Bonanza Creek Energy Announces Third Quarter 2014 Financial Results and Provides an Operations Update

DENVER, November 6, 2014 - Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported its third quarter 2014 operating and financial results.

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

• 44% increase in sales volumes to 25,505 Boe/d; 69% crude oil and liquids
• 24% increase in revenue to $156.4 million
• 14% decrease in per unit cash operating costs⁽²⁾
• 174% increase in net income to $48.8 million, or $1.18 per diluted share; excluding the impact of certain items such as derivative gains, adjusted net income⁽³⁾  was $18.9 million, or $0.46 per diluted share
• 27% increase in adjusted EBITDAX⁽³⁾ to $110.4 million

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 third quarter 2013 are presented as continuing operations. 
2. Cash operating costs include lease operating expense and cash general and administrative expense, a non-GAAP measure. See Schedule 1 for general and administrative break-out of stock-based compensation.
3. Non-GAAP measure; see attached Reconciliation Schedules.

Operational highlights for third quarter 2014 include:

• 40-acre spaced Niobrara B bench pad achieved an average initial 90-day production rate of 416 Boe/d; after 200 days, all four wells are tracking above the 313 Mboe type curve
• Drilled and completed the Company's first Niobrara A bench well; its initial 30-day production rate was 325 Boe/d
• Successfully drilled and completed two 9,000 foot laterals and both are in the first month of production

Marvin Chronister, Bonanza Creek's Interim President and Chief Executive Officer, commented, "I am pleased with our progress towards our 2014 goals, particularly with respect to per unit operating costs. Despite downtime issues experienced due to Wattenberg Field gas compression and processing infrastructure, we are well-positioned to execute on all of our strategic priorities this year. Our evolution in completion design continues to encourage and has established an attractive economic baseline that supports our 3P inventory assumptions. The detailed analysis performed on the acquisition acreage over the past several months confirms our inventory assumption of approximately 700 net locations made back in July and we are eager to begin our drilling efforts there in the fourth quarter. Furthermore, our catalyst well program has shown positive results in the thinner Codell, the Niobrara A bench and extended reach laterals. We are keeping a close eye on macro oil price conditions as we plan our budget for 2015 but we are confident that our program achieves attractive economic returns at current levels and are planning for another exciting year of value creation for our shareholders."

Third Quarter 2014 Financial Results

Average realized prices for third quarter 2014, before the effect of commodity derivatives, were $85.78 per Bbl of oil, $4.76 per Mcf of natural gas and $49.03 per Bbl of NGLs, compared to $100.37 per Bbl of oil, $4.58 per Mcf of natural gas and $55.14 per Bbl of NGLs for third quarter 2013.

Net revenue for third quarter 2014 was $156.4 million, compared to $126.0 million for third quarter 2013. Crude oil and liquids revenue accounted for approximately 87% of total revenue.

Lease operating expense ("LOE") for third quarter 2014 was $18.2 million, or $7.76 per Boe, compared to $13.0 million, or $7.98 per Boe, for third quarter 2013.

General and administrative expense ("G&A") for third quarter 2014 was $14.8 million, or $6.31 per Boe, compared to $13.8 million, or $8.50 per Boe, for third quarter 2013. Cash G&A⁽²⁾ was $11.7 million, or $4.97 per Boe, compared to $11.2 million, or $6.87 per Boe, for third quarter 2013.

Severance and ad valorem taxes for third quarter 2014 were $15.3 million, or $6.54 per Boe, compared to $8.1 million, or $4.98 per Boe, for third quarter 2013.

Net income for third quarter 2014 was $48.8 million, or $1.18 per diluted share, compared to $17.8 million, or $0.44 per diluted share for third quarter 2013. Adjusted net income⁽²⁾ for third quarter 2014 was $18.9 million, or $0.46 per diluted share, compared to adjusted net income of $25.6 million, or $0.65 per diluted share for third quarter 2013.

