EX-99.1 2 a15-16339_1ex99d1.htm EX-99.1

Exhibit 99.1

Bonanza Creek Energy Announces Second Quarter 2015 Financial and Operating Results

DENVER, July 27, 2015 — Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported its second quarter 2015 financial and operating results. The Company previously announced revisions to its agreements with its gas processing providers in the Rocky Mountain region allowing it to report 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 second quarter 2015 and current operations include:

· Sales volumes grew to 28.0 Mboe/d representing a 14% increase compared to estimated 3-stream sales volumes in the second quarter of 2014(1) and 2% compared to first quarter 2015

· Increased Rocky Mountain region sales volumes by 21% compared to second quarter 2014(1), to 22.7 Mboe/d and 4% compared to first quarter 2015

· Estimated sales volumes(2) for the first 20 days in July were 29.4 Mboe/d, an all-time record for the Company

· Current Wattenberg Field standard 4,000 foot lateral (“SRL”) well costs are $3.4-3.5 million vs. $3.6 million during the second quarter

· First BCEI operated long reach lateral on northern acreage in the Wattenberg Field tracking to a 9,000 foot lateral (“XRL”) equivalent EUR of 680 Mboe

· Company to seek strategic operating and capital partners for the purposes of accelerating the growth of the Company’s wholly-owned midstream subsidiary, Rocky Mountain Infrastructure, LLC (“RMI”)

· Cash operating costs (lease operating expense (“LOE”), production taxes and general and administrative expense (“G&A”)) of $16.58 per Boe

· Adjusted EBITDAX(3) of $74.0 million

· Adjusted net loss(3) of $6.9 million, or $0.14 per share

· Liquidity at June 30, 2015 of $498.3 million

· BCEI recognized by Colorado regulators for operations excellence in its commitment to safety, regulatory compliance and environmentally conscious operations

(1) Second 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) Estimated sales volume exclude changes in field inventories.

(3) 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, “In the second quarter we demonstrated the recurring and sustainable benefits of our long-term corporate strategy. Full-field development engineering is not only positively affecting subsurface reservoir productivity, but is also validating surface engineering efficiencies that drive long-term economies of scale and cost reductions life-of-field. Our team’s focus on supply chain and procurement logistics is also materially reducing costs. Key performance indicators are resonating with ongoing reductions in LOE and well costs in addition to record high sales volume rates in July. Firm-wide systematic process improvements are working, and we are executing on our plan to deliver large scale industrial efficiencies. The Company

is well positioned to harvest the significant resource base of approximately 550 MMboe of 3P reserves which is underpinned by data from 380 horizontal wellbores in our portfolio.”

Second Quarter 2015 Financial Results

Net revenue for second quarter 2015 was $90.4 million, compared to $151.7 million for second quarter 2014. Crude oil and liquids accounted for approximately 92% of total revenue. Average realized prices for second quarter 2015, before the effect of commodity derivatives, were $49.90 per Bbl of oil, $1.96 per Mcf of natural gas and $16.28 per Bbl of NGLs, compared to $92.60 per Bbl of oil, $5.34 per Mcf of natural gas and $51.89 per Bbl of NGLs for second quarter 2014.

LOE for second quarter 2015 was $20.9 million, or $8.19 per Boe, compared to $18.0 million, or $8.67 per Boe ($8.07 per Boe adjusted for estimated 3-stream volumes), for second quarter 2014. Included in second quarter lease operating expense is $0.6 million or $0.24 per Boe related to expenses associated with RMI operating expenses.

G&A for second quarter 2015 was $21.6 million, or $8.47 per Boe, compared to $24.5 million, or $11.81 per Boe ($10.99 per Boe adjusted for estimated 3-stream volumes), for second quarter 2014. Cash G&A (non-GAAP, excludes stock-based compensation expense)(2) was $17.2 million, or $6.76 per Boe for the second quarter of 2015 compared to $17.2 million, or $8.27 per Boe for second quarter 2014 ($7.70 per Boe adjusted for estimated 3-stream volumes). Second quarter 2014 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 the second quarter 2014 was $14.3 million, or $6.86 per Boe ($6.40 per Boe adjusted for estimated 3-stream volumes).

Depreciation, depletion and amortization for second quarter 2015 was $69.9 million, or $27.41 per Boe, compared to $54.1 million, or $26.03 per Boe ($24.23 per Boe adjusted for estimated 3-stream volumes), for the second quarter 2014.

