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Bonanza Creek Energy Announces Fourth Quarter and Full Year 2016 Financial and Operating Results

  • Fourth quarter sales volumes averaged 18.2 MBoe per day, compared to guidance midpoint of 18.0 MBoe per day
  • GAAP cash used in operating activities of $16.0 million; adjusted EBITDAX(1) of $14.5 million; GAAP net loss of $1.37 per diluted share; adjusted net loss(1) of $0.57 per diluted share
  • Year-end 2016 proved reserves of 90.7 MMBoe, 55% oil, and 56% proved developed
    (1) Non-GAAP measure, see attached Reconciliation Schedules.

DENVER, March 15, 2017 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE:BCEI) (the "Company") today announces its fourth quarter and full year 2016 financial and operating results.

Fourth Quarter 2016 Results

Three Months Ended Twelve Months Ended
Avg. Daily Sales Volumes: 12/31/2016 9/30/2016 % Change 12/31/2016 12/31/2015 % Change
Crude oil (Bbls/d) 9,058 10,997 (18)% 11,776 16,636 (29)%
Natural gas (Mcf/d) 29,664 32,677 (9)% 33,419 39,866 (16)%
Natural gas liquids (Bbls/d) 4,237 4,523 (6)% 4,336 4,992 (13)%
Crude oil equivalent (Boe/d) 18,239 20,966 (13)% 21,682 28,272 (23)%
Product Mix
Crude oil 50% 52% 54% 59%
Natural gas 27% 26% 26% 23%
Natural gas liquids 23% 22% 20% 18%
Average Sales Prices (before derivatives):
Crude oil (per Bbl) $41.96 $37.45 12% 35.42 40.98 (14)%
Natural gas (per Mcf) $2.45 $2.31 6% 1.88 1.82 3%
Natural gas liquids (per Bbl) $14.40 $10.80 33% 12.39 9.49 31%
Crude oil equivalent (per Boe) $28.17 $25.57 10% 24.61 28.36 (13)%
Product Revenue (in thousands) $47,266 $49,325 (4)% $195,295 $292,679 (33)%

For the fourth quarter of 2016, the Company reported reduced production volumes on a sequential and annual basis due to inactivity. At the end of the first quarter of 2016, the Company released its last drilling rig and suspended drilling and completion operations. Since the beginning of the second quarter, the Company has focused efforts on maximizing production from PDP wells, meeting or beating the midpoint of its production guidance range in each quarter of 2016. Realized pricing before the effects of derivative activity was stronger in the fourth quarter of 2016 compared to the previous quarter resulting in a moderated decrease to top line revenue on a sequential basis. For the full year of 2016, the Company reported reduced revenues due to both decreased production volumes as well as weaker realized pricing when compared to the 2015 fiscal year.

Given the lack of drilling and completion activity during the year, a key focus of the Company was to materially reduce operating expenses while retaining its commitment to safety and the environment. The table below provides operating expenses comparatively on a sequential quarterly basis and annual year-over-year basis.

Three Months Ended Twelve Months Ended
Operating Expenses 12/31/2016 9/30/2016 % Change 12/31/2016 12/31/2015 % Change
Lease operating expense 9,743 9,893 (2)% 43,671 65,038 (33)%
Gas plant and midstream operating expense 2,628 2,874 (9)% 12,826 11,368 13%
Severance and ad valorem taxes 3,773 4,100 (8)% 15,304 18,629 (18)%
Exploration 3 NM 946 15,827 (94)%
Depreciation, depletion and amortization 26,613 27,296 (3)% 111,215 244,921 (55)%
Impairment of oil and gas properties —% 10,000 740,478 (99)%
Abandonment and impairment of unproved properties 229 7,682 (97)% 24,692 33,543 (26)%
Unused commitments 4,226 1,688 NM 7,686 NM
Contract settlement expense 21,000 NM 21,000 NM
Recurring Cash G&A (1) 11,374 10,890 4% 45,636 54,612 (16)%
Stock Compensation 1,643 1,863 (12)% 8,892 14,552 (39)%
Cash severance costs —% 2,162 1,155 87%
Advisor fees related to financial alternatives 14,457 5,918 144% 20,375 NM
Total General and Administrative 27,474 18,671 47% 77,065 70,319 10%
Total Operating Expenses 95,689 72,204 33% 324,405 1,200,123 (73)%
Adjusted cash operating expense (2) 27,518 27,757 (1)% 117,437 149,647 (22)%
(1) Recurring cash G&A is a non-GAAP measure that is exclusive of the Company's stock based compensation, one-time severance charges and advisor fees. See schedule 10 for reconciliation to GAAP G&A.
(2) Adjusted cash operating expense is a non-GAAP measure and includes recurring cash costs associated with producing hydrocarbons and includes lease operating expense, midstream operating expense, severance and ad valorem taxes, and recurring cash G&A. This measure excludes non-cash items and items which are considered one-time in nature. The Company provides this metric as it believes it provides comparable cash operating costs between periods.

