Bonanza Creek Energy Announces First Quarter 2015 Financial and Operating Results

DENVER, May 7, 2015 - Bonanza Creek Energy, Inc. BCEI today reported its first quarter 2015 financial and operating results. The Company previously announced it reached agreement with its gas processing providers in the Rocky Mountain region to realize operated sales volumes in three streams (oil, NGLs and natural gas) effective January 1, 2015. Unless noted, all references to barrel of oil equivalent (boe) volumes related to activities completed in the Rocky Mountain region during 2014 have incorporated 6:1 gas to liquids conversion of two-stream (oil and wet gas) volumes.

Highlights from first quarter 2015 include:

• Sales volumes grew to 27.5 Mboe/d representing a 30% increase compared to estimated 3-stream sales volumes in the first quarter of 2014⁽¹⁾
• Increased Rocky Mountain production by 41% compared to first quarter 2014⁽¹⁾, to 21.9 Mboe/d
• Cumulative production of 40-acre Niobrara wells with 28 stage fracs consistent with 354 MBoe target type curve
• Cash operating costs (LOE, production taxes and G&A) of $15.83 per Boe
• Adjusted EBITDAX⁽²⁾ of $69.3 million
• Adjusted net loss⁽²⁾ of $2.7 million, or $0.06 per share
• Total capital costs incurred of $123.4 million, down approximately 20% from first quarter 2014
• Liquidity at March 31 of $646.5 million
• Formation of a wholly-owned Wattenberg midstream development entity
• BCEI employees achieved over 1.2 million worker-hours with no lost time injury incidents

(1) Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or held for sale as of March 31, 2014. First 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.

(2) Non-GAAP measure, see attached Reconciliation Schedules. With respect to Cash G&A, see Schedule 1 for general and administrative break-out of stock-based compensation.

 

Richard Carty, President and Chief Executive Officer, commented on the Company's financial and operating results, "We are pleased with the underlying performance of our asset base during the first quarter. Everyone in the energy sector is adjusting to a radically different commodity price environment and the Bonanza Creek team has ably adapted to meet the challenges that these conditions present to our business. Compared to 2014 levels, our recurring efficiency initiatives and external service cost reductions have yielded a reduction in well costs by approximately 20% in the Wattenberg Field.  Wells with 4,000 foot laterals completed with 25 frac stages are now projected to cost approximately $3.6 million, and 9,000 foot laterals target $5.9 million costs. As our cash operating costs of $15.83 per Boe demonstrate, our contiguous leasehold position is proving to be a critical benefit to us during this time of depressed oil prices, enabling capital efficiencies as a result of our ability to drill wells into de-risked areas, drill multiple wells on scalable pads and co-locate new wells with previously installed surface infrastructure. Consistent with our previously disclosed 2015 plan, we are now running two rigs in the Wattenberg and expect to hold this activity flat through the end of the year. Although we are not adjusting any elements of our guidance for the full year at this time, we expect average well costs in 2015 to be below the assumptions that underpinned our capital activity budget of $400-420 million when announced in early January."

First Quarter 2015 Financial Results

Net revenue for first quarter 2015 was $73.1 million, compared to $127.4 million for first quarter 2014. Crude oil and liquids accounted for approximately 89% of total revenue.

Average realized prices for first quarter 2015, before the effect of commodity derivatives, were $39.87 per Bbl of oil, $2.28 per Mcf of natural gas and $14.14 per Bbl of NGLs, compared to $89.11 per Bbl of oil, $5.99 per Mcf of natural gas and $54.53 per Bbl of NGLs for first quarter 2014.

Lease operating expense for first quarter 2015 was $19.3 million, or $7.78 per Boe, compared to $17.1 million, or $9.63 per Boe ($8.99 per Boe adjusted for estimated 3-stream volumes), for first quarter 2014.

General and administrative expense ("G&A") for first quarter 2015 was $16.9 million, or $6.81 per Boe, compared to $23.7 million, or $13.37 per Boe ($12.48 per Boe adjusted for estimated 3-stream volumes), for first quarter 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense)⁽²⁾ was $13.4 million, or $5.43 per Boe for the first quarter of 2015 compared to $16.9 million, or $9.54 per Boe for first quarter 2014. First quarter 2014 G&A was impacted by executive departure costs of approximately $7.5 million, of which $3.6 million was cash. Not including departure costs, cash G&A for the first quarter 2014 was $13.3 million, or $7.51 per Boe ($7.00 per Boe adjusted for estimated 3-stream volumes).

Depreciation, depletion and amortization for first quarter 2015 was $59.0 million, or $23.83 per Boe, compared to $41.1 million, or $23.20 per Boe ($21.65 per Boe adjusted for estimated 3-stream volumes), for the first quarter 2014.