Interest expense for second quarter 2015 was $14.5 million compared to $9.4 million for the second quarter 2014.

Adjusted EBITDAX(2) for second quarter 2015 was $74.0 million, compared to $97.4 million for the second quarter 2014.

Second quarter 2015 earnings included non-cash mark-to-market losses on derivatives of $20.7 million before tax, or $0.42 per diluted share. Derivative cash settlements for the second quarter resulted in a cash receipts of $25.7 million which was partially offset by a cash payment of $10.5 million in May to cover the short puts associated with 3-way collars that are scheduled to settle during the third and fourth quarters of 2015.

Second quarter 2015 earnings also included non-cash, pre-tax charges of $20.2 million. The Company fully impaired its North Park Basin acreage and wrote off its exploratory wells in progress due to a strategic shift in future development plans in the Rocky Mountain region and plans to divest of this asset in the near future. It also recorded an impairment related to the expiration of leasehold within the Wattenberg Field.

Reported net loss for second quarter 2015 was $41.2 million, or $0.83 per diluted share, compared to net income of $1.2 million, or $0.03 per diluted share, for second quarter 2014.

Adjusted net loss(2) for second quarter 2015 was $6.9 million, or $0.14 per diluted share, compared to adjusted net income of $20.7 million, or $0.52 per diluted share for second quarter 2014.

Operations Update

During second quarter 2015, the Company achieved average sales volumes of 28.0 Mboe/d, comprised of 60% crude oil, 17% NGLs and 23% natural gas, increasing total sales volumes by 14% over estimated 3-stream volumes in the second quarter of 2014. For the first 20 days of July, estimated sales volumes averaged 29.4 Mboe/d.

Total capital costs incurred during the second quarter totaled $164.0 million.

The Company is proud to announce that it will be receiving an Outstanding Operator Award from our state regulator, the Colorado Oil & Gas Conservation Commission, on August 27th in recognition of its innovations in flow back operations that have led to decreased air emissions while optimizing well productivity.

Rocky Mountain Region — Wattenberg Horizontal Development

The Company spud 19 gross operated (14.1 net) horizontal wells and tied 21 gross operated (18.6 net) horizontal wells into sales during the quarter. The Company did not participate in any new non-operated activities during the second quarter. Spud and completion activity began the quarter ahead of the Company’s 2015 plan, but rainfall that was unseasonal in its consistency and magnitude during May and June slowed activity with poor road conditions and periodic flooding along the South Platte River. During May and June, the Company completed 8 gross (6.6 net) fewer SRL-equivalent wells than planned. For the second quarter, upstream capital costs incurred for the region were $138.6 million.

During second quarter 2015, the Rocky Mountain region sold 22.7 Mboe/d, or 81% of total Company volumes, with over 95% coming from horizontal wells. The production was comprised of 62% crude oil, 16% NGLs and 22% natural gas. On a 3-stream basis, sales volumes were up 21% compared to the second quarter of 2014 and increased by 4% compared to the first quarter of 2015. Of note, the completion of a 5 well pad of XRLs (100% working interest) was delayed by approximately 30 days as a result of slowed field logistics due to weather conditions which impacted average sales rates for the second quarter by approximately 690 boe/d (net). Second quarter sales volumes were also impacted by the underperformance of a 5 well pad of 6,500 foot laterals (“MRL”) (99% working interest) completed in February on the extreme southeastern edge of our central legacy leasehold. This pad’s contribution to second quarter was approximately 745 boe/d (net) less than anticipated. The remainder of the Company’s base production and newly completed wells in the Wattenberg Field were above expectation by approximately 1,000 boe/d (net) due to a combination of well performance and increased working interests. For the first 20 days of July, estimated sales volumes for the Rocky Mountain region averaged 24.2 Mboe/d.

As part of our drive for permanent well efficiencies that do not effect overall well performance, we reduced the SRL frac stages by three to a 25-stage frac design for our 2015 drilling campaign. Early results from SRL wells completed during 2015 utilizing the Company’s 25-stage frac design have performed in-line with 28-stage SRL wells that were drilled in the same areas of the field during 2014.