Throughout 2016, the Company implemented cost-saving measures that resulted in a material reduction in adjusted cash operating expense. The reduction was led by decreases in LOE and recurring cash G&A. The decrease in DD&A in 2016 is due to the lower depreciable asset base resulting from the large property impairment in 2015. Notable increases in expenses in 2016 were severance and advisory expense, unused commitments, contract settlement, and midstream operating expense. The severance and advisory expenses incurred in 2016 relate to reduction-in-force payments made to employees in the first quarter of 2016, and the advisory fees relate to efforts to explore financial alternatives and restructuring options. Unused commitments relate to pipeline volume deficiencies the Company incurred during the year. Increases to midstream operating expense year over year are due to the build-out of the RMI asset during 2015, which made up 43% of the total midstream operating expense in the fourth quarter of 2016. A breakout of the LOE and midstream operating expense by region is included in the table below.

Regional Breakout
Three Months Ended December 31, 2016
Rocky Mountain Mid-Continent Total Company
($M) ($/Boe) ($M) ($/Boe) ($M) ($/Boe)
LOE$6,696 $4.99 $3,047 $9.04 $9,743 $5.81
Gas plant and midstream operating expense1,127 0.84 1,501 4.45 2,628 1.57
Total$7,823 $5.83 $4,548 $13.49 $12,371 $7.38

Reported net loss for the fourth quarter of 2016 was $67.3 million, or $1.37 per diluted share, compared to a net loss of $573.7 million, or $12.08 per diluted share, for the fourth quarter of 2015. The quarterly GAAP net loss for 2015 was driven largely by total property impairments of $585.6 million. Adjusted net loss for the fourth quarter of 2016 was $27.9 million, or $0.57 per diluted share, compared to adjusted net loss of $8.4 million, or $0.17 per diluted share for the fourth quarter of 2015.

Adjusted EBITDAX for the fourth quarter of 2016 was $14.5 million, a 78% decrease compared to $67.1 million for the fourth quarter of 2015.

Adjusted net loss and adjusted EBITDAX are non-GAAP financial measures. 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 annual results as compared to previously provided guidance.

Guidance vs Actual Summary
Three Months Ended December 31, 2016
Guidance Actual
Production (MBoe/d)17.7 – 18.3 18.2
Twelve Months Ended December 31, 2016
Guidance Actual
Production (MBoe/d)21.5 – 21.7 21.7
LOE ($MM)$43 – $46 $43.7
Midstream ($MM)$12 – $14 $12.8
Recurring cash G&A ($MM)*$44 – $46 $45.6
Production taxes (% of pre-derivative realization)6% – 7% 7.8%
CAPEX ($MM)$25 – $27 $21.7
* 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 $20.4 million. The Company does not guide to GAAP G&A expense because of the uncertain nature of the amount of stock based compensation expense in a given period and the non-recurring portions of GAAP G&A. See schedule 10 for reconciliation to GAAP G&A.

2016 Proved Reserves

As of year-end 2016, Bonanza Creek reported proved reserves of 90.7 MMBoe, which represents a decrease of 10% from 2015. The Company's year-end 2016 proved reserves were comprised of 50.1 MMBbls of oil, 17.5 MMBbls of NGLs, and 138.0 Bcf of natural gas and were 56% proved developed. The Company recorded a 40% decline in its year-end 2016 Mid-Continent proved reserves from 2015 as a result of writing off all remaining proved undeveloped reserves in the region. These proved undeveloped reserves were removed as the Company's drilling plans did not contemplate the development of these proved undeveloped locations within the required five-year period. The PV-10 value for estimated proved reserves as of December 31, 2016 was $276.9 million. PV-10 is a non-GAAP measure and is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. A reconciliation of PV-10 to its most comparable GAAP financial measure is provided in Schedule 9 of this release. The 12-month average benchmark pricing used to estimate SEC proved reserves for crude oil and natural gas was $42.75 per Bbl of WTI crude oil and $2.48 per MMBtu of natural gas at Henry Hub before differential adjustments. Year-end 2016 benchmark prices for oil, and natural gas were 15%, and 4% lower, respectively, from year-end 2015 SEC pricing. After differential adjustments, the Company's SEC pricing realizations for year-end 2016 were $38.42 per Bbl of oil, $12.12 per Bbl of NGLs, and $2.07 per Mcf of natural gas. As of year-end 2016, the Company estimates that its exit-to-exit corporate PDP decline rate will be 25% in 2017, 20% in 2018, and 16% in 2019. The table below summarizes estimated proved reserves for 2016.