Interest expense for first quarter 2015 was $14.2 million compared to $9.3 million for the first quarter 2014.

Adjusted EBITDAX⁽²⁾ for first quarter 2015 was $69.3 million, compared to $80.5 million for the first quarter 2014.

First quarter 2015 earnings included non-cash mark-to-market losses on derivatives of $16.6 million before tax, or $0.37 per diluted share.

First quarter 2015 earnings also included non-cash, pre-tax charges of $5.5 million related to the impairment of unproved properties within the Wattenberg Field resulting from lease expiration during the quarter.

Reported net loss for first quarter 2015 was $18.4 million, or $0.41 per diluted share, compared to net income of $13.5 million, or $0.34 per diluted share, for first quarter 2014. Adjusted net loss⁽²⁾ for first quarter 2015 was $2.7 million, or $0.06 per diluted share, compared to adjusted net income of $18.4 million, or $0.46 per diluted share for first quarter 2014.

Operations Update

During first quarter 2015, the Company achieved average sales volumes of 27.5 Mboe/d, comprised of 60% crude oil, 16% NGLs and 24% natural gas, increasing total sales volumes by 30% over estimated 3-stream volumes in the first quarter of 2014. Total capital costs incurred during the first quarter totaled $123.4 million which represents approximately 30% of the Company's capital budget for 2015.

Rocky Mountain Region - Wattenberg Horizontal Development

During first quarter 2015, the Rocky Mountain region sold 21.9 Mboe/d, or 80% of total Company volumes, with over 95% coming from horizontal wells. On a 3-stream basis, sales volumes were up 41% compared to the first quarter of 2014 and increased by 3% compared to the fourth quarter of 2014. Capital costs incurred for the region were $111.7 million for the quarter.

The Company spud 30 gross operated (23.4 net) horizontal wells and tied 30 gross operated (20.5 net) horizontal wells into sales during the quarter. Non-operated activity for the quarter included no spud activity but 2 gross (0.1 net) wells tied into sales. Compared to the Company's budget for 2015, the pace of spud activity moved 5 gross (3.6 net) wells ahead of plan during March as field operating conditions were favorable and rig efficiencies improved. During the first quarter, we spud 9 gross (7.9 net) operated extended reach lateral wells. Utilizing fit-for-purpose rigs, batch drilling on multi-well pads has resulted in spud-to-rig release times of 10-11 days for 9,000 foot lateral wells compared to 15-17 days during 2014.

The number of wells tied into sales was in-line with the Company's plan for the quarter. The pace of well tie-ins was weighted to activity during February and March as January accounted for 15% of the net wells that began flowback during the quarter. For the remainder of the year, the Company expects to tie-in approximately 18-23 gross (15-20 net) wells per quarter.

The Company continues to be pleased with the growing set of extended production histories on catalyst wells drilled in 2014. We have 14 Niobrara B and C bench wells drilled on 40-acre spacing and completed with 28 frac stages. In aggregate, the cumulative production from these laterals is proximal to the cumulative production profile represented in our 354 Mboe (3-stream) target type curve. In the Codell, our first well to test thinner net pay (less than eight feet) is nearly one year old and is tracking to a 300 MBoe (3-stream) recovery. A second Codell well drilled into less than eight feet of net pay is in early stages of flowback.

Differentials to WTI in the Wattenberg Field have decreased to an average of $10 per Bbl during the first quarter compared to $12 per Bbl during the fourth quarter of 2014. The Company expects incremental improvement over the remainder of 2015 into the $9 to $10 per Bbl range. On May 1, 2015, the Company began shipping 12,500 Bbls/d (gross) on the Pony Express Pipeline.

On April 30, 2015, the company consolidated its Pronghorn and 70 Ranch gas gathering and compression systems in the Wattenberg Field into a new, wholly-owned subsidiary, Rocky Mountain Infrastructure, LLC.  This midstream subsidiary will serve as an operating platform from which the Company intends to facilitate the development of surface infrastructure in concert with the demands of its upstream business.

Mid-Continent Region - Cotton Valley Development

The Mid-Continent region contributed 5.6 Mboe/d, or 20% of total Company net sales volumes for first quarter 2015, comprised of 52% crude oil, 18% NGLs and 30% natural gas. Sales volumes were flat compared to the first quarter of 2014, but decreased by 15% compared to the fourth quarter of 2014. Capital costs incurred for the region were $10.2 million for the quarter.

During the first quarter 2015, Bonanza Creek spud 9 gross (7.0 net) Cotton Valley wells, tied 5 gross (3.3 net) wells into sales and performed 17 gross (15.7 net) recompletions.