The Company is also pleased to report that the Wattenberg Niobrara reservoirs have been demonstrating a widespread increase in performance with the benefit of controlled surface infrastructure as a result of our full-field development plan. Significant advancements in our field operations and frac designs over the past two years are now being evidenced in our proved reserves showing increasing oil EUR’s across our acreage which will positively impact our PUD reserves, which are booked on 80 acre spacing, by 6% to 18%. Our continued diligence on our more recent spacing and pattern wells is expected to have similar results over time.

In second quarter of 2014, we announced the acquisition of contiguous acreage to the north and south of our legacy acreage. In the this newly acquired acreage, the Company is pleased to report that its first long reach B bench well (7,300 foot lateral) drilled on its northern acreage has been on-line for approximately 100 days and is tracking to an EUR of 550 Mboe (or 680 Mboe for a 9,000 foot lateral equivalent). This result is consistent with the Company’s expectations for development wells in our northern acreage and provides the first tangible data point derived from an extended reach well that was drilled, completed and produced with Bonanza Creek as operator in each phase.

Also on the northern acreage, the Company has extended production history on a well that was drilled in 2010 by a previous owner of the asset. This well was drilled with only a 3,000 foot lateral in the B bench and was prepared for completion with a 15 stage sliding sleeve mechanism prior to being abandoned for 4 years. Bonanza Creek elected to complete the well in January and has collected six months of production history which is tracking to a 200 Mboe EUR which, when extrapolated to a 50-stage, 9,000 foot XRL, equates to an EUR of 650 Mboe.

Rocky Mountain Region — Wattenberg Infrastructure Development

Bonanza Creek has begun seeking strategic operating and capital partners for the purposes of accelerating the growth of midstream infrastructure in the region through RMI. During the second quarter of 2015, capital costs incurred by RMI totaled $5.6 million. As of June 30, 2015, RMI had total assets of $53.9 million. The Company believes its contiguous and largely undeveloped leasehold position provides a significant platform from which to optimize the build out of midstream capabilities to handle oil, gas and water. The Company is driving permanent and repeatable reduction in well costs leveraging its current and future midstream infrastructure in the full field development.

During the second quarter, RMI and DCP Midstream completed two separate gas pipelines that connect the Company’s newly completed Pronghorn gas gathering system on its eastern legacy leasehold to its 70 Ranch gathering system on its western legacy leasehold. These new connections allow gas produced by the wells located in the Company’s eastern legacy leasehold an alternate route to access DCP Midstream’s gas processing infrastructure providing greater access to the lowest line pressures on the greater DCP gas gathering and process system.

In another positive field development, DCP Midstream commissioned its Lucerne II gas processing facility at the end of June. The facility continues to ramp-up as scheduled to its full capacity of 200 MMcf/d. In concert with the start up of Lucerne II, DCP Midstream has constructed two compressor stations that are proximate to Bonanza Creek acreage. The 70 Ranch compressor station is on line and has a capacity of 45 MMcf/d while the 100 MMcf/d Rocky compressor station is currently being commissioned.

Differentials to WTI in the Wattenberg Field have decreased to an average of $9.22 per Bbl during the second quarter compared to $10.36 per Bbl during the first quarter of 2015. On May 1, 2015, the Company began shipping 12,580 Bbls/d (gross) on the Pony Express Pipeline.

Tony Buchanon, Executive Vice President & Chief Operating Officer, stated, “We are pleased to have a quarter that was not severely hampered by midstream downtime and believe the underlying assets of Bonanza Creek are performing very well. While we have very few Bonanza Creek operated well results on our northern acreage, we believe that data from nearby operators and recent strong well performance recorded to date have confirmed our long standing views that the quality of the acreage is very similar to our legacy position with low variability and high repeatability. The construction of the gas pipelines, including the Windmill interconnector line, ties together our east and west legacy acreage. This provides significant flexibility in the movement of gas throughout our acreage. Furthermore it positions what is now a reliable Sullivan compression station at the northern edge of our acreage as the potential driver to regulate line pressures for future wells drilled on our northern acreage. We believe that as more field infrastructure on the northern acreage is built, project economics in this area will compete very well compared to those of projects within our legacy Wattenberg portfolio.”

Mid-Continent Region — Cotton Valley Development

During the second quarter 2015, Bonanza Creek spud 7 gross (5.9 net) Cotton Valley wells, tied 8 gross (7.6 net) wells into sales and performed 25 gross (20.9 net) recompletions. For the second quarter, capital costs incurred for the region were $19.4 million.