Operations Update

During third quarter 2014, the Company achieved an average production rate of 25,505 Boe/d, comprised of 65% crude oil, 4% NGLs, and 31% natural gas.

Rocky Mountain Region - Wattenberg Horizontal Development

The Rocky Mountain region contributed 19,531 Boe/d, or 77% of total Company net sales volumes for the quarter, comprised of 70% crude oil and 30% liquids-rich natural gas. Sales volumes increased by approximately 65% over third quarter 2013.

During the quarter, the Company spud 30 gross (24.8 net) wells and placed 27 gross (23.0 net) operated wells into sales.

Catalyst Drilling Program

The Company continues to evaluate the performance of its four well pad spaced at 40-acres in the Niobrara B bench, in which the two internal wells were completed with 28 stages. The 90-day production rate was 416 Boe/d, compared to an average 60-day rate of 463 Boe/d and a 30-day rate of 477 Boe/d. As a consequence, all four wells are still tracking above the Company's target type curve for an 80-acre spaced well. A five well pad targeting both the Niobrara B and C benches at 40-acre spacing, utilizing 28-stage completions in each well, was successfully drilled and completed and is in early flowback.

The Company drilled and completed its first Niobrara A bench well, reporting an average initial 30-day production rate of 325 Boe/d. This well was drilled to a lateral length of approximately 4,000 feet and completed using the traditional 18 sliding sleeve stages and 4 million pounds of sand. No 3P inventory or reserves are currently assigned to the Niobrara A bench.

The Company reported that its eastern Codell well, targeting a net pay thickness of six feet, had an initial average 60-day production rate of 343 Boe/d, a 19% decline from its 30-day production rate of 426 Boe/d. The Company expects to spud its second eastern step-out well and a two well pad testing 80 acre downspacing in the fourth quarter.

Extended and medium reach laterals continue to perform as expected. During the third quarter, the Company successfully drilled and completed two 9,000 foot lateral wells in the Niobrara B bench. These wells are currently on early flowback and six are scheduled to drill in the fourth quarter, including a five well pad of 7,500 foot laterals drilled to the Niobrara B, C and Codell.

Midstream and Crude Marketing Update

The Company reached two agreements to secure firm transportation capacity on interstate pipelines that will transport crude oil from the DJ Basin to Cushing, OK.  In total, these agreements provide the Company approximately 27,500 Bbl/d (gross) of takeaway capacity by year-end 2016, of which, 12,580 Bbl/d is expected to be available by the second quarter of 2015.  Both agreements provide for oil realizations of NYMEX less approximately $10 based on trucking distance to pipeline input points, fixed pipeline tariffs and marketing fees.    

For the fourth quarter, the Company expects its differentials in the DJ Basin to be approximately $11.00 to $13.00 per barrel off of WTI.

During the third quarter, the Company experienced periods in late August and early September of third party midstream downtime. To date in the fourth quarter, inconsistent midstream performance has again negatively impacted sales volumes. The Company has revised its annual production guidance accordingly, reflected in the 2014 Annual Guidance Update table below. 

Mid-Continent Cotton Valley Program

The Mid-Continent region contributed 5,974 Boe/d, or 23% of total Company net sales volumes for third quarter 2014, comprised of 50% crude oil, 18% natural gas liquids and 32% natural gas. During the quarter, Bonanza Creek spud 14 gross (12.8 net) wells, performed 29 recompletions and tied 12 gross (10.0 net) wells into sales.

Capital Spending Update

The Company is increasing its 2014 capital budget by approximately $55 million, of which approximately 60% is allocated to various drilling and completion activities, including drilling one well and completing three wells on the recently acquired acreage and additional testing of completion techniques; 25% to leasing and acquisition of seismic, and the remaining 15% to infrastructure investment that will enhance line pressure efficiencies on our acreage.

2014 Annual Guidance Update

The Company updated its annual guidance for production, cash expenses, and production taxes. It alsoadjusted the range for capital expenditures to account for the incremental activities discussed above.