Proved Reserves As of December 31, 2015 As of December 31, 2016
Reserve Category Equiv. (MMBoe)% of Total Oil (MMBbls)NGLs (MMBbls)Gas (Bcf)Equiv. (MMBoe)% of TotalYoY Change
Proved Developed Producing 49.7 49% 25.3 9.8 83.6 49.0 54% (1)%
Proved Developed Non-Producing 2.4 2% 1.0 0.2 2.3 1.6 2% (33)%
Proved Undeveloped 49.2 49% 23.8 7.6 52.1 40.1 44% (18)%
Total Proved Reserves 101.3 100% 50.1 17.5 138.0 90.7 100% (10)%
Regional Summary
Rocky Mountain 80.1 79% 42.5 16.4 114.2 78.0 86% (3)%
Mid-Continent 21.2 21% 7.6 1.2 23.9 12.7 14% (40)%
Total Proved Reserves 101.3 100% 50.1 17.5 138.0 90.7 100% (10)%

Note: Totals may not foot due to rounding

Restructuring Update and 2017 Outlook

The Company continues to pursue a restructuring under the terms set forth in the Restructuring Support and Lock-Up Agreement ("RSA"), filed with the SEC on December 23, 2016. Since filing voluntary petitions under chapter 11 of the United Sates Code in the United States Bankruptcy Court for the District of Delaware, on January 4, 2017, the Company has been granted all of its first day motions which include, among others things the ability to conduct its normal business activities, pay its trade vendors, royalty interest owners, and partners. The Company is scheduled to have a confirmation hearing on the proposed Plan of Reorganization and the associated Disclosure Statement on April 3, 2017 and expects to emerge from Chapter 11 during the first half of 2017.

Certain holders of the Company’s common shares have formed an ad hoc committee of equity security holders (the “Ad Hoc Equity Committee”) and have filed motions and other pleadings in the Chapter 11 cases adverse to the restructuring contemplated by the RSA. In particular, on February 3, 2017, the Ad Hoc Equity Committee filed a motion (the “Trustee Motion”) for an order appointing a trustee pursuant to section 1104(a) of the Bankruptcy Code or, in the alternative, appointing an examiner pursuant to section 1104(c) of the Bankruptcy Code. If the Trustee Motion were granted with respect to the Ad Hoc Equity Committee’s request for the appointment of a trustee, then the Company and its subsidiaries would cease to be debtors in possession and the affairs and management of the business would be controlled by a court-appointed trustee.

Upon emergence from bankruptcy, the Company expects to resume drilling and completion activity. The activity program that was presented to the signatories of the RSA contemplates a one-rig program, with an intermittent second rig to satisfy leasehold obligations. The capital requirements expected for the proposed program would range from $160 – $180 million for the time period from May to December 2017. This program assumes drilling 61 and completing 53 net standard reach lateral equivalent ("SRLe") wells in its Wattenberg program, investing a modest amount on infrastructure, participating in economic non-operated wells, and investing $3 – $5 million in Mid-Continent recompletions. The Company expects approximately 65% of its 53 SRLe completions to be XRLs. The proposed capital budget is dependent on emergence from bankruptcy and approval from a newly appointed board.