The Mid-Continent region contributed 5.3 Mboe/d, or 19% of total Company net sales volumes for second quarter 2015, comprised of 52% crude oil, 19% NGLs and 29% natural gas. Sales volumes were down 8% compared to the second quarter of 2014 and decreased by 4% compared to the first quarter of 2015.

Sales volumes were down compared to the first quarter of 2015 due to the effects of reduced activity in 2015 and the lingering impacts of below average initial production of the projects executed during the first quarter. For the first 20 days of July, estimated sales volumes for the Mid-Continent region averaged 5.2 Mboe/d.

Financial and Risk Management Update

Debt and Liquidity

Bonanza Creek has a $1.0 billion revolving credit facility with an approved borrowing base of $550 million. The Company elected to limit bank commitments to $500 million while reserving the option to access the full $550 million, at the Company’s request prior to the next semi-annual redetermination date. As of June 30, 2015, the Company had borrowings under its credit facility of $43.0 million, a letter of credit totaling $24.0 million and cash totaling $15.3 million, resulting in total liquidity of $498.3 million. Bonanza Creek has two outstanding issues of unsecured high-yield bonds which consist of $500 million 6.75% senior notes due in 2021 and $300 million 5.75% senior notes due in 2023.

On May 13, 2015, the Company and its ten member bank group agreed to amend the maintenance covenants associated with its revolving credit facility during its semi-annual redetermination. The amendment permanently removed the maximum total debt to trailing twelve month debt to earnings before interest expense, income taxes, depreciation, depletion,

amortization, exploration expenses and other non-cash charges (“EBITDAX”) covenant of 4.0x and introduced both a maximum senior secured debt (defined as borrowings under the revolving credit facility, balances drawn under letters of credit and any outstanding second lien debt) to trailing twelve month EBITDAX covenant of 2.5x and a minimum trailing twelve month interest to trailing twelve month EBITDAX coverage covenant of 2.5x. The revolving credit facility also contains a minimum current ratio covenant of 1.0x. As of June 30, 2015, the Company was in compliance with all financial covenants as our senior secured debt to EBITDAX ratio was 0.2x, our interest coverage ratio was 6.1x and our current ratio was 3.5x.

Commodity Derivatives Positions

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

Settlement Period	Swap Volume	Fixed Price	Collar Volume	Average Short Floor	Average Floor	Average Ceiling
Oil	Bbl/d	$	Bbl/d	$	$	$
Q3 2015	6,000	72.16	6,500		84.62	95.49
Q4 2015	6,000	72.16	6,500		84.62	95.49
FY 2016			5,500	70.00	85.00	96.83

Gas	MMBtu/d	$	MMBtu/d	$	$	$
Q3 2015			15,000	3.50	4.00	4.75
Q4 2015			15,000	3.50	4.00	4.75

Updated 2015 Guidance

The Company is establishing forward quarter guidance for sales volumes in the third quarter of 28.6 Mboe/d. Based on year to date results, it is narrowing the range of its annual sales volume guidance by lowering the top end of the range from 30.7 Mboe/d to 29.0 Mboe/d resulting in a new mid-point of 28.4 Mboe/d. Annual ranges for LOE and Cash G&A are unchanged. Annual guidance for production taxes has been lowered from 10% to 6% based on levels year to date that were lower than budgeted and the anticipation of a non-recurring severance tax credit expected during the third quarter. Annual capital expenditure guidance is unchanged due to higher net capital associated with RMI that was previously allocated to non-operated working interest partners ($22.5 million) and increased working interests on wells drilled within the 2015 capital program ($17.0 million). Offsetting these increases, the Company believes decreased well costs will generate $40 million in savings relative to assumptions employed in the construction of the original 2015 budget.

Average sales volumes
3Q		28.6 Mboe/d
Full Year		27.8 – 29.0 Mboe/d
Unit operating costs and expenses:
LOE		$7.75 – $8.25 / boe
Cash G&A		$5.75 – $6.25 / boe
Production taxes (% of pre-hedge realizations):		6%

Capital expenditures (in millions):		$400 – $440

2016 Outlook

The Company believes that current commodity prices and capital cost structures are not sufficiently aligned to incentivize growth in activity levels. Our formal planning process for 2016 began in July and will continue through the remainder of the year. Many variables that underpin the size, pace and geographic concentration of our 2016 budget will be dictated by ongoing service price and equipment utilization discussions with our oilfield service partners, progress on a potential partnership with our RMI midstream business and commodity price signals as the year ends.