Average production (Boe/d)			23,200 - 24,200
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):		$	630 - 680

Financial and Risk Management Update

On September 30, 2014, the Company's $1.0 billion revolving credit facility was amended to increase its borrowing base from $450 million to $600 million. The Company elected to limit bank commitments to $500 million while reserving the option to access, at the Company's request, the full $600 million prior to the next semi-annual redetermination. The Company has a letter of credit totaling $24.0 million and cash totaling $92.6 million, resulting in total liquidity of $668.6 million.

Commodity Derivatives Positions

The following table summarizes the Company's crude oil and natural gas commodity derivative positions as of November 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		$		$		$
Q4 2014		6,370		95.62		4,326				86.16		96.57
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		$		$		$
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, November 7, 2014 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). To access the live interactive call, please dial (877) 415-3181 or (857) 244-7324 and use the passcode 99057635. 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 3P inventory and reserves assumptions, capital program, drilling and development program, downspacing results and midstream transportation arrangements. 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

Senior 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
	September 30
	2014		2013
NET REVENUES
Oil and gas sales	$  156,371		$  125,973
OPERATING EXPENSES
Lease operating	18,217		12,958
Severance and ad valorem taxes	15,334		8,086
Exploration	3,291		2,099
Depreciation, depletion and amortization	63,241		36,750
General and administrative (including $3,162 and $2,652 in 2014 and 2013, respectively, of stock-based compensation)	14,814		13,811
Total operating expenses	114,897		73,704
INCOME FROM OPERATIONS	41,474		52,269
OTHER INCOME (EXPENSE)
Derivative gain (loss)	50,846		(16,890)
Interest expense	(13,228)		(6,180)
Other income (loss)	181		(53)
Total other income (expense)	37,799		(23,123)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	79,273		29,146
Income tax expense	(30,419)		(11,221)
INCOME FROM CONTINUING OPERATIONS	$  48,854		$  17,925
DISCONTINUED OPERATIONS
Loss from operations associated with oil and gas properties held for sale	-		(234)
Loss on sale of oil and gas properties	(117)		-
Income tax benefit	45		90
Loss from discontinued operations	(72)		(144)
NET INCOME	$  48,782		$  17,781
DILUTED INCOME PER SHARE
Income from continuing operations	$  1.18		$  0.44
Income (loss) from discontinued operations	$  0.00		$  0.00
Net income per common share	$  1.18		$  0.44
WEIGHTED AVERAGE NUMBER OF SHARES OF OUTSTANDING COMMON STOCK
Basic	40,556		39,356
Diluted	40,708		39,375

 

• 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)

							Nine Months Ended
							September 30
							2014		2013
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income						$ 63,471		$43,752
Adjustments to reconcile net income to net cash
provided by operating activities:
	Depreciation, depletion and amortization						158,557		89,897
	Deferred income taxes						39,369		27,402
	Stock-based compensation						17,312		9,716
	Amortization of deferred financing costs						1,953		1,120
	Amortization of premium on Senior Notes						(921)		-
	Accretion of contractual obligation for land acquisition						571		571
	Derivative (gain) loss						(14,761)		14,443
	Abandoned lease						-		1,688
	Gain on sale of oil and gas properties						(6,213)		-
	Other						(12)		-
Changes in current assets and liabilities:
	Accounts receivable						(23,837)		(32,081)
	Prepaid expenses and other assets						(2,286)		726
	Accounts payable and accrued liabilities						43,133		33,961
	Settlement of asset retirement obligations						(374)		(73)
		Net cash provided by operating activities					275,962		191,122
CASH FLOWS FROM INVESTING ACTIVITIES:
	Acquisition of oil and gas properties						(178,883)		(10,969)
	Proceeds from sale of oil and gas properties						6,000		-
	Payments of contractual obligations						(12,000)		(12,000)
	Exploration and development of oil and gas properties						(448,586)		(306,685)
	Natural gas plant capital expenditures						(281)		(4,459)
	Derivative cash settlements						(9,136)		(9,867)
	(Increase) decrease in restricted cash						(3,062)		79
	Additions to property and equipment - non oil and gas						(5,451)		(3,695)
		Net cash used in investing activities					(651,399)		(347,596)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from credit facility						230,000		72,000
	Payments to credit facility						(230,000)		(191,500)
	Proceeds from sale of Senior Notes						300,000		300,000
	Offering costs related to sale of Senior Notes						(6,867)		(7,343)
	Payment of employee tax withholdings in exchange for the return of common stock						(5,319)		(3,503)
	Deferred financing costs						(341)		(79)
		Net cash provided by financing activities					287,473		169,575
Net change in cash and cash equivalents							(87,964)		13,101
Cash and cash equivalents, beginning of period							180,582		4,268
Cash and cash equivalents, end of period							$  92,618		$17,369