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 future reserves; EUR estimates and PDP decline rates; development and completion expectations and strategy; anticipated operating and capital costs; and the timing of emergence from Chapter 11. 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: further declines in natural gas, oil and NGL prices, including any impact on the Company's asset carrying values or reserves arising from price declines; general economic conditions, including the performance of financial markets and interest rates; the Company's liquidity; drilling programs and results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions and uncertainties inherent in projecting future drilling and completion activities and costs; uncertainties of negotiations to result in an agreement or a completed transaction; 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, 2016, filed on March 15, 2017, 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 December 31, Twelve Months Ended December 31,
2016 2015 2016 2015
Operating net revenues:
Oil and gas sales$47,266 $57,032 $195,295 $292,679
Operating expenses:
Lease operating expense9,743 13,214 43,671 65,038
Midstream operating expense2,628 2,797 12,826 11,368
Severance and ad valorem taxes3,773 5,574 15,304 18,629
Exploration3 2,602 946 15,827
Depreciation, depletion and amortization26,613 57,357 111,215 244,921
Impairment of oil and gas properties 573,698 10,000 740,478
Abandonment and impairment of unproved properties229 11,916 24,692 33,543
Unused commitments4,226 7,686
Contract settlement expense21,000 21,000
General and administrative (including $1,643, $3,601, $8,892, and $14,552 respectively, of stock compensation)27,474 14,027 77,065 70,319
Total operating expenses95,689 681,185 324,405 1,200,123
Income (loss) from operations(48,423) (624,153) (129,110) (907,444)
Other income (expense):
Derivative gain (loss)490 5,286 (11,234) 56,558
Interest expense(15,842) (14,273) (62,058) (57,052)
Gain on termination fee 6,000
Other income (loss)(3,559) (574) (2,548) (2,503)
Total other income (expense)(18,911) (9,561) (69,840) (2,997)
Income (loss) from continuing operations before taxes(67,334) (633,714) (198,950) (910,441)
Income tax benefit (expense) 60,051 164,894
Net income (loss)$(67,334) $(573,663) $(198,950) $(745,547)
Net income (loss) per basic common share$(1.37) $(12.08) $(4.04) $(15.57)
Net income (loss) per diluted common share$(1.37) $(12.08) $(4.04) $(15.57)
Basic weighted-average common shares outstanding49,338 49,030 49,268 47,874
Diluted weighted-average common shares outstanding49,338 49,030 49,268 47,874
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 14 – Earnings per Share in the Form 10-K, for a detailed calculation.

Schedule 2: Statement of Cash Flows
(in thousands, unaudited)

Three Months Ended December 31, Twelve Months Ended December 31,
2016 2015 2016 2015
Cash flows from operating activities:
Net income (loss)$(67,334) $(573,663) $(198,950) $(745,547)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization26,613 57,357 111,215 244,921
Deferred income taxes (60,072) (165,667)
Impairment of oil and gas properties 573,698 10,000 740,478
Abandonment and impairment of unproved properties229 11,916 24,692 33,543
Dry hole expense(33) (1,998) 872 5,630
Stock-based compensation1,643 3,601 8,892 14,552
Amortization of deferred financing costs and debt premium475 588 3,180 2,280
Accretion of contractual obligation for land acquisition 814
Derivative (gain) loss(490) (5,286) 11,234 (56,558)
Derivative cash settlements2,584 42,624 18,333 130,996
Inventory adjustment4,390 4,390
Other(450) 1,146 (323) 1,429
Changes in current assets and liabilities:
Accounts receivable5,840 6,977 35,282 35,230
Prepaid expenses and other assets(791) 7,450 (1,838) 8,444
Accounts payable and accrued liabilities11,636 (11,750) (11,616) (23,655)
Settlement of asset retirement obligations(327) (89) (800) (867)
Net cash provided by operating activities(16,015) 52,499 14,563 226,023
Cash flows from investing activities:
Acquisition of oil and gas properties821 (2,668) (98) (16,270)
Deposits for acquisitions 1,549 1,549
Proceeds from sale of oil and gas properties
Payments of contractual obligation (12,000) (12,000)
Exploration and development of oil and gas properties(4,853) (64,900) (52,344) (425,918)
Natural gas plant capital expenditures 1 (112)
(Increase) decrease in restricted cash5,094 61 (2,613) 2,987
Additions to property and equipment - non oil and gas(240) (419) (346) (2,809)
Net cash used in investing activities822 (66,376) (67,401) (452,573)
Cash flows from financing activities:
Proceeds from credit facility 22,000 209,000 137,000
Payments to credit facility(37,666) (12,000) (96,333) (91,000)
Proceeds from sale of common stock 8 209,308
Offering costs related to sale of common stock (6,620)
Proceeds from sale of Senior Notes
Offering costs related to sale of Senior Notes (99)
Payment of employee tax withholdings in exchange for the return of common stock(6) (90) (289) (2,683)
Deferred financing costs (26) (316) (599)
Net cash provided by (used in) financing activities(37,672) 9,892 112,062 245,307
Net change in cash and cash equivalents(52,865) (3,985) 59,224 18,757
Cash and cash equivalents:
Beginning of period133,430 25,326 21,341 2,584
End of period$80,565 $21,341 $80,565 $21,341