The Company believes that a program of 80 net SRL-equivalent wells to be completed in 2016 would be sufficient to maintain 2015 exit rates in the Rocky Mountain region. The Company expects XRL wells to account for approximately 50% of 2016 activity (26.7 net XRL wells). This compares to the Company’s 2015 program of 96 net SRL-equivalent wells of which 30% are a combination of MRLs and XRLs.

With continued innovations in well construction and frac design along with infrastructure costs being allocated to RMI, the Company anticipates SRL well costs of $2.7 million will be achievable in 2016.

Conference Call Information

Bonanza Creek will host a conference call on Tuesday, July 28, 2015 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). To access the live interactive call, please dial (877) 280-4959 or (857) 244-7316 and use the passcode 53169455 . 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 EURs; future reserves; impacts of the Company’s development plan and spacing and pattern wells; development expectations and strategy; decreasing operating and capital costs; consistency of the Company’s acreage

position; project economics; divestiture intentions; optimization of midstream capabilities; and the intent to seek strategic operational and capital partners for RMI; updated 2015 guidance and 2016 outlook. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2014, filed on February 27, 2015, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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 June 30
	2015			2014
OPERATING NET REVENUES:
Oil and gas sales	$	90,422		$	151,682
OPERATING EXPENSES:
Lease operating expense	20,895			18,018
Severance and ad valorem taxes	4,148			16,263
Exploration	5,748			96
Depreciation, depletion and amortization	69,925			54,117
Abandonment and impairment of unproved properties	14,527			—
General and administrative (including $4,359 and $7,353 of stock compensation for 2015 and 2014, respectively)	21,602			24,547
Total operating expenses	136,845			113,041
INCOME (LOSS) FROM OPERATIONS	(46,423		)	38,641
OTHER INCOME (EXPENSE):
Derivative loss	(5,478		)	(27,307		)
Interest expense	(14,468		)	(9,434		)
Other income	198			167
Total other expense	(19,748		)	(36,574		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE TAXES	(66,171		)	2,067
Income tax benefit (expense)	25,007			(796		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	(41,164	)	$	1,271
DISCONTINUED OPERATIONS:
Loss from operations associated with oil and gas properties held for sale	—			—
Loss on sale of oil and gas properties	—			(184		)
Income tax benefit	—			71
Loss from discontinued operations	—			(113		)
NET INCOME (LOSS)	$	(41,164	)	$	1,158
BASIC AND DILUTED INCOME (LOSS) PER SHARE
Income (loss) from continuing operations	$	(0.83	)	$	0.03
Income from discontinued operations	$	—		$	—
Net income (loss) per common share	$	(0.83	)	$	0.03
BASIC WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING	48,923			39,758
DILUTED WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING	48,923			39,857

* 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)

	Six Months Ended June 30,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(59,586	)	$	14,689
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	128,929			95,316
Deferred income taxes	(36,544		)	9,095
Abandonment and impairment of unproved properties	19,996			—
Dry hole expense	5,680			—
Stock-based compensation	7,787			14,150
Amortization of deferred financing costs and debt premium	1,226			542
Accretion of contractual obligation for land acquisition	698			381
Derivative (gain) loss	(13,378		)	36,085
Gain on sale of oil and gas properties	—			(6,330		)
Other	(43		)	(14		)
Changes in current assets and liabilities:
Accounts receivable	18,319			(32,385		)
Prepaid expenses and other assets	(1,348		)	(2,575		)
Accounts payable and accrued liabilities	(23,054		)	29,114
Settlement of asset retirement obligations	(519		)	(99		)
Net cash provided by operating activities	48,163			157,969

CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of oil and gas properties	(11,914		)	(3,091		)
Proceeds from sale of oil and gas properties	—			6,000
Exploration and development of oil and gas properties	(282,993		)	(275,890		)
Natural gas plant capital expenditures	(113		)	(271		)
Derivative cash settlements	50,655			(8,142		)
(Increase) decrease in restricted cash	—			(11,280		)
Additions to property and equipment - non oil and gas	(649		)	(3,989		)
Net cash used in investing activities	(245,014		)	(296,663		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facility	87,000			—
Payments to credit facility	(77,000		)	—
Proceeds from sale of common stock	209,300			—
Offering costs related to sale of common stock	(6,607		)	—
Offering costs related to the sale of Senior Notes	(93		)	(277		)
Payment of employee tax withholdings in exchange for the return of common stock	(2,448		)	(4,766		)
Deferred financing costs	(545		)	(290		)
Net cash provided by (used in) financing activities	209,607			(5,333		)
Net change in cash and cash equivalents	12,756			(144,027		)

