Civitas Resources (CIVI) 8-K Results of Operations and Financial Condition

Exhibit 99.1

Bonanza Creek Energy Announces Fourth Quarter and 2013 Financial Results; Sales Volumes Exceed Annual Guidance, Proved Reserves Increase 32% and Wattenberg Horizontal 3P Reserves Increase 30%

DENVER, February 27, 2014 — Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported its fourth quarter and full year 2013 financial and operating results in conjunction with the release of its year-end 2013 proved reserves as prepared by its independent third party reserve engineer, Netherland, Sewell & Associates, Inc. The Company also updated its 3P reserves analysis, reporting increased EUR assumptions and inventory count for its Niobrara and Codell potential.

Key highlights from continuing operations(1) for the fourth quarter 2013 include:

·Achieved sales volumes of 21,119 barrels of oil equivalent per day (Boe/d)

·Production in the Rocky Mountain region of 15,036 Boe/d, 95% from horizontal wells

·Production in the Mid-Continent region of 6,083 Boe/d

·Financial performance compared to fourth quarter 2012:

·Net revenue of $133.1 million, an increase of 81%

·Adjusted EBITDAX(2) of $99.5 million, an increase of 84%

·Unit cash margin(2) of $51.98 per Boe, an increase of 6%

·Net income of $25.4 million, or $0.63 per diluted share, an increase of 95%

·Adjusted net income(2) of $25.5 million, or $0.65 per diluted share, an increase of 62%

Significant achievements from continuing operations(1) for full year 2013 include:

·Production volumes of 16,172 Boe/d exceeded the top end of annual guidance and increased 75% over 2012

·Rocky Mountain production volumes increased 132% and Mid-Continent production increased 18% over 2012

·Booked year-end proved reserves of approximately 70 MMBoe, a 32% increase over year-end 2012, with reserve replacement of 393%

·Wattenberg horizontal 3P reserves increased from 237 MMBoe to 308 MMBoe and inventory increased by 314 gross locations to 1,841 gross locations

·Added approximately 4,500 net acres in the Wattenberg Field for a total of 35,500 net acres

·Outstanding safety performance record with a Lost Time Incident rate of 0.00

·Financial performance compared to full year 2012:

·Net revenue of $421.9 million, an increase of 82%

·Adjusted EBITDAX(2) of $292.4 million, an increase of 80%

·Unit cash margin(2) of $51.50 per Boe, an increase of 9%

·Net income of $69.2 million, or $1.71 per diluted share, an increase of 49%

·Adjusted net income(2) of $78.0 million, or $1.98 per diluted share, an increase of 49%

(1)Bonanza Creek began the divestiture process of its California properties in the second quarter 2012, with one property remaining to be sold as of December 31, 2013. Under generally accepted accounting principles, the results of operations for the California properties are presented as “discontinued operations.”

(2)Non-GAAP measure, see attached Reconciliation Schedules

The Company also announced today that it received the 2013 Corporate Growth Award from the Association of Corporate Growth which recognizes companies for their excellence in growth strategies.

Marvin Chronister, Bonanza Creek’s interim President and Chief Executive Officer, commented: “We are pleased to report strong financial and operating results for the fourth quarter and full year 2013. The Company continues to execute on its strategic plan and deliver superior results for its stockholders thanks to a team of dedicated professionals operating high quality assets.”

Tony Buchanon, Bonanza Creek’s Executive Vice President and Chief Operating Officer, commented: “The Company had another outstanding year operationally led by our safety performance which recorded zero lost time incidents for both company employees and contractors. We exceeded our annual production guidance and significantly reduced operating costs, all while coming in at the low end of our capital budget range. Our substantial investment in the Wattenberg Field in 2013 resulted in outstanding proved reserve growth of approximately 51% in the Rocky Mountain region and 32% company-wide. We executed on our catalyst well program in both of our core regions, which led to increases in our inventory of undrilled locations and internal assessment of risked 3P reserves. During 2014, we plan to expand the development of the Wattenberg Field with the application of increased downspacing and extended reach laterals as well as 5-acre downspacing in the Mid-Continent.”

