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Bonanza Creek Energy Announces Third Quarter 2016 Financial and Operating Results

  • Third quarter production volumes averaged 21.0 MBoe per day, exceeding the midpoint of guidance by 5%

  • Improving operational efficiency resulted in the fifth consecutive quarter of reductions in Rockies LOE and midstream expense; Rockies upstream LOE of $4.09/Boe

  • GAAP cash provided by operating activities of $17.5 million; adjusted EBITDAX(1) of $25.1 million; GAAP net loss of $0.71 per diluted share; adjusted net loss(1) of $0.35 per diluted share

  • Updated 2016 guidance reflects increased production and reduced LOE and midstream expense

(1) Non-GAAP measure, see attached Reconciliation Schedules.

DENVER, Nov. 09, 2016 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today announces its third quarter 2016 financial and operating results.

Third Quarter 2016 Results

For the third quarter of 2016, the Company reported average daily production of 21.0 MBoe per day, a 10% sequential decrease from the second quarter of 2016, and a 28% decrease from the third quarter of 2015. The reduction in production volumes is a result of suspended drilling and completion operations at the end of the first quarter of 2016. Product mix for the third quarter of 2016 was 52% oil, 22% NGLs, and 26% natural gas.

Net revenue for the third quarter of 2016 was $49.3 million, a 10% sequential decrease from the second quarter of 2016 and a 32% decrease from the third quarter of 2015. Crude oil accounted for approximately 77% of total revenue. Differentials for the Company's Rocky Mountain oil production during the quarter averaged approximately $9.64 per Bbl. Average realized prices for the third quarter of 2016 are presented below.

Average Realized Prices
Three Months Ended
September 30, 2016
Before
Derivatives
After
Derivatives
Oil (per Bbl) (1)37.45 41.74
Gas (per Mcf) (2)2.31 2.31
NGL (per Bbl)10.80 10.80
Boe (Per Boe)25.57 27.83
(1) Crude oil sales includes $104,000 and $46,000 of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2016 and 2015, respectively.
(2) Natural gas sales includes $381,000 and $291,000 of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2016 and 2015, respectively.

The Company's Rocky Mountain region has lowered its cost structure significantly on a sequential basis by reducing its LOE and midstream operating expense by $2.3 million and $0.3 million, respectively, from the second quarter of 2016. Rockies LOE and midstream expense for the third quarter of 2016 was $6.4 million and $1.2 million, respectively. Total Company LOE for the third quarter of 2016 was $9.9 million, or $5.13 per Boe, compared to $10.7 million, or $5.08 per Boe in the second quarter of 2016, and $17.2 million, or $6.44 per Boe in the third quarter of 2015. The Company continues to execute on cost saving initiatives resulting in a 20% year over year reduction in per unit LOE in a period of declining production. Below is a breakout of the Company's regional LOE and gas plant and midstream operating expense for the third quarter of 2016.

Lease Operating Expense
Three Months Ended September 30, 2016
Rocky Mountain Mid-Continent Total Company
($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)
LOE$6,403 $4.09 $3,490 $9.61 $9,893 $5.13
Gas plant and midstream operating expense1,237 0.79 1,637 4.51 2,874 1.49
Total$7,640 $4.88 $5,127 $14.12 $12,767 $6.62

Recurring cash general and administrative ("G&A") expense, which excludes stock compensation and advisor fees, for the third quarter of 2016 was $10.9 million, or $5.65 per Boe. This compares to recurring cash G&A expense of $10.9 million, or $5.13 per Boe in the second quarter of 2016, and $13.5 million, or $5.07 per Boe in the third quarter of 2015. Total G&A expense for the third quarter of 2016 was $18.7 million, or $9.68 per Boe. This compares to G&A expense of $17.8 million, or $6.69 per Boe in the third quarter of 2015 and $13.2 million, or $6.26 per Boe in the second quarter of 2016. Total G&A expense has increased sequentially by 41% from the second quarter of 2016, and has increased by 5% from the third quarter of 2015. The increase to G&A during the third quarter of 2016 was a result of advisor fees incurred in connection with the Company's evaluation of certain financing alternatives of $5.9 million.

Depreciation, depletion and amortization ("DD&A") for third quarter of 2016 was $27.3 million, or $14.15 per Boe, a 3% sequential decrease on a per unit basis from the second quarter of 2016 and a 36% decrease on a per unit basis from the third quarter 2015.