Cash and cash equivalents:
Beginning of period	2,584			180,582
End of period	$	15,340		$	36,555

Schedule 3: Condensed Balance Sheet

(in thousands, unaudited)

	June 30,		December 31,
	2015		2014
ASSETS
Current assets	$	168,426	$	208,475
Total property and equipment, net	1,890,974		1,756,477
Other assets	33,486		41,137
Total Assets	$	2,092,886	$	2,006,089

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	171,424	$	198,447
Long-term debt	850,006		840,619
Deferred income taxes	129,122		165,667
Other long-term liabilities	53,816		61,285
Total Liabilities	$	1,204,368	$	1,266,018

Stockholders’ Equity	888,518		740,071
Total Liabilities and Stockholders’ Equity	$	2,092,886	$	2,006,089

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

(unaudited)

	Three Months Ended
	June 30,
	2015		3-Stream 2014 (1)	2-Stream 2014
Wellhead Volumes and Prices

Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains	14,079		12,163	12,163
Mid-Continent	2,768		2,962	2,962
Total	16,847		15,125	15,125

Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains	$	48.72		$	90.59
Mid-Continent	55.93			100.84
Composite (before derivatives)	$	49.90		$	92.60
Composite (after derivatives)	$	59.37		$	88.31

Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains	3,696		2,886	35
Mid-Continent	1,020		919	919
Total	4,716		3,805	954

Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains	$	15.75		$	28.72
Mid-Continent	16.56			52.79
Composite (before derivatives)	$	16.28		$	51.89
Composite (after derivatives)	$	16.28		$	51.89

Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains	29,782		22,229	29,183
Mid-Continent	9,075		11,445	11,445
Total	38,857		33,674	40,628

Natural Gas Realized Prices ($/Mcf)
Rocky Mountains	$	1.65		$	5.53
Mid-Continent	2.99			4.84
Composite (before derivatives)	$	1.96		$	5.34
Composite (after derivatives)	$	2.15		$	5.33

Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains	22,738		18,754	17,061
Mid-Continent	5,300		5,788	5,788
Total	28,038		24,542	22,849

Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains	$	34.96		$	74.10
Mid-Continent	37.50			69.55
Composite (before derivatives)	$	35.44		$	72.95
Composite (after derivatives)	$	41.39		$	70.10

Total Sales Volumes (MBoe)	2,551.5		2,233.4	2,079.3

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 unrealized gains and losses on unsettled derivative instruments, impairment of oil and gas properties, other similar non-cash charges and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on a tax rate of 38.5%, 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 (loss) (GAAP) to adjusted net income (loss) (non-GAAP):

	Three Months Ended
	June 30,
	2015			2014
Net income (loss)	$	(41,164	)	$	1,158

Adjustments to net income (loss):
Derivative loss	5,478			27,307
Derivative cash settlements	15,189			(5,915		)
Loss on sale of oil and gas properties	—			184
Abandonment and impairment of unproved properties	14,527			—
Exploratory dry hole	5,680			—
Stock-based compensation	4,359			7,353
Total adjustments before taxes	45,233			28,929
Income tax effect	17,415			11,138
Total adjustments after taxes	27,818			17,791

Adjusted net income (loss)	$	(13,346	)	$	18,949
Adjusted net income (loss) per diluted share	$	(0.27	)	$	0.48

Schedule 5: Adjusted Net Income (Con’t)

(in thousands, except per share amounts, unaudited)

The Company also included a supplementary adjusted net income (loss) calculation to reflect exclusion of derivative conversion payments during the second quarter of 2015 and cash severance costs recorded during the second quarter of 2014 due to executive departures.