Fourth Quarter 2013 Financial Results from Continuing Operations

Net revenue for fourth quarter 2013 was $133.1 million, compared to $73.6 million for fourth quarter 2012. Crude oil and liquids accounted for approximately 88% of total revenue.

Average realized prices for fourth quarter 2013, before the effect of commodity derivatives, were $86.91 per Bbl of oil, $4.86 per Mcf of natural gas and $49.36 per Bbl of NGLs, compared to $84.16 per Bbl of oil, $4.36 per Mcf of natural gas and $54.60 per Bbl of NGLs for fourth quarter 2012.

Lease operating expense for fourth quarter 2013 was $10.8 million, or $5.55 per Boe, compared to $8.2 million, or $7.45 per Boe, for fourth quarter 2012.

General and administrative expense (“G&A”) for fourth quarter 2013 was $15.2 million, or $7.85 per Boe, compared to $9.0 million, or $8.18 per Boe, for fourth quarter 2012. Cash G&A (non-GAAP, excludes stock-based compensation expense) was $12.3 million, or $6.34 per Boe for the fourth quarter of 2013 compared to $7.4 million, or $6.75 per Boe for fourth quarter 2012.

Depreciation, depletion and amortization for fourth quarter 2013 was $50.5 million, or $26.01 per Boe, compared to $24.5 million, or $22.24 per Boe, for the fourth quarter 2012.

Interest expense for fourth quarter 2013 was $8.0 million compared to $1.8 million for the fourth quarter 2012. The increase in interest expense is primarily related to the issuance of $500 million of senior notes during 2013.

Adjusted EBITDAX(2) for fourth quarter 2013 was $99.5 million, compared to $54.0 million for the fourth quarter 2012.

Net income for fourth quarter 2013 was $25.4 million, or $0.63 per diluted share, compared to net income of $13.0 million, or $0.32 per diluted share, for fourth quarter 2012. Adjusted net

income(2) for fourth quarter 2013 was $25.5 million, or $0.65 per diluted share, compared to adjusted net income of $15.7 million, or $0.40 per diluted share for fourth quarter 2012.

2013 Proved Reserves and 3P Reserves Update

Bonanza Creek’s proved reserves increased 32% year-over-year to 69.8 MMBoe; before tax PV-10 (non-GAAP) was approximately $1.2 billion. Reserve replacement in 2013 for the Company was 393%. As a result of continued success in the Wattenberg horizontal program, Rocky Mountain region proved reserves increased 51% and the before tax PV-10 increased 102% to $908.9 million. See Schedule 8 for further discussions regarding PV-10 value and Bonanza Creek’s belief in its usefulness in evaluating its reserves.

The following table summarizes the Company’s 2013 proved reserves:

Reserve Category	% of Reserves		Oil (MBbls)	Gas (Mcf)	NGL (MBbls)	2013 MBOE	2012 MBOE	% Change		2013PV-10 (millions)
Proved Developed Producing	40	%	18,554	50,128	932	27,840	16,579	68	%	$	757.2
Proved Developed Non-Producing	6	%	2,100	9,122	687	4,308	7,253	(41	)%	$	112.4
Proved Undeveloped	54	%	22,892	80,364	1,317	37,603	29,192	29	%	$	357.6
Total Proved	100	%	43,546	139,614	2,936	69,751	53,024	32	%	$	1,227.2
Rocky Mountain Region	70	%	32,121	101,246	0	48,995	32,434	51	%	$	908.9
Mid-Continent Region	30	%	11,413	38,368	2,936	20,744	20,559	0	%	$	318.1
Western Region	<1	%	12	0	0	12	31	(58	)%	$	0.2
Total Proved	100	%	43,546	139,614	2,936	69,751	53,024	32	%	$	1,227.2

The Company also updated its year-end 2013 internal 3P reserves analysis from its two core regions. Total 3P reserves were 354 MMBoe from a remaining well inventory of 2,276 gross (1,667 net) locations. In the Wattenberg Field, horizontal 3P reserves increased by 30% to 308 MMBoe primarily as a result of increased EURs in the Niobrara C Bench and Codell formation and a 20% increase in remaining well inventory to 1,841 gross (1,314 net) locations. The incremental well count is based on acreage additions and increased confidence gained from drilling over 100 horizontal wells in 2012 and 2013 both laterally across the acreage and vertically through the producing intervals. In addition, Dorcheat-Macedonia 3P reserves increased by 14% to 41 MMBoe and remaining well count increased 12% to 380 gross (316 net) locations.