During the third quarter, the Company incurred upstream CAPEX of approximately $1.0 million, which related to lease extensions and pumping units in the Wattenberg field. This compares to upstream CAPEX of $77.8 million in the third quarter of 2015. Year to date, 2016 total CAPEX was $18.5 million, of which $2.1 million was attributable to the Company's midstream subsidiary, Rocky Mountain Infrastructure, LLC ("RMI").

Reported GAAP net loss for the third quarter of 2016 was $34.9 million, or $0.71 per diluted share, compared to a net loss of $112.3 million, or $2.25 per diluted share, for the third quarter of 2015. Adjusted net loss for the third quarter of 2016 was $17.4 million, or $0.35 per diluted share, compared to an adjusted net loss of $3.6 million, or $0.07 per diluted share for the third quarter of 2015, and an adjusted net loss of $19.7 million, or $0.40 per diluted share for the second quarter of 2016. Adjusted EBITDAX for the third quarter of 2016 was $25.1 million, a 66% decrease compared to $73.3 million for the third quarter of 2015 and a 9% sequential decrease from the second quarter of 2016.

Recurring cash G&A, adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Recurring cash G&A is defined as GAAP G&A expense excluding stock compensation and non-recurring items such as severance costs and advisory fees. See Schedule 1 for general and administrative break-out of stock-based compensation and schedule 6 for the break out of severance costs and advisor fees. For adjusted net income and adjusted EBITDAX, please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures.

The table below summarizes the Company's quarterly and year to date results as compared to guidance provided in the second quarter earnings release. Updated twelve month guidance is included in the Fourth Quarter Guidance and Update section of this release.

Third Quarter Guidance vs Actual Summary
Three Months Ended September 30, 2016
Guidance Actual
Production (MBoe/d)19.6 – 20.2 21.0
Twelve Months Ended
December 31, 2016
Nine Months Ended
September 30, 2016
Guidance Actual
LOE ($MM)$44 – $48 $33.9
Midstream ($MM)$14 – $16 $10.2
Recurring cash G&A ($MM)*$40 – $44 $34.3
Production taxes (% of pre-derivative realization)6% – 7% 7.8%
CAPEX ($MM)$25 – $35 $18.5
* Recurring cash G&A guidance is a non-GAAP measure that is exclusive of the Company's stock based compensation, one-time severance charges of $2.2 million in the first quarter of 2016, and advisor fees of $5.9 million in the third quarter of 2016. The Company does not guide to GAAP G&A expense as it has less certainty to the stock based compensation and non-recurring portions of GAAP G&A.

Operations Update

Rocky Mountain Region – Wattenberg

Production from the Rocky Mountain region during the third quarter of 2016, averaged 17.0 MBoe/d, or 81% of total Company volumes. The production was comprised of 52% crude oil, 23% NGLs, and 25% natural gas. Rocky Mountain average daily sales volumes decreased sequentially by 11% from the second quarter of 2016 and decreased 28% compared to the third quarter of 2015 due to suspended drilling and completion activity.

The Company did not drill or complete any horizontal wells during the third quarter as it idled its development program at the end of the first quarter. At the end of the third quarter, the Company had six drilled uncompleted wells, consisting of four standard reach and two extended reach laterals. The Company does not currently have any plans to restart drilling or completion activity in the fourth quarter of 2016.

Mid-Continent Region – Cotton Valley

The Mid-Continent region contributed 3.9 MBoe/d, or 19% of total Company net sales volumes for the third quarter of 2016, and was comprised of 55% crude oil, 15% NGLs, and 30% natural gas. Sales volumes decreased sequentially by 6% from the second quarter of 2016 and decreased 26% compared to the third quarter of 2015 as a result of suspended drilling and completions activity.