	Three Months Ended
	June 30,
	2015			2014
Net income (loss)	$	(41,164	)	$	1,158

Adjustments to net income (loss):
Derivative loss	5,478			27,307
Derivative cash settlements	15,189			(5,915		)
Derivative conversion payment (1)	10,472			—
Loss on sale of oil and gas properties	—			184
Severance costs	—			2,922
Abandonment and impairment of unproved properties	14,527			—
Exploratory dry hole costs	5,680			—
Stock-based compensation	4,359			7,353
Total adjustments before taxes	55,705			31,851
Income tax effect	21,446			12,263
Total adjustments after taxes	34,259			19,588

Adjusted net income (loss)	$	(6,905	)	$	20,746
Adjusted net income (loss) per diluted share	$	(0.14	)	$	0.52

(1) We paid $10.5 million to convert our three-way collars, scheduled to settle in the third and fourth quarters of 2015, to two-way collars during the second quarter of 2015.

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 income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

	Three Months Ended
	June 30,
	2015			2014
Net income (loss)	$	(41,164	)	$	1,158
Exploration	5,748			96
Depreciation, depletion and amortization	69,925			54,117
Abandonment and impairment of unproved properties	14,527			—
Stock-based compensation	4,359			7,353
Loss on sale of oil and gas properties	—			184
Interest expense	14,468			9,434
Derivative loss	5,478			27,307
Derivative cash settlements	15,189			(5,915		)
Income tax (benefit) expense	(25,007		)	725

Adjusted EBITDAX	$	63,523		$	94,459

Schedule 6: Adjusted EBITDAX (Con’t)

(in thousands, except per share amounts, unaudited)

The Company also included a supplementary adjusted EBITDAX calculation to reflect exclusion of derivative conversion payments during the second quarter of 2015 and cash severance costs recorded during the second quarter of 2014 due to executive departures.

	Three Months Ended
	June 30,
	2015			2014
Net income (loss)	$	(41,164	)	$	1,158
Exploration	5,748			96
Depreciation, depletion and amortization	69,925			54,117
Abandonment and impairment of unproved properties	14,527			—
Stock-based compensation	4,359			7,353
Severance costs	—			2,922
Loss on sale of oil and gas properties	—			184
Interest expense	14,468			9,434
Derivative loss	5,478			27,307
Derivative cash settlements	15,189			(5,915		)
Derivative conversion payment (1)	10,472			—
Income tax (benefit) expense	(25,007		)	725

Adjusted EBITDAX	$	73,995		$	97,381

(1) We paid $10.5 million to convert our three-way collars, scheduled to settle in the third and fourth quarters of 2015, to two-way collars during the second quarter of 2015.

Schedule 7: Estimated 2014 3-Stream Sales Volumes

The following estimates are based on internal BCEI calculations which convert previously reported 2-stream sales volumes in the Rocky Mountain region to 3-stream commodity mix. No assurances can be provided to the accuracy of these figures as they are based on a variety of assumptions related, but not limited, to wet gas shrink and NGL yields.

	Three Months Ended				Twelve Months Ended
	March 31, 2014	June 30, 2014	September 30, 2014	December 31, 2014	December 31, 2014
Rocky Mountains
Oil (Bbl/d)	9,987	12,163	13,606	13,520	12,332
NGLs (Bbl/d)	2,417	2,886	3,483	3,430	3,058
Natural Gas (Mcf/d)	18,614	22,229	26,822	26,417	23,551
Total Equivalent (Boe/d)	15,506	18,754	21,559	21,353	19,315
Total Equivalent (MBoe)	1,395.6	1,706.6	1,983.4	1,964.5	7,050.0
Mid-Continent
Oil (Bbl/d)	2,949	2,962	2,965	3,367	3,062
NGLs (Bbl/d)	1,006	919	1,079	1,154	1,040
Natural Gas (Mcf/d)	9,887	11,445	11,581	12,106	11,261
Total Equivalent (Boe/d)	5,602	5,788	5,974	6,538	5,978
Total Equivalent (MBoe)	504.2	526.7	549.6	601.5	2,182.0
Total Company
Oil (Bbl/d)	12,936	15,125	16,571	16,887	15,394
NGLs (Bbl/d)	3,423	3,805	4,562	4,584	4,098
Natural Gas (Mcf/d)	28,501	33,674	38,403	38,523	34,812
Total Equivalent (Boe/d)	21,108	24,542	27,533	27,891	25,293
Total Equivalent (MBoe)	1,899.7	2,233.3	2,533.0	2,566.0	9,231.9