via the White Cliffs expansion and other pipeline projects under consideration. Crude oil differentials to the West Texas Intermediate benchmark in the DJ Basin currently range from $11 to $14.

Mid-Continent Cotton Valley Program

The Mid-Continent region contributed 5,788 Boe/d, or 25% of total Company net sales volumes for second quarter 2014, comprised of 51% crude oil, 16% natural gas liquids and 33% natural gas. Sales volumes increased by approximately 13% over second quarter 2013. During the quarter, Bonanza Creek spud 12 gross (9.0 net) wells, performed 33 recompletions and tied 15 gross (10.8 net) wells into sales.

2014 Annual Guidance Update

The Company updated its 2014 annual guidance to incorporate the acquisition of approximately 34,000 net acres in the Wattenberg Field and its associated production.

 

Average production (Boe/d)			23,200 - 25,200
Operating costs and expenses (per Boe):
Lease operating		$	8.00 - 8.60
Cash general and administrative		$	6.25 - 7.00
Production taxes (% of pre-hedge realizations):		%	9.5 - 10.0
Capital expenditures (in millions):		$	575 - 625

The Company has adjusted its forecast for production taxes for 2014 from 6.5 to 7.0 percent of pre-hedge revenue to a range of 9.5 to 10.0 percent as a result of a loss of ad valorem tax credits related to low rate vertical well production.

Financial and Risk Management Update

As of June 30, 2014, the Company had a $1.0 billion revolving credit facility with a borrowing base of $525 million. The Company had a letter of credit totaling $36.0 million and cash totaling $36.6 million, resulting in total liquidity of $525.6 million. Concurrent with our $300 million offering of 5.75% senior notes which was completed on July 18^th, our borrowing base was reduced by $75 million to $450 million.

Commodity Derivatives Positions

The following table summarizes the Company's crude oil and natural gas commodity derivative positions as of August 1, 2014 and settling quarterly thereafter:

Settlement		Swap		Fixed		Collar		Average		Average		Average
Period		Volume		Price		Volume		Short Floor		Floor		Ceiling
Oil		Bbl/d		$		Bbl/d		$		$		$
Q3 2014		5,870		96.09		4,326				86.16		96.57
Q4 2014		6,370		95.62		4,326				86.16		96.57
Q3-Q4 2014						2,000		65.00		87.68		99.75
Q1 2015		6,000		95.39		6,500		68.08		84.32		95.90
Q2 2015		5,000		94.21		5,500		67.73		84.09		95.16
Q3-Q4 2015		2,000		93.43		6,500		68.46		84.62		95.49
FY 2016						5,500		70.00		85.00		96.83
Gas		MMBtu/d		$		MMBtu/d		$		$		$
Q3-Q4 2014						30,000		3.63		4.21		4.81
FY 2015						15,000		3.50		4.00		4.75

Conference Call Information

Bonanza Creek will host a conference call on Friday, August 8, 2014 at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time). To access the live interactive call, please dial (866) 825-1709 or (617) 213-8060 and use the passcode 82982957. This call is being webcast and can be accessed at Bonanza Creek's website www.bonanzacrk.com for one year after the event.

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 oil shale, and in southern Arkansas, focused on the oil-rich 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 the Company's capital program, drilling and development program, downspacing results and ability to secure firm transportation. 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; and access to adequate gathering systems and pipeline take-away capacity. 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, 2013 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:

Mr. Ryan Zorn
Vice President - Finance & Treasurer
720-440-6172

Mr. James Masters
Investor Relations Manager
720-440-6121

Schedule 1: Condensed Statements of Operations
(in thousands, expect for per share data, unaudited)