Financial and Risk Management Update

Debt and Liquidity

The Company has a $1.0 billion revolving credit facility, which was redetermined on October 31, the "Redetermination Date" to an approved borrowing base and commitment amount of $150 million. As of September 30, 2016, the Company had borrowings under its credit facility of $229.3 million and cash totaling $133.4 million. As the outstanding borrowings on the credit facility exceed the newly redetermined borrowing base, the Company, under the terms of the agreement, has 20 days from the Redetermination Date to notify the bank group of its intended method to cure the deficiency. To cure the deficiency, the Company may elect to, a) repay advances such that the deficiency is cured within a 30-day period, b) pledge additional oil and gas properties acceptable to the lenders to eliminate the deficiency, c) elect to repay the deficiency amount in 6 equal monthly installments, or d) a combination of options b and c. As of the end of the third quarter, the Company had two remaining deficiency payments payable to the bank group related to its borrowing base deficiency resulting from the May 20, 2016 redetermination, the first of which was paid on October 13, 2016, with the last payment due in November.

As of September 30, 2016, the Company was not in compliance with its interest coverage ratio covenant under its credit facility. The interest coverage ratio as set forth in the credit facility is to remain above 2.5x. At the end of the third quarter, the Company's interest coverage ratio was 2.3x. The Company is currently in discussions with its credit facility lending syndicate to negotiate a waiver, amendment or forbearance agreement. If the Company is unable to obtain one of the aforementioned remedies, the lenders could give notice of acceleration as a result of this non-compliance. The Company was in compliance with its remaining two financial covenants under its credit facility, with a senior secured debt to TTM EBITDAX ratio of 1.7x, and a current ratio of 2.4x. The Company's credit facility covenants require a secured debt to TTM EBITDAX ratio of less than 2.5x and a current ratio of greater than 1.0x.

On November 8, 2016, the Company made the bond interest payment on its $500 million issue of 6.75% senior unsecured notes to the indenture trustee, which was due on October 15, 2016. By making the $17.0 million interest payment within the 30-day grace period, the Company remains in compliance with its senior unsecured notes.

The Company continues to work with its advisors, and is currently in discussions with various stakeholders, regarding a potential (i) debt for equity exchange or (ii) private secured financing transaction.

Please review the Company's quarterly report on Form 10-Q filed with the Securities Exchange Commission on November 9, 2016 for further information regarding the Company's debt and liquidity.

Commodity Derivatives Positions

The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of September 30, 2016 and settling quarterly:

Settlement Period Volume (Bbls/d) Contract Type Swap Price
4Q 2016 2,303 Fixed Price Swap $52.83
Settlement Period Volume (Bbls/d) Contract Type Floor Price
4Q 2016 4,031 Floor (Long Put) $51.01

Fourth Quarter Guidance and Update

The Company is providing updated cost and CAPEX guidance for the fourth quarter of 2016 that reflects a continued improvement in cost structure and lower than expected PDP declines. As a result, the Company has increased its production guidance for the full year 2016, reduced the midpoint of its full year guidance for LOE, midstream expense, and CAPEX. The table below provides updated guidance for the fourth quarter and full year of 2016.

Fourth Quarter Guidance Summary
Three Months Ended
December 31, 2016
Twelve Months Ended
December 31, 2016
Production (MBoe/d)17.7 – 18.3 21.5 – 21.7
LOE ($MM) $43 – $46
Midstream expense ($MM) $12 – $14
Recurring cash G&A ($/Boe)* $44 – $46
Production taxes (% of pre-derivative realization) 6% – 7%
Total CAPEX $25 – $27
* Recurring cash G&A guidance is a non-GAAP measure that is exclusive of the Company's stock based compensation, one-time severance charges of $2.2 million in the first quarter of 2016, and advisor fees of $5.9 million in the third quarter of 2016. The Company does not guide to GAAP G&A expense as it has less certainty to the stock based compensation and non-recurring portions of GAAP G&A.

Conference Call Information
The Company will not be hosting a conference call to discuss its third quarter results.

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 Mountain region 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 updated 2016 guidance; drilling and completion expectations for the remainder of 2016; and the impact of redeterminations of the Company's borrowing base and covenant breaches under the Company's revolving credit facility and the Company's ability to cure such deficiencies. 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, 2015, filed on February 29, 2016, 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.