The following table summarizes the Company’s 2013 horizontal risked 3P reserves and inventory count in the Wattenberg Field:

	2012EUR (MBoe)	2013 EUR (MBoe)	% Change		2012GrossLocations	2012NetReserves(MMBoe)	2013Gross Locations	2013Net Locations	2013 Net Reserves (MMBoe)
HZ Unproved
Niobrara B Bench	269	277	3	%	647	107.0	707	495	112.6
Niobrara C Bench	230	258	12	%	724	96.0	888	614	130.1
Codell	230	321	40	%	81	12.0	101	75	19.7
Total/Weighted Avg	247	270	9	%	1,452	215.0	1,696	1,184	262.4
HZ Proved(1)					75	22.0	145	130	45.6
Total					1,527	237.0	1,841	1,314	308.0

(1)Location counts represent proved undeveloped inventory only

Operations Update

During fourth quarter 2013, the Company achieved an average production rate of 21,119 Boe/d from continuing operations, comprised of 66% crude oil, 5% NGLs, and 29% natural gas, increasing total production by 77% over fourth quarter 2012 and 20% over the previous quarter. The Company also maintained its top safety record with no recordable lost time incidents for the twelve months ended December 31, 2013.

Rocky Mountain Region — Wattenberg Horizontal Development

During fourth quarter 2013, the Rocky Mountain region produced 15,036 Boe/d, or 71% of total company volumes, with 14,344 Boe/d coming from horizontal wells. Production increased 130% and the contribution from horizontal wells grew 289% over fourth quarter 2012. Compared to the previous quarter, Rocky Mountain volumes increased 27% and horizontal production volumes grew by 29%.

The Company spud 22 gross (18.9 net) horizontal wells and tied 15 gross (13.8 net) horizontal wells into sales during the quarter. For full year 2013, it spud 87 gross (81.3 net) horizontal wells and tied 73 gross (67.2 net) horizontal wells into sales. The Company’s non-operated activity for the year included the completion of four gross (1.4 net) horizontal wells in the fourth quarter. The Company began drilling its 15 well Super-Section from three pads in October and finished in December. Completion operations began in mid-January and currently all 15 wells are on flowback or early production.

The Company reported encouraging results from its catalyst testing program during 2013. The Niobrara C Bench, Codell formation, downspacing and extended reach laterals performed within expectations. The Company will expand the testing and development of these upside opportunities in 2014.

The Company now has five Codell wells on production with an average 30-day production rate of 498 Boe/d at 75% crude oil, an average 60-day rate of 422 Boe/d, and an average 90-day rate of 399 Boe/d on three wells. It also has five Niobrara C Bench wells producing for over three months with an average 30-day production rate of 425 Boe/d at 83% crude oil, an average 60-day rate of 380 Boe/d, and an average 90-day rate of 347 Boe/d.

Extended reach laterals continue to impress. The Company’s last two of three 9,000’ wells, completed optimally, continued to increase in rate through 60 days before exhibiting a very shallow decline. The average 30-day production rate for these two wells was 654 Boe/d, the average 60-day rate increased to 667 Boe/d, and the 90-day rate was only 5% less than the average 30-day rate at 622 Boe/d.

The Company’s Niobrara B Bench 40-acre spaced testing is ongoing and results are within the range of expectations though hampered by operational and high line pressure issues. The six downspaced wells averaged a 30-day production rate of 368 Boe/d at 82% crude oil, a 60-day rate of 305 Boe/d and a 90-day average rate on four wells of 271 Boe/d.

Mid-Continent Cotton Valley Program

The Mid-Continent region contributed 6,083 Boe/d, or 29% of total company net sales volumes for fourth quarter 2013, comprised of 50% crude oil, 18% natural gas liquids and 32% natural gas. Sales volumes increased by approximately 13% over fourth quarter 2012.