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

December 31, December 31,
2016 2015
ASSETS
Current assets$112,428 $120,074
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $636,917 in 2015 214,922
Total property and equipment, net1,018,968 922,344
Other assets3,082 2,301
Total Assets$1,134,478 $1,259,641
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities$1,070,466 $135,973
Long-term debt 871,666
Other long-term liabilities44,951 42,595
Total Liabilities1,115,417 1,050,234
Stockholders’ Equity19,061 209,407
Total Liabilities and Stockholders’ Equity$1,134,478 $1,259,641

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

Three Months Ended
December 31,
2016 2015
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains7,042 13,655
Mid-Continent2,016 2,627
Total9,058 16,282
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains$40.10 $33.90
Mid-Continent48.44 41.69
Composite (before derivatives)41.96 35.15
Composite (after derivatives)45.06 63.15
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains3,695 4,745
Mid-Continent542 765
Total4,237 5,510
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains (1)$13.19 $12.82
Mid-Continent (1)22.65 (65.98)
Composite (before derivatives)(1)14.40 1.88
Composite (after derivatives)14.40 1.88
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains23,061 31,236
Mid-Continent6,603 9,441
Total29,664 40,677
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains (2)$2.29 $0.49
Mid-Continent3.01 2.32
Composite (before derivatives)(2)2.45 0.91
Composite (after derivatives)2.45 1.10
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains14,581 23,606
Mid-Continent3,658 4,966
Total18,239 28,572
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains$26.34 $22.83
Mid-Continent35.47 16.29
Composite (before derivatives)28.17 21.70
Composite (after derivatives)29.71 37.91
Total Sales Volumes (MBoe)1,678.0 2,628.6
(1) Fourth quarter 2015 includes pricing adjustments of approximately $5.2 million. Without the effect of these adjustments, realized pricing would have been approximately $11.60/Bbl in the Rocky Mountain region, $14.90/Bbl in the Mid-Continent region, and $12.06/Bbl (before derivatives) on a corporate basis.
(2) Fourth quarter 2015 includes a State of Colorado royalty adjustment of approximately $2.5 million. Without the effect of this adjustment, realized pricing would have been approximately $1.35/Mcf in the Rocky Mountain region and $1.57/Mcf (before derivatives) on a corporate basis.

Schedule 5: Per unit operating margins
(unaudited)

For the Three Months Ended December 31, For the Twelve Months Ended December 31,
2016 2015
Percent Change 2016 2015 Percent Change
Per Unit Costs ($/Boe)
Realized price (before derivatives)$28.17 $21.70 30% $24.61 $28.36 (13)%
LOE$5.81 $5.03 16% $5.50 $6.30 (13)%
Midstream expense$1.57 $1.06 48% $1.62 $1.10 47%
Severance and Ad Valorem$2.25 $2.12 6% $1.93 $1.81 7%
Cash General and Administrative (1)$15.39 $3.97 288% $8.59 $5.40 59%
Total cash operating costs$25.02 $12.18 105% $17.64 $14.61 21%
Cash operating margin (before derivatives)$3.15 $9.52 (67)% $6.97 $13.75 (49)%
Derivative Cash Settlements$1.54 $16.21 (90)% $2.31 $12.70 (82)%
Cash operating margin (after derivatives)$4.69 $25.73 (82)% $9.28 $26.45 (65)%
Non-cash items
Depreciation Depletion and Amortization$15.86 $21.82 (27)% $14.01 $23.73 (41)%
Non-cash General and Administrative$0.98 $1.37 (28)% $1.12 $1.41 (21)%
(1) Cash general and administrative expense excludes stock based compensation of $1.6 million and $3.6 million for the three-month periods ended December 31, 2016 and 2015, respectively, and $8.9 million and $14.5 million for the twelve-month periods ended December 31, 2016 and 2015, respectively.

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

Adjusted net loss 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 loss as net loss 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 (2) one-time transactions and then (3) 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 loss is not a measure of net loss as determined by GAAP.