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

Three Months Ended
September 30,
Nine Months Ended
September 30,
2016 2015 2016 2015
Operating net revenues:
Oil and gas sales$49,325 $72,149 $148,029 $235,647
Operating expenses:
Lease operating expense9,893 17,155 33,928 51,710
Gas plant and midstream operating expense2,874 3,081 10,198 8,685
Severance and ad valorem taxes4,100 2,411 11,531 13,055
Exploration 6,979 943 13,225
Depreciation, depletion and amortization27,296 58,635 84,602 187,564
Impairment of oil and gas properties 166,780 10,000 166,780
Abandonment and impairment of unproved properties7,682 1,630 24,463 21,627
Unused commitments1,688 3,460
General and administrative (including $1,863, $3,164, $7,249 and $10,951, respectively, of stock-based compensation)18,671 17,818 49,591 56,292
Total operating expenses72,204 274,489 228,716 518,938
Loss from operations(22,879) (202,340) (80,687) (283,291)
Other income (expense):
Derivative gain (loss)2,206 37,894 (11,724) 51,272
Interest expense(15,142) (14,073) (46,216) (42,779)
Gain on termination fee 6,000
Other gain (loss)913 (2,077) 1,011 (1,929)
Total other income (expense)(12,023) 21,744 (50,929) 6,564
Loss from operations before taxes(34,902) (180,596) (131,616) (276,727)
Income tax benefit 68,297 104,843
Net loss$(34,902) $(112,299) (131,616) $(171,884)
Basic and diluted net loss per common share$(0.71) $(2.25) $(2.67) $(3.56)
Basic and diluted weighted-average common shares outstanding49,324 48,962 49,244 47,485

  • The Company follows the two-class method when computing the basic and diluted 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
September 30,
Nine Months Ended
September 30,
2016 2015 2016 2015
Cash flows from operating activities:
Net loss$(34,902) $(112,299) $(131,616) $(171,884)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization27,296 58,635 84,602 187,564
Deferred income tax benefit (69,051) (105,595)
Impairment of oil and gas properties 166,780 10,000 166,780
Abandonment and impairment of unproved properties7,682 1,630 24,463 21,627
Dry hole expense(61) 1,948 905 7,628
Stock-based compensation1,865 3,164 7,249 10,951
Amortization of deferred financing costs and debt premium426 466 2,705 1,692
Accretion of contractual obligation for land acquisition 116 814
Derivative (gain) loss(2,206) (37,894) 11,724 (51,272)
Derivative cash settlements4,348 37,717 15,749 88,372
Other1,923 328 127 283
Changes in current assets and liabilities:
Accounts receivable6,027 9,934 29,442 28,253
Prepaid expenses and other assets301 2,342 (1,047) 994
Accounts payable and accrued liabilities5,205 11,149 (23,252) (11,905)
Settlement of asset retirement obligations(398) (259) (473) (778)
Net cash provided by operating activities17,506 74,706 30,578 173,524
Cash flows from investing activities:
Acquisition of oil and gas properties(103) (1,688) (919) (13,602)
Payments of contractual obligation (12,000) (12,000) (12,000)
Exploration and development of oil and gas properties(4,738) (78,025) (47,491) (361,131)
Increase in restricted cash(5,172) 2,926 (7,707) 2,926
Additions to property and equipment - non oil and gas(145) (1,741) (106) (2,390)
Net cash used in investing activities(10,158) (90,528) (68,223) (386,197)
Cash flows from financing activities:
Proceeds from credit facility 28,000 209,000 115,000
Payments to credit facility(44,000) (2,000) (58,667) (79,000)
Proceeds from sale of common stock 209,300
Offering costs related to sale of common stock (13) (6,620)
Offering costs related to sale of Senior Notes (6) (99)
Payment of employee tax withholdings in exchange for the return of common stock(10) (145) (283) (2,593)
Deferred restructuring charges
Deferred financing costs(79) (28) (316) (573)
Net cash provided by (used in) financing activities(44,089) 25,808 149,734 235,415
Net change in cash and cash equivalents(36,741) 9,986 112,089 22,742
Cash and cash equivalents:
Beginning of period170,171 15,340 21,341 2,584
End of period$133,430 $25,326 $133,430 $25,326


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

September 30, December 31,
2016 2015
ASSETS
Current assets$176,746 $120,074
Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion and amortization of $636,917 in 2015 214,922
Total property and equipment, net1,039,289 922,344
Other noncurrent assets8,362 2,301
Total Assets$1,224,397 $1,259,641
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities$1,101,870 $135,973
Long-term debt 871,666
Other long-term liabilities37,771 42,595
Total Liabilities1,139,641 1,050,234
Stockholders’ Equity84,756 209,407
Total Liabilities and Stockholders’ Equity$1,224,397 $1,259,641