	Three Months Ended
	June 30
	2014		2013
NET REVENUES
Oil and gas sales	$  151,682		$    84,517
OPERATING EXPENSES
Lease operating	18,018		12,898
Severance and ad valorem taxes	16,263		5,352
Exploration	96		862
Depreciation, depletion and amortization	54,117		29,517
General and administrative (including $7,353 and $2,685 in 2014 and 2013, respectively, of stock compensation)	24,547		13,283
Total operating expenses	113,041		61,912
INCOME FROM OPERATIONS	38,641		22,605
OTHER INCOME (EXPENSE)
Derivative gain (loss)	(27,307)		7,562
Interest expense	(9,434)		(5,870)
Other income (loss)	167		(86)
Total other income (expense)	(36,574)		1,606
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	2,067		24,211
Income tax expense	(796)		(9,328)
INCOME FROM CONTINUING OPERATIONS	$     1,271		$   14,883
DISCONTINUED OPERATIONS
Loss from operations associated with oil and gas properties held for sale	-		(274)
Loss on sale of oil and gas properties	(184)		-
Income tax benefit	71		106
Loss from discontinued operations	(113)		(168)
NET INCOME	$     1,158		$   14,715
DILUTED INCOME PER SHARE
Income from continuing operations	$       0.03		$       0.37
Income (loss) from discontinued operations	$       0.00		$     (0.01)
Net income per common share	$       0.03		$       0.36
WEIGHTED AVERAGE NUMBER OF SHARES OF OUTSTANDING COMMON STOCK
Basic	39,758		39,336
Diluted	39,857		39,350

• 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 11 - Earnings per Share in the Form 10-Q, for a detailed calculation.

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

						Six Months Ended
						June 30
						2014		2013
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income					$   14,689		$ 25,971
Adjustments to reconcile net income to net cash
provided by operating activities:
	Depreciation, depletion and amortization					95,316		53,084
	Deferred income taxes					9,095		16,270
	Stock-based compensation					14,150		7,063
	Amortization of deferred financing costs					1,156		665
	Amortization of premium on Senior Notes					(614)		-
	Accretion of contractual obligation for land acquisition					381		381
	Derivative (gain) loss					36,085		(2,447)
	Gain on sale of oil and gas properties					(6,330)		-
	Other					(14)		-
Changes in current assets and liabilities:
	Accounts receivable					(32,385)		(9,343)
	Prepaid expenses and other assets					(2,575)		634
	Accounts payable and accrued liabilities					29,114		(1,377)
	Settlement of asset retirement obligations					(99)		(73)
		Net cash provided by operating activities				157,969		90,828
CASH FLOWS FROM INVESTING ACTIVITIES:
	Acquisition of oil and gas properties					(3,091)		(8,352)
	Proceeds from sale of oil and gas properties					6,000		-
	Exploration and development of oil and gas properties					(275,890)		(162,689)
	Natural gas plant capital expenditures					(271)		(3,987)
	Derivative cash settlements					(8,142)		(2,993)
	(Increase) decrease in restricted cash					(11,280)		79
	Additions to property and equipment - non oil and gas					(3,989)		(2,626)
		Net cash used in investing activities				(296,663)		(180,568)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from credit facility					-		33,500
	Payments to credit facility					-		(191,500)
	Proceeds from sale of Senior Notes					-		300,000
	Offering costs related to sale of senior subordinated notes					(277)		(7,270)
	Net share settlement from issuance of stock awards					(4,766)		(3,127)
	Deferred financing costs					(290)		(46)
		Net cash (used in) provided by financing activities				(5,333)		131,557
Net change in cash and cash equivalents						(144,027)		41,817
Cash and cash equivalents, beginning of period						180,582		4,268
Cash and cash equivalents, end of period						$   36,555		$ 46,085

Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)

	June 30,		December 31,
	2014		2013
Assets
Current assets	$     152,319		$      264,174
Oil and gas properties and gas plant, net	1,470,248		1,267,249
Other assets	24,548		14,152
Oil and gas properties held for sale, less accumulated depreciation, depletion, and amortization	-		360
Total Assets	$   1,647,115		$   1,545,935
Liabilities and Stockholders' Equity
Current liabilities	236,537		175,226
Long-term debt	530,647		530,880
Deferred taxes	161,776		152,681
Other long-term liabilities	38,055		31,120
Total Liabilities	$      967,015		$       889,907
Stockholders' Equity	680,100		656,028
Total Liabilities and Stockholders' Equity	$   1,647,115		$    1,545,935

Schedule 4: Volumes and Realized Prices
(unaudited)