Sales volumes were down compared to the fourth quarter of 2014 due to a 50% cut in the number of recompletions executed. In addition, sales volumes in the fourth quarter benefited from several recompletions that produced at higher than average initial rates and then experienced steeper than average declines into the first quarter. For the remainder of 2015, the Company expects to maintain a similar pace of drilling and recompletions as performed in the first quarter.

Financial and Risk Management Update

Debt and Liquidity

As of March 31, 2015, Bonanza Creek had a $1.0 billion revolving credit facility with an undrawn borrowing base of $600 million. The Company elected to limit bank commitments to $500 million while reserving the option to access the full $600 million, at the Company's request. The Company had a letter of credit totaling $24.0 million and cash totaling $70.5 million, resulting in total liquidity of $646.5 million. The Company expects to report the results of its Spring 2015 bank redetermination in mid-May. Net debt to trailing 12-month EBITDAX equaled 2.2x.

Commodity Derivatives Positions

The following table summarizes the Company's crude oil and natural gas commodity derivative positions as of May 1, 2015 and settling quarterly:

Settlement		Swap		Fixed		Collar		Average		Average		Average
Period		Volume		Price		Volume		Short Floor		Floor		Ceiling
Oil		Bbl/d		$		Bbl/d		$		$		$
Q2 2015		5,000		94.41		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		$		$		$
Q2-Q4 2015						15,000		3.50		4.00		4.75

Conference Call Information

Bonanza Creek will host a conference call on Friday, May 8, 2015 at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time). To access the live interactive call, please dial (877) 299-4454 or (617) 597-5447 and use the passcode 74944642. 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 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 projected well costs and impact on the Company's 2015 capital budget, anticipated tie-in, drilling and recompletion activity, differentials to WTI and timing of release of the Company's spring 2015 bank redetermination. 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.

For further information, please contact:

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

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

	Three Months Ended
	March 31
	2015		2014
OPERATING NET REVENUES
Oil and gas sales	$  73,076		$   127,395
OPERATING EXPENSES
Lease operating	19,264		17,082
Severance and ad valorem taxes	6,496		10,749
Exploration	498		1,083
Depreciation, depletion and amortization	59,004		41,132
Abandonment and impairment of unproved properties	5,469		---
General and administrative (including $3,427 and $6,797 in 2015 and 2014, respectively, of stock-based compensation)	16,872		23,714
Total operating expenses	107,603		93,760
INCOME (LOSS) FROM OPERATIONS	(34,527)		33,635
OTHER INCOME (EXPENSE)
Derivative gain (loss)	18,856		(8,778)
Interest expense	(14,238)		(9,335)
Other income (loss)	(49)		51
Total other (expense) income	4,569		(18,062)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE TAXES	(29,958)		15,573
Income tax benefit (expense)	11,537		(5,996)
INCOME (LOSS) FROM CONTINUING OPERATIONS	$   (18,421)		$   9,577
DISCONTINUED OPERATIONS
Loss from operations associated with oil and gas properties held for sale	---		(85)
Gain on sale of oil and gas properties	---		6,514
Income tax expense	---		(2,475)
Gain from discontinued operations	---		3,954
NET INCOME (LOSS)	$   (18,421)		$   13,531
DILUTED INCOME PER SHARE
Income (loss) from continuing operations	$   (0.41)		$   0.24
Income from discontinued operations	$  ---		$   0.10
Net income (loss) per common share	$   (0.41)		$   0.34
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK
Basic	44,520		39,605
Diluted	44,520		39,762

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
						March 31,
						2015		2014
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income (loss)					$  (18,421)		$   13,531
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
	Depreciation, depletion and amortization					59,004		41,199
	Deferred income taxes					(11,537)		8,471
	Abandonment and impairment of unproved properties					5,469		---
	Stock-based compensation					3,427		6,797
	Amortization of deferred financing costs and debt premium					523		255
	Accretion of contractual obligation for land acquisition					349		190
	Derivative (gain) loss					(18,856)		8,778
	Gain on sale of oil and gas properties					---		(6,514)
	Other					(27)		(2)
Changes in current assets and liabilities:
	Accounts receivable					16,298		(12,721)
	Prepaid expenses and other assets					(1,873)		(2,637)
	Accounts payable and accrued liabilities					(1,981)		20,337
	Settlement of asset retirement obligations					(285)		---
		Net cash provided by operating activities				32,090		77,684
CASH FLOWS FROM INVESTING ACTIVITIES:
	Acquisition of oil and gas properties					(11,382)		(1,202)
	Proceeds from sale of oil and gas properties					---		6,000
	Exploration and development of oil and gas properties					(154,300)		(123,835)
	Natural gas plant capital expenditures					(112)		(194)
	Derivative cash settlements					35,466		(2,227)
	Additions to property and equipment - non oil and gas					(1,490)		(838)
		Net cash used in investing activities				(131,818)		(122,296)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from credit facility					44,000		--
	Payments to credit facility					(77,000)		---
	Offering costs related to sale of Senior Notes					(19)		(140)
	Proceeds from sale of common stock					209,300		---
	Offering costs related to the sale of common stock					(6,492)		---
	Payment of employee tax withholdings in exchange for the return of common stock					(2,127)		(4,461)
	Deferred financing costs					(4)		(26)
		Net cash (used in) provided by financing activities				167,658		(4,627)
Net change in cash and cash equivalents						67,930		(49,239)
Cash and cash equivalents, beginning of period						2,584		180,582
Cash and cash equivalents, end of period						$  70,514		$  131,343