The following table provides a reconciliation of net loss (GAAP) to adjusted net loss (non-GAAP):

Three Months Ended Twelve Months Ended
December 31, December 31,
2016 2015 2016 2015
Net income (loss)$(67,334) $(573,663) $(198,950) $(745,547)
Adjustments to net income (loss):
Derivative (gain) loss(490) (5,286) 11,234 (56,558)
Derivative cash settlements2,584 42,624 18,333 130,996
Impairment of proved properties 573,698 10,000 740,478
Abandonment and impairment of unproved properties229 11,916 24,692 33,543
Exploratory dry hole expense(33) (1,998) 872 5,630
Stock-based compensation (1)1,643 3,601 8,892 14,552
Advisor fees related to financial alternatives (1)14,457 20,375
Cash severance costs (1) 2,162 1,155
Gain on termination fee 6,000
Contract settlement expense21,000 21,000
Derivative conversion payment (2) 10,472
Litigation settlement (3) 1,638
Total adjustments before taxes39,390 624,555 123,560 881,906
Income tax effect (59,333) (160,988)
Total adjustments after taxes$39,390 $565,222 $123,560 $720,918
Adjusted net income (loss)$(27,944) $(8,441) $(75,390) $(24,629)
Adjusted net income (loss) per diluted share$(0.57) $(0.17) $(1.53) $(0.51)
Diluted weighted-average common shares outstanding49,338 49,030 49,268 47,874
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) 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.
(3) Included as a portion of other income (loss) on the consolidated statement of operations.

Schedule 7: 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 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 GAAP financial measures of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

Three Months Ended Twelve Months Ended
December 31, December 31,
2016 2015 2016 2015
Net Income (loss)$(67,334) $(573,663) $(198,950) $(745,547)
Exploration3 2,602 946 15,827
Depreciation, depletion and amortization26,613 57,357 111,215 244,921
Impairment of proved properties 573,698 10,000 740,478
Abandonment and impairment of unproved properties229 11,916 24,692 33,543
Stock-based Compensation (1)1,643 3,601 8,892 14,552
Cash severance costs (1) 2,162 1,155
Advisor fees related to financial alternatives (1)14,457 20,375
Gain on termination fee (6,000)
Contract settlement expense21,000 21,000
Derivative conversion payment (2) 10,472
Litigation Settlement (3) 1,638
Interest expense15,842 14,273 62,058 57,052
Derivative (gain) loss(490) (5,286) 11,234 (56,558)
Derivative cash settlements2,584 42,624 18,333 130,996
Income tax (benefit) expense (60,051) (164,894)
Adjusted EBITDAX$14,547 $67,071 $85,957 $283,635
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) 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.
(3) Included as a portion of other income (loss) on the consolidated statement of operations.

Schedule 8: Costs Incurred

For the Year Ended December 31,
2016
(in thousands)
Acquisition(1) $97
Development(2) 31,209
Exploration 74
Total(3) $31,380
(1) Acquisition costs for unproved properties were $97,000. Acquisition costs for proved properties were $0.
(2) Development costs include workover costs of $6.0 million.
(3) Includes amounts relating to asset retirement obligations of $3.1 million.

Schedule 9: PV-10 of Estimated Proved Reserves

PV-10 is derived from the 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 proved oil and natural gas reserves.

The following table presents a reconciliation of GAAP Standardized Measure to the non-GAAP financial measure of PV-10.

December 31,
(in thousands) 2016
PV-10 $276,955
Present value of future income taxes discounted at 10% (1)
Standardized Measure $276,955
(1) The tax basis of the Company's oil and gas properties as of December 31, 2016 provides more tax deduction than income generation when reserve estimates were prepared using 2016 SEC pricing.

Schedule 10: Recurring cash G&A
(in thousands, unaudited)

Recurring cash G&A 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 recurring cash G&A as GAAP general and administrative expense exclusive of the Company's stock based compensation and one-time charges, such as severance costs and advisor fees. The Company refers to recurring cash G&A to provide typical cash G&A costs that are planned for in a given period. Recurring cash G&A is not a measure fully inclusive measure of general and administrative expense as determined by GAAP.

The following table presents a reconciliation of GAAP financial measures of G&A expense to the non-GAAP financial measure of recurring cash G&A.

Three Months Ended Twelve Months Ended
12/31/2016 9/30/2016 12/31/2016 12/31/2015
General and Administrative Expense $27,474 $18,671 $77,065 $70,319
Stock Compensation (1,643) (1,863) (8,892) (14,552)
Cash severance costs (2,162) (1,155)
Advisor fees related to financial alternatives (14,457) (5,918) (20,375)
Recurring cash G&A Expense $11,374 $10,890 $45,636 $54,612


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

Source:Bonanza Creek Energy, Inc.