During the fourth quarter 2013, Bonanza Creek spud 8 gross (6.8 net) Cotton Valley wells, tied 10 gross (7.3 net) wells into sales and performed 17 gross (13.9 net) recompletions. For the full year 2013, it spud 47 gross (38.5 net) wells, tied 48 gross (39.6 net) wells into sales and performed 103 gross (91.4 net) recompletions. In 2013, the Company completed nine wells testing 5-acre spacing. There has been no observed interference and initial production and subsequent recompletion efforts have all been above expectations.

Financial and Risk Management Update

Debt and Liquidity

As of December 31, 2013, Bonanza Creek had a $600 million revolving credit facility with an undrawn borrowing base of $450 million. The Company had a letter of credit totaling $36.0 million and cash totaling $180.6 million, resulting in total liquidity of $594.6 million.

On April 9, 2013, the Company sold $300 million of 6.75% Senior Notes that mature on April 15, 2021. On November 15, 2013, the Company sold an additional $200 million aggregate principal amount of 6.75% Senior Notes as an additional issuance of the Company’s existing Senior Notes.

Commodity Derivatives Positions

The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of February 27, 2014 and settling quarterly:

Settlement Period	Swap Volume	Fixed Price	Collar Volume	Average Short Floor	Average Floor	AverageCeiling
Oil	Bbl/d	$	Bbl/d	$	$	$
Q1 2014	3,133	96.97	5,617		86.33	97.09
Q2 2014	4,126	96.20	4,846		86.55	96.72
Q3 2014	3,870	93.04	4,326		86.16	96.57
Q4 2014	3,870	93.04	4,326		86.16	96.57
Q1 2014			1,000	60.00	85.00	99.50
Q2-Q4 2014			2,000	65.00	87.68	99.75
FY 2015			4,500	66.67	83.33	94.12

Gas	MMBtu/d	$	MMBtu/d	$	$	$
Q1 2014			22,500	3.56	4.13	4.78
Q2-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, February 28, 2014 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). To access the live interactive call, please dial (866) 515-2912 or (617) 399-5126 and use the passcode 20429568. 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 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 the Company’s drilling and development program; the Company’s testing and recompletion activities; liquidity; and results of the Company’s catalyst well testing program. 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, 2013, expected to be filed on or about February 28, 2014, 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

720-440-6172

Mr. James Masters

Investor Relations Manager

720-440-6121

Schedule 1: Statement of Operations

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

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2013			2012			2013			2012
NET REVENUES
Oil and gas sales	$	133,062		$	73,592		$	421,860		$	231,205
OPERATING EXPENSES
Lease operating	10,785			8,189			47,771			30,695
Severance and ad valorem taxes	8,952			4,287			27,203			13,674
Exploration	689			1,151			4,213			10,715
Depreciation, depletion and amortization	50,546			24,451			140,176			66,202
Impairment of oil and gas properties	—			342			—			611
General and administrative	15,242			8,995			55,502			31,405
Total operating expenses	86,214			47,415			274,865			153,302
INCOME FROM OPERATIONS	46,848			26,177			146,995			77,903
OTHER INCOME (EXPENSE)
Other (loss)	(40		)	(50		)	(43		)	(133		)
Interest expense	(7,959		)	(1,791		)	(21,972		)	(4,133		)
Derivative gain (loss)	1,971			(887		)	(12,472		)	925
Total other (expense)	(6,028		)	(2,728		)	(34,487		)	(3,341		)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	$	40,820		$	23,449		$	112,508		$	74,562
Income tax (expense)	(15,319		)	(10,194		)	(42,926		)	(29,991		)
INCOME FROM CONTINUING OPERATIONS	25,501			13,255			69,582			44,571
DISCONTINUED OPERATIONS
(Loss) from operations associated with oil and gas properties held for sale	(109		)	(135		)	(644		)	(927		)
Gain (loss) on sale of oil and gas properties	—			(88		)	—			4,192
Income tax (expense) benefit	40			18			246			(1,313		)
Income (loss) from discontinued operations	(69		)	(205		)	(398		)	1,952
NET INCOME	$	25,432		$	13,050		$	69,184		$	46,523
DILUTED INCOME (LOSS) PER COMMON SHARE
Income from continuing operations per common share	$	0.64		$	0.32		$	1.72		$	1.12
Income (loss) from discontinued operations per common share	$	(0.01	)	$	(0.00	)	$	(0.01	)	$	0.05
Net income per common share	$	0.63		$	0.32		$	1.71		$	1.17
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
Basic	39,402			39,077			39,337			39,052
Diluted	39,486			39,077			39,404			39,052

*    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 13 — Earnings per Share in the Form 10-K, for a detailed calculation.