Schedule 3: Condensed Balance Sheet

(in thousands, unaudited)

 

	September 30,		December 31,
	2014		2013
Assets
Current assets	$  214,075		$   264,174
Oil and gas properties and gas plant, net	1,823,208		1,267,249
Other assets	28,948		14,152
Oil and gas properties held for sale, less accumulated depreciation, depletion, and amortization	-		360
Total Assets	$  2,066,231		$  1,545,935
Liabilities and Stockholders' Equity
Current liabilities	230,519		175,226
Long-term debt	818,530		530,880
Deferred taxes	192,050		152,681
Other long-term liabilities	44,590		31,120
Total Liabilities	$  1,285,689		$  889,907
Stockholders' Equity	780,542		656,028
Total Liabilities and Stockholders' Equity	$  2,066,231		$  1,545,935

 

Schedule 4: Volumes and Realized Prices

(unaudited)

 

	Three Months Ended
	September 30
	2014		2013
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains	13,606		8,736
Mid-Continent	2,965		2,988
Total	16,571		11,724
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$  83.81		$  97.80
Mid-Continent	94.79		107.88
Composite (before derivatives)	$  85.78		$ 100.37
Composite (after derivatives)	$  84.74		$  93.92
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains	56		40
Mid-Continent	1,079		1,022
Total	1,135		1,062
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$  23.08		$  20.52
Mid-Continent	50.38		56.48
Composite (before derivatives)	$  49.03		$  55.14
Composite (after derivatives)	$  49.03		$  55.14
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains	35,214		18,156
Mid-Continent	11,581		11,058
Total	46,794		29,214
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$  4.98		$  5.05
Mid-Continent	4.08		3.79
Composite (before derivatives)	$  4.76		$  4.58
Composite (after derivatives)	$   4.89		$  4.61
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains	19,531		11,802
Mid-Continent	5,974		5,854
Total	25,505		17,656
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$  67.44		$  80.26
Mid-Continent	64.05		72.10
Composite (before derivatives)	$  66.64		$  77.54
Composite (after derivatives)	$  66.22		$  73.31
Total Sales Volumes (MBoe)	2,346.4		1,624.3

 

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
		September 30
		2014		2013
Net Income		$  48,782		$ 17,781
Derivative loss (gain)		(50,846)		16,890
Derivative cash settlements		(994)		(6,874)
Loss on sale of oil and gas properties		117		-
Stock-based compensation		3,162		2,652
Total adjustments before tax		(48,561)		12,668
Adjustment of income tax effect		(18,696)		4,877
Adjusted for income tax effects		(29,865)		7,791
Adjusted Net Income		$  18,917		$ 25,572
Adjusted Net Income per diluted share		$  0.46		$  0.65

 

 

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
		September 30
		2014		2013
Net Income		$  48,782		$  17,781
Exploration		3,291		2,099
Depreciation, depletion and amortization		63,241		36,812
Stock-based compensation		3,162		2,652
Loss on sale of oil and gas properties		117		-
Interest expense		13,228		6,180
Derivative loss (gain)		(50,846)		16,890
Derivative cash settlements		(994)		(6,874)
Income tax expense		30,374		11,131
Adjusted EBITDAX		$110,355		$  86,671

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