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

	March  31,		December 31
	2015		2014
ASSETS
Current assets	$  247,755		$  208,475
Total property and equipment, net	1,816,000		1,756,477
Other assets	50,995		41,137
Total Assets	$  2,114,750		$  2,006,089
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities	$  161,219		$  198,447
Long-term debt	807,313		840,619
Deferred income taxes, net	154,129		165,667
Other long-term liabilities	66,323		61,285
Total Liabilities	$  1,188,984		$  1,266,018
Stockholders' Equity	925,766		740,071
Total Liabilities and Stockholders' Equity	$  2,114,750		$  2,006,089

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

	Three Months Ended
	March 31,
	2015		3-Stream 2014 (1)		2-Stream 2014
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains	13,674		9,987		9,987
Mid-Continent	2,887		2,949		2,949
Total	16,561		12,936		12,936
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$  38.28				$  86.72
Mid-Continent	47.40				97.21
Composite (before derivatives)	$  39.87				$  89.11
Composite (after derivatives)	$  63.21				$  87.65
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains	3,460		2,417		39
Mid-Continent	993		1,006		1,006
Total	4,453		3,423		1,045
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$  13.67				$  27.12
Mid-Continent	15.77				55.59
Composite (before derivatives)	$  14.14				$  54.53
Composite (after derivatives)	$  14.14				$  54.53
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains	28,815		18,614		24,438
Mid-Continent	10,155		9,887		9,887
Total	38,970		28,501		34,325
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$  1.95				$  6.27
Mid-Continent	3.21				5.31
Composite (before derivatives)	$  2.28				$  5.99
Composite (after derivatives)	$   2.47				$  5.82
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains	21,936		15,506		14,099
Mid-Continent	5,573		5,602		5,602
Total	27,509		21,109		19,701
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$  28.58				$  72.37
Mid-Continent	33.22				70.52
Composite (before derivatives)	$  29.52				$  71.85
Composite (after derivatives)	$  43.84				$  70.59
Total Sales Volumes (MBoe)	2,475.8		1,899.8		1,773.1

(1) First 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: 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, impairment of oil and gas properties, and other similar non-cash charges, and then (2) the non-cash 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 (Loss) Income (GAAP) to Adjusted Net (Loss) Income (non-GAAP):

		Three Months Ended
		March 31,
		2015		2014
Net (Loss) Income		$  (18,421)		$  13,531
Adjustments to Net (Loss) Income:
Derivative (gain) loss		(18,856)		8,778
Derivative cash settlements		35,466		(2,227)
Gain on sale of oil and gas properties		---		(6,514)
Abandonment and impairment of unproved properties		5,469		---
Exploratory dry hole cost		---		1,044
Stock-based compensation		3,427		6,797
Total pre-tax adjustments		25,506		7,878
Income tax effect		9,820		3,033
Total after-tax adjustments		15,686		4,845
Adjusted net (loss) income		$  (2,735)		$   18,376
Adjusted net income per diluted share		$  (0.06)		$  0.46
Weighted Average Number of Shares		44,520		39,762

Schedule 6: 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 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 (Loss) Income to the non-GAAP financial measure of Adjusted EBITDAX.

		Three Months Ended
		March 31,
		2015		2014
Net (Loss) Income		$  (18,421)		$  13,531
Exploration		498		1,083
Depreciation, depletion and amortization		59,004		41,199
Abandonment and impairment of unproved properties		5,469		---
Stock-based compensation		3,427		6,797
Gain on sale of oil and gas properties		---		(6,514)
Interest expense		14,238		9,335
Derivative (gain) loss		(18,856)		8,778
Derivative cash settlements		35,466		(2,227)
Income tax (benefit) expense		(11,537)		8,471
Adjusted EBITDAX		$  69,288		$  80,453

Schedule 7: Estimated 2014 Rocky Mountain 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
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