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Bonanza Creek Energy Announces Fourth Quarter and Full Year 2015 Financial and Operating Results

  • Fourth quarter sales volumes averaged 28.6 MBoe per day, compared to guidance midpoint of 27.8 MBoe per day
  • 2015 proved reserves of 101.3 MMBoe, 57% oil, and 51% proved developed; all-in reserve replacement of 216%; 26% increase to Wattenberg PDP year over year
  • Adjusted EBITDAX(1) of $67.1 million; adjusted net loss(1) of $8.4 million, or $0.17 per diluted share
  • Fourth quarter CAPEX of $31 million, full year CAPEX of $404 million, below guidance midpoint of $420 million
  • The Company is re-marketing its Rocky Mountain Infrastructure ("RMI") assets as its previously announced transaction with Meritage Midstream did not close


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

DENVER, Feb. 29, 2016 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE:BCEI) today announces its fourth quarter and full year 2015 financial and operating results. The Company has posted a related investor presentation to its website at www.bonanzacrk.com and has scheduled a conference call to discuss these results on March 1, 2016 at 9:00 AM Mountain Time (11:00 AM Eastern Time). Dial-in information is included at the end of this release.

Richard Carty, President and Chief Executive Officer, commented, "Despite the challenging macro environment the industry was faced with in 2015, Bonanza Creek rapidly adapted to the circumstances by significantly reducing cost structure and improving well and field performance, resulting in a more competitive and capital efficient Company. During 2015, capital costs were reduced by over 40% per well, cash operating costs decreased by more than 30%, and our field performance increased significantly through advances in well design and increased infrastructure. We are very pleased with the field-wide response from our facilities engineering accomplishments in 2015, which validate the transition from a focus on drilling activity towards a dedication to base production optimization in 2016. As we have not reached mutually agreeable terms on which to close our contemplated RMI divestiture, we have terminated the agreement and are released from exclusivity terms allowing us to resume talks with other interested parties."

Fourth Quarter 2015 Results

For the fourth quarter of 2015, the Company reported average daily sales volumes of 28.6 MBoe per day, above the Company's provided guidance of 27.5 - 28.1 MBoe/d. Fourth quarter 2015 sales volumes represent a 10% increase from the fourth quarter of 2014 (2% increase adjusted for estimated 3-stream volumes), and a 1% sequential decrease from the third quarter of 2015. Product mix for the quarter was 57% oil, 19% NGLs, and 24% natural gas.

Net revenue for the fourth quarter of 2015 was $57.0 million, compared to $123.2 million for the fourth quarter of 2014. Crude oil and liquids accounted for approximately 85% of total revenue. Average realized prices for the fourth quarter of 2015 are presented below.

Average Realized Prices
For the Three Months Ended
December 31, 2015
Before
Derivatives
After
Derivatives
Oil (per Bbl)$35.15 $63.15
Gas (per Mcf)$0.91 $1.10
NGL (per Bbl)$1.88 $1.88
Boe (Per Boe)$21.70 $37.91

Fourth quarter realized natural gas pricing was adversely affected by a State of Colorado royalty adjustment in the Company's Rocky Mountain region, which totaled $2.5 million. Realized pricing without these adjustments would have been approximately $1.57/Mcf and closer to the Company's historical and expected realized price of approximately 75% of Henry Hub. The Company's realized prices for NGLs in the fourth quarter were also adversely affected by pricing adjustments of approximately $5.2 million, primarily in the Mid-Continent region. The Company's fourth quarter realized pricing for NGLs without the effect of the adjustments would have been approximately $12.06 per Bbl, similar to the Company's historical and expected realized price of approximately 25% of WTI.

Cash operating costs, which includes lease operating expense, production taxes, and cash G&A, for the fourth quarter were $32.0 million, or $12.18 per Boe, a 31% decrease from $17.75 per Boe ($16.47 per Boe adjusted for estimated three-stream volumes), in the fourth quarter of 2014, and a 13% sequential decrease from the third quarter of 2015. Cash operating costs for the quarter were sequentially lower, largely as a result of decreased cash G&A and LOE. A summary of the LOE components by region is presented below:

Lease Operating Expense
(in thousands)Three Months Ended December 31, 2015
Rocky Mountain Mid-Continent Total Company
($MM) ($/Boe) ($MM) ($/Boe) ($MM) ($/Boe)
LOE$8,611 $3.97 $4,603 $10.08 $13,214 $5.03
Midstream OPEX1,277 0.59 1,520 3.33 2,797 1.06
Total$9,888 $4.55 $6,123 $13.40 $16,011 $6.09

Depreciation, depletion and amortization for fourth quarter of 2015 was $57.4 million, or $21.82 per Boe, a 26% decrease from $29.51 per Boe ($27.40 per Boe adjusted for estimated 3-stream volumes), in the fourth quarter 2014. The Company recorded no DD&A expense related to its Mid-Continent and RMI assets as both were classified as held for sale throughout the fourth quarter.