Schedule 2: Statement of Cash Flows

(in thousands, unaudited)

	Twelve Months Ended
	December 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	69,184		$	46,523
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	140,546			68,445
Impairment of oil and gas properties	—			2,259
Deferred income taxes	42,432			30,773
Stock-based compensation	12,638			4,483
Exploration	1,709			8,379
Amortization of deferred financing costs and debt premium	1,505			700
Accretion of contractual obligation for land acquisition	761			317
Derivative (gain) loss	12,472			(924		)
(Gain) on sale of oil and gas properties	—			(4,192		)
Other	(7		)	168
Changes in current assets and liabilities:
Accounts receivable	(26,315		)	(20,738		)
Prepaid expenses and other assets	1,394			(1,164		)
Accounts payable and accrued liabilities	50,897			22,769
Excess income tax benefit from the vesting of stock awards	(128		)	—
Settlement of asset retirement obligations	(73		)	(162		)
Net cash provided by operating activities	307,015			157,636
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties	—			9,337
Acquisition of oil and gas properties	(13,797		)	(13,920		)
Payments of contractual obligations for land acquisition	(12,000		)	—
Exploration and development of oil and gas properties	(417,835		)	(281,326		)
Natural gas plant capital expenditures	(5,202		)	(15,788		)
Decrease in restricted cash	79			253
Derivative cash settlements	(11,330		)	(726		)
Additions to property and equipment-non oil and gas	(5,138		)	(3,107		)
Net cash used in investing activities	(465,223		)	(305,277		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facility	102,000			151,400
Payments to credit facility	(260,000		)	—
Net share settlement from issuance of stock awards	(4,439		)	(467		)
Net proceeds from senior notes	488,278			—
Premium on senior notes	9,000			—
Excess income tax benefit from the vesting of stock awards	128			—
Offering costs related to sale of common stock	—			(3		)
Deferred financing costs	(445		)	(1,111		)
Net cash provided by financing activities	334,522			149,819
Net increase in cash and cash equivalents	176,314			2,178
Cash and cash equivalents, beginning of period	4,268			2,090
Cash and cash equivalents, end of period	$	180,582		$	4,268

Schedule 3: Condensed Balance Sheet

(in thousands, unaudited)

	December 31		December 31,
	2013		2012
Assets
Current assets	$	264,174	$	55,304
Oil and gas properties and gas plant, net	1,259,844		938,975
Other assets	21,557		7,629
Oil and gas properties held for sale, less accumulated depreciation, depletion, and amortization	360		582
Total Assets	$	1,545,935	$	1,002,490
Liabilities and Stockholders’ Equity
Current liabilities	175,226		102,603
Long-term debt	508,846		158,000
Deferred taxes	152,681		110,377
Other long-term liabilities	53,154		52,992
Total Liabilities	$	889,907	$	423,972
Stockholders’ Equity	656,028		578,518
Total Liabilities and Stockholders’ Equity	$	1,545,935	$	1,002,490

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

(unaudited)

	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains	10,940		4,951		7,690		3,433
Mid-Continent	3,053		2,965		2,960		2,553
Total	13,993		7,916		10,650		5,986
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$	84.13	$	80.07	$	88.76	$	84.60
Mid-Continent	96.90		90.99		99.84		95.12
Composite	$	86.91	$	84.16	$	91.84	$	89.08
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains	29		—		28		—
Mid-Continent	1,069		895		939		778
Total	1,098		895		967		778
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$	22.69	$	—	$	27.90	$	—
Mid-Continent	50.09		54.60		52.45		55.54
Composite	$	49.36	$	54.60	$	51.74	$	55.54
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains	24,406		9,583		17,398		6,808
Mid-Continent	11,764		9,249		9,933		8,146
Total	36,170		18,832		27,331		14,954
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$	5.35	$	5.17	$	5.13	$	4.46
Mid-Continent	3.83		3.53		3.84		2.91
Composite	$	4.86	$	4.36	$	4.66	$	3.62
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains	15,036		6,549		10,618		4,567
Mid-Continent	6,083		5,401		5,554		4,689
Total	21,119		11,950		16,172		9,256
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$	69.96	$	68.51	$	72.80	$	70.48
Mid-Continent	64.84		65.03		68.93		66.07
Composite	$	68.48	$	66.94	$	71.45	$	68.12
Total Sales Volumes (MMBoe)	1.9		1.1		5.9		3.4