	Three Months Ended
	June 30
	2014		2013
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains	12,163		5,902
Mid-Continent	2,962		2,845
Total	15,125		8,747
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$      90.59		$   86.02
Mid-Continent	100.84		96.44
Composite (before derivatives)	$      92.60		$   89.41
Composite (after derivatives)	$      88.31		$   87.41
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains	35		30
Mid-Continent	919		842
Total	954		872
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$      28.72		$   37.93
Mid-Continent	52.79		49.42
Composite (before derivatives)	$      51.89		$   49.03
Composite (after derivatives)	$      51.89		$   49.03
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains	29,183		14,547
Mid-Continent	11,445		8,688
Total	40,628		23,235
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$        5.53		$      4.62
Mid-Continent	4.84		4.21
Composite (before derivatives)	$        5.34		$      4.47
Composite (after derivatives)	$        5.33		$      4.52
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains	17,061		8,357
Mid-Continent	5,788		5,136
Total	22,849		13,493
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$      74.10		$   68.95
Mid-Continent	69.55		68.66
Composite (before derivatives)	$      72.95		$   68.83
Composite (after derivatives)	$      70.10		$   67.62
Total Sales Volumes (MBoe)	2,079.3		1,227.8

Schedule 5: 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 changes in unrealized gains and losses on unsettled derivative instruments, loss on sale of oil and gas properties and stock-based compensation, and then (2) these items' impact on taxes based on a tax rate of 38.5%, which approximates our effective tax rate. Adjusted Net Income is not a measure of net income as determined by GAAP.

The following table provides a reconciliation of net income (GAAP) to Adjusted Net Income (non-GAAP):

		Three Months Ended
		June 30
		2014		2013
Net Income		$      1,158		$   14,715
Derivative loss (gain)		27,307		(7,562)
Derivative cash settlements		(5,915)		(1,486)
Loss on sale of oil and gas properties		184		-
Stock-based compensation		7,353		2,685
Total adjustments before tax		28,929		(6,363)
Adjustment of income tax effect		11,138		(2,450)
Adjusted for income tax effects		17,791		(3,913)
Adjusted Net Income		$    18,949		$   10,802
Adjusted Net Income per diluted share		$        0.48		$      0.27

The Company also included a supplementary adjusted net income calculation to reflect exclusion of cash severance costs recorded during the quarter due to executive departures.

		Three Months Ended
		June 30
		2014		2013
Net Income		$    1,158		$   14,715
Derivative loss (gain)		27,307		(7,562)
Derivative cash settlements		(5,915)		(1,486)
Loss on sale of oil and gas properties		184		-
Severance costs		2,922		-
Stock-based compensation		7,353		2,685
Total adjustments before tax		31,851		(6,363)
Adjustment of income tax effect		12,263		(2,450)
Adjusted for income tax effects		19,588		(3,913)
Adjusted Net Income		$  20,746		$  10,802
Adjusted Net Income per diluted share		$      0.52		$      0.27

Schedule 6: 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, exploration expenses and other similar non-cash charges. Adjusted EBITDAX is not a measure of net income or cash flows as determined by United States Generally Accepted Accounting Principles, or GAAP.

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

		Three Months Ended
		June 30
		2014		2013
Net Income		$    1,158		$  14,715
Exploration		96		870
Depreciation, depletion and amortization		54,117		29,617
Stock-based compensation		7,353		2,685
Loss on sale of oil and gas properties		184		-
Interest expense		9,434		5,870
Derivative loss (gain)		27,307		(7,562)
Derivative cash settlements		(5,915)		(1,486)
Income tax expense		725		9,222
Adjusted EBITDAX		$  94,459		$  53,931

The Company also included a supplementary adjusted EBITDAX calculation to reflect exclusion of cash severance costs recorded during the quarter due to executive departures.

		Three Months Ended
		June 30
		2014		2013
Net Income		$    1,158		$  14,715
Exploration		96		870
Depreciation, depletion and amortization		54,117		29,617
Severance costs		2,922		-
Non-cash stock-based compensation		7,353		2,685
Loss on sale of oil and gas properties		184		-
Interest expense		9,434		5,870
Derivative loss (gain)		27,307		(7,562)
Derivative cash settlements		(5,915)		(1,486)
Income tax expense		725		9,222
Adjusted EBITDAX		$  97,381		$  53,931