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

Three Months Ended
September 30,
Nine Months Ended
September 30,
2016 2015 2016 2015
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains8,845 14,083 10,403 13,947
Mid-Continent2,152 2,774 2,286 2,809
Total10,997 16,857 12,689 16,756
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains$35.77 $37.49 $32.15 $41.52
Mid-Continent$44.33 $45.89 $41.64 $49.70
Composite (before derivatives) (1)$37.45 $38.87 $33.86 $42.89
Composite (after derivatives) (1)$41.74 $62.75 $38.39 $61.76
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains3,916 4,409 3,702 3,859
Mid-Continent607 862 667 958
Total4,523 5,271 4,369 4,817
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains$9.77 $8.01 $11.08 $12.15
Mid-Continent$17.44 $7.37 $15.38 $13.50
Composite (before derivatives)$10.80 $7.90 $11.73 $12.42
Composite (after derivatives)$10.80 $7.91 $11.73 $12.42
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains25,536 30,914 27,202 29,843
Mid-Continent7,141 10,022 7,478 9,750
Total32,677 40,936 34,680 39,593
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains$2.14 $1.89 $1.54 $1.85
Mid-Continent$2.93 $2.88 $2.33 $3.03
Composite (before derivatives) (2)$2.31 $2.13 $1.71 $2.14
Composite (after derivatives) (2)$2.31 $2.32 $1.71 $2.33
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains17,017 23,645 18,639 22,780
Mid-Continent3,949 5,306 4,199 5,392
Total20,966 28,951 22,838 28,172
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains$24.05 $26.14 $22.39 $29.90
Mid-Continent$32.13 $30.64 $29.26 $33.77
Composite (before derivatives)$25.57 $27.09 $23.66 $30.64
Composite (after derivatives)$27.83 $41.25 $26.17 $42.13
Total Sales Volumes (MBoe)1,928.9 2,663.5 6,257.5 7,690.8
(1) Crude oil sales includes $104,000 and $46,000 of oil transportation revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2016 and 2015, respectively; and includes $387,000 and $46,000 for the nine months ended September 30, 2016 and 2015, respectively.
(2) Natural gas sales includes $381,000 and $291,000 of gas gathering revenues from third parties, which do not have associated sales volumes, for the three months ended September 30, 2016 and 2015, respectively; and includes $1.1 million and $0.4 million for the nine months ended September 30, 2016 and 2015, respectively.


Schedule 5: Per unit operating margins
(unaudited)

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 Percent
Change
2016 2015 Percent
Change
Production
Oil (MBbl)1,011.7 1,550.8 (35)% 3,476.6 4,574.3 (24)%
Gas (MMcf)3,006.2 3,766.0 (20)% 9,502.2 10,808.8 (12)%
NGL (MBbl)416.2 485.0 (14)% 1,197.2 1,315.0 (9)%
Equivalent (MBoe)1,928.9 2,663.5 (28)% 6,257.5 7,690.8 (19)%
Realized pricing (before derivatives)
Oil ($/Bbl)$37.45 $38.87 (4)% $33.86 $42.89 (21)%
Gas ($/Mcf)$2.31 $2.13 8% 1.71 2.14 (20)%
NGL ($/Bbl)$10.80 $7.91 37% 11.73 12.42 (6)%
Equivalent ($/Boe)$25.57 $27.09 (6)% $23.66 $30.64 (23)%
Per Unit Costs ($/Boe)
Realized price (before derivatives)$25.57 $27.09 (6)% $23.66 30.64 (23)%
LOE5.13 6.44 (20)% $5.42 $6.72 (19)%
Gas plant and midstream operating expense1.49 1.16 28% $1.63 $1.13 44%
Severance and Ad Valorem2.13 0.91 134% $1.84 $1.70 8%
Cash General and Administrative 8.71 5.50 58% $6.77 $5.90 15%
Total cash operating costs$17.46 $14.01 25% $15.66 $15.45 1%
Cash operating margin (before derivatives)$8.11 $13.08 (38)% $8.00 $15.19 (47)%
Derivative Cash Settlements2.26 14.16 (84)% $2.51 11.49 (78)%
Cash operating margin (after derivatives)$10.37 $27.24 (62)% $10.51 26.68 (61)%
Non-cash items
Depreciation Depletion and Amortization14.15 22.01 (36)% $13.52 $24.39 (45)%
Non-cash General and Administrative$0.97 $1.19 (18)% $1.16 $1.42 (18)%