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 income (GAAP) to Adjusted Net Income (non-GAAP):

	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2013			2012		2013			2012
Net Income	$	25,432		$	13,050	$	69,184		$	46,523
Derivative gain (loss)	(1,970		)	888		12,472			(924		)
Derivative cash settlement	(1,464		)	448		(11,330		)	(726		)
Loss (gain) on sale of oil and gas properties	—			88		—			(4,192		)
Exploratory dry hole cost	630			1,000		630			8,379
Impairment of oil and gas properties	—			343		—			2,259
Stock-based compensation	2,922			1,571		12,638			4,483
Total adjustments before tax	118			4,338		14,410			9,279
Adjustment of income tax effect	45			1,670		5,548			3,572
Adjusted for income tax effects	73			2,668		8,862			5,707
Adjusted net income	$	25,505		$	15,718	$	78,046		$	52,230
Adjusted net income per diluted share	$	0.65		$	0.40	$	1.98		$	1.34

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, 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 tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measures of net income.

	Three Months Ended					Twelve Months Ended
	December 31,					December 31,
	2013			2012		2013			2012
Net Income	$	25,432		$	13,050	$	69,184		$	46,523
Exploration	688			1,173		4,278			10,754
Depreciation, depletion and amortization	50,649			24,544		140,546			68,445
Impairment of oil and gas properties	—			342		—			2,259
Stock-based compensation	2,922			1,571		12,638			4,483
Loss (gain) on sale of oil and gas properties	—			88		—			(4,192		)
Interest expense	7,959			1,791		21,972			4,133
Derivative (gain) loss	(1,970		)	888		12,472			(924		)
Derivative cash settlements	(1,463		)	448		(11,330		)	(726		)
Income tax expense	15,279			10,176		42,680			31,305
Adjusted EBITDAX	$	99,495		$	54,071	$	292,440		$	162,060

Schedule 7: Cash Margin

(in thousands)

We define unhedged cash margin per Boe as oil and natural gas revenues, less (1) lease operating expense, (2) oil and natural gas taxes, and (3) cash G&A expense (excludes stock-based compensation), divided by production for continuing operations. Cash margin is presented herein and reconciled to the GAAP measure of net revenues because of its wide acceptance by the investment community as a financial indicator of a Company’s ability to generate cash flow from sales. This measure is provided in addition to, not as an alternative for and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes) in our SEC filings and posted on our website. The following table provides a reconciliation of cash margin to net revenues for the three and twelve months ended December 31, 2013 and 2012, respectively.

	Three Months Ended				Twelve Months Ended
	December 31,				December 31,
	2013		2012		2013		2012
Net revenues	$	133,062	$	73,592	$	421,860	$	231,205
Lease operating	10,785		8,189		47,771		30,695
Severance & ad valorem taxes	8,952		4,287		27,203		13,674
Cash G&A expense	12,320		7,424		42,864		26,922
Cash Operating Margin	$	101,005	$	53,692	$	304,022	$	159,914
Production from continuing operations (MBoe)	1,943		1,099		5,903		3,388
Unhedged unit cash margin	$	51.98	$	48.86	$	51.50	$	47.20

Schedule 8: Definition of PV-10 Value and the Standardized Measure

PV-10 is derived from the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”), which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 to the Standardized Measure at December 31, 2013 and 2012:

	December 31,
(in millions)	2013			2012
PV-10	$	1,227.2		$	834.7
Present value of future income taxes discounted at 10%	(301.9		)	(151.3		)
Standardized Measure	$	925.3		$	683.4