Schedule 6: Adjusted Net Income (Loss)
(in thousands, except per share amounts, unaudited)

Adjusted net income is a supplemental non-GAAP financial measure that is used by management to present recurring profitability by excluding items which are non-recurring in nature or items which are not easily estimable. Management believes adjusted net income provides external users of the Company's consolidated financial statements such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. 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 an applicable rate that approximates the Company's effective tax rate in each period. Adjusted net income is not a measure of net income as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of adjusted net income (loss).

Three Months Ended
September 30,
Nine Months Ended
September 30,
2016 2015 2016 2015
Net loss $(34,902) $(112,299) $(131,616) $(171,884)
Adjustments to net loss:
Derivative (gain) loss (2,206) (37,894) 11,724 (51,272)
Derivative cash settlements 4,348 37,717 15,749 88,372
Impairment of proved properties 166,780 10,000 166,780
Abandonment and impairment of unproved properties 7,682 1,630 24,463 21,627
Exploratory dry hole (61) 1,948 905 7,628
Stock-based compensation 1,865 3,164 7,249 10,951
Advisor fees related to financial alternatives (1) 5,918 5,918
Cash severance costs (1) 1,155 2,162 1,155
Gain on termination fee (2) (6,000)
Derivative conversion payment (3) 10,472
Litigation settlement (4) 1,638 1,638
Total adjustments before taxes 17,546 176,138 72,170 257,351
Income tax effect % 38.5% % 38.5%
Total adjustments after taxes $17,546 $108,677 $72,170 $158,271
Adjusted net loss $(17,356) $(3,622) $(59,446) $(13,613)
Adjusted net loss per diluted share $(0.35) $(0.07) $(1.21) $(0.29)
Diluted weighted-average common shares outstanding 49,324 48,962 49,244 47,485
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) Gain resulting from termination fee on unsuccessful RMI transaction during the first quarter of 2016.
(3) Conversion payment is included as a portion of derivative cash settlements on the statement of cash flows and results from hedge restructuring in the second quarter of 2015 from 3-way collars to 2-way collars.
(4) Included as a portion of other income (loss) on the consolidated statement of operations.

Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management to provide a metric of the Company's ability to internally generate funds for exploration and development of oil and gas properties and service debt. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes adjusted EBITDAX provides and external users of the Company’s consolidated financial statements, such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income or cash flows as determined by GAAP.

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

Three Months Ended
September 30,
Nine Months Ended
September 30,
2016 2015 2016 2015
Net loss $(34,902) $(112,299) $(131,616) $(171,884)
Exploration 6,979 943 13,225
Depreciation, depletion and amortization 27,296 58,635 84,602 187,564
Impairment of proved properties 166,780 10,000 166,780
Abandonment and impairment of unproved properties 7,682 1,630 24,463 21,627
Stock-based compensation 1,865 3,164 7,249 10,951
Cash severance costs (1) 1,155 2,162 1,155
Advisor fees related to financial alternatives (1) 5,918 5,918
Gain on termination fee (2) (6,000)
Derivative conversion payment (3) 10,472
Litigation Settlement (4) 1,638 1,638
Interest expense 15,142 14,073 46,216 42,779
Derivative (gain) loss (2,206) (37,894) 11,724 (51,272)
Derivative cash settlements 4,348 37,717 15,749 88,372
Income tax benefit (68,297) (104,843)
Adjusted EBITDAX $25,143 $73,281 $71,410 $216,564
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) Gain resulting from termination fee on unsuccessful RMI transaction during the first quarter of 2016.
(3) Conversion payment is included as a portion of derivative cash settlements on the statement of cash flows and results from hedge restructuring in the second quarter of 2015 from 3-way collars to 2-way collars.
(4) Included as a portion of other income (loss) on the consolidated statement of operations.


For further information, please contact: James R. Edwards Director - Investor Relations 720-440-6136 jedwards@bonanzacrk.com

Source:Bonanza Creek Energy, Inc.