Total CAPEX for the fourth quarter of 2015 were $31.0 million, of which $7.3 million was attributable to the Company's RMI midstream subsidiary. For the 12-month period ending on December 31, 2015, total costs incurred for the Company were $404.2 million, or 4% below the midpoint of its guidance. During 2015, the Company incurred costs related to RMI of $50.7 million.

Reported net loss for the fourth quarter of 2015 was $573.7 million, or $12.08 per diluted share, compared to a net loss of $43.2 million, or $1.06 per diluted share, for fourth quarter 2014. The quarterly GAAP net loss for 2015 was driven largely by total property impairments of $585.6 million. Adjusted net loss for fourth quarter 2015 was $8.4 million, or $0.17 per diluted share, compared to adjusted net income of $10.0 million, or $0.24 per diluted share for fourth quarter 2014.

Adjusted EBITDAX for fourth quarter 2015 was $67.1 million, a 35% decrease compared to $102.4 million for the fourth quarter 2014. The related decrease in realized price per Boe over the two periods was approximately 58%.

Adjusted net income 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
3 Months Ended December
31, 2015
12 Months Ended December
31, 2015
Guidance Actual Guidance Actual
Production (MBoe/d)27.5 – 28.1 28.6 28.0 – 28.2 28.3
LOE ($/Boe) $6.09 $7.75 – $8.00 $7.40
Cash G&A ($/Boe) $3.97 $5.75 – $6.00 $5.40
Production taxes (% of pre-derivative realization) 9.8% 6% 6.4%
CAPEX (in millions)
E&P CAPEX $24 $353
RMI CAPEX $7 $51
Total CAPEX (in millions) $31 $410 – $430 $404

2015 Proved Reserves

As of year-end 2015, Bonanza Creek reported proved reserves of 101.3 MMBoe, which represents an increase of 13% from 2014 and all-in reserve replacement of 216%. 2015 proved reserves were comprised of 57.4 MMBbls of oil, 19.9 MMBbls of NGLs, and 144.2 Bcf of natural gas and were 51% proved developed. PV-10 value for estimated proved reserves was $327.8 million, of which, 81% is attributable to oil, 11% is attributable to gas, and 8% is attributable to NGLs. 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. In the Rocky Mountain region, the Company increased proved reserves 17.6% to 80.2 MMBoe. The 12-month average benchmark pricing used to estimate SEC proved reserves for crude oil, natural gas, and natural gas liquids was $50.28 per Bbl of WTI crude oil and $2.59 per MMBtu of natural gas at Henry Hub before differential adjustments. Year-end 2015 prices for oil, NGLs, and natural gas were 47%, and 40% lower, respectively, from year-end 2014 SEC pricing. After differential adjustments, the Company's SEC pricing realizations were $44.00 per Bbl of oil, $12.90 per Bbl of NGLs, and $2.33 per Mcf of natural gas. As of year-end 2015, the Company estimates that its exit-to-exit corporate PDP decline rate will be 40% in 2016, 25% in 2017, and 19% in 2018. The table below summarizes estimated proved reserves for 2015.

Proved Reserves As of December 31, 2014 As of December 31, 2015
Reserve Category Equiv. (MMBoe)% of Total Oil (MMBbls)NGLs (MMBbls)Gas (Bcf)Equiv. (MMBoe)% of TotalYoY Change
Proved Developed Producing 41.3 46% 27.6 10.0 72.9 49.7 49%20%
Proved Developed Non-Producing 5.0 6% 1.3 0.3 4.6 2.4 2%(52)%
Proved Undeveloped 43.2 48% 28.5 9.6 66.7 49.2 49%14%
Total Proved Reserves 89.5 100% 57.4 19.9 144.2 101.3 100%13%
Regional Summary
Rocky Mountain 68.1 76% 45.8 17.1 103.8 80.2 79%18%
Mid-Continent 21.4 24% 11.6 2.8 40.4 21.2 21%(1)%
Total Proved Reserves 89.5 100% 57.4 19.9 144.2 101.3 100%13%
Note: Totals may not foot due to rounding

As of December 31, 2015, the Company estimated a total net risked resource of approximately 566 MMBOE, which was comprised of 54% oil, 23% NGLs, and 23% natural gas. Within the risked resource, the Company has identified approximately 2,300 total net undeveloped locations with a corresponding 515 MMBoe of risked resource. The table below summarizes the Company's 2015 undeveloped risked resource for its Rocky Mountain region.

Undeveloped Risked Resource As of December 31, 2015
Gross Locations Net Locations Net Risked
Resource (MMBoe)
Rocky Mountain Region
Proved Undeveloped 204 164 41,408
Unproved Resource 3,038 1,920 454,755
Total 3,242 2,084 496,163


Operations Update

Rocky Mountain Region

During the quarter, the Company connected 14 operated gross (11.6 net) horizontal wells to sales, all of which were standard reach laterals ("SRLs"). In addition to the operated wells brought online during the fourth quarter, the Company had 0.8 net non-operated wells connected into production. For the full year 2015, the Company completed and connected into sales 95 gross (77.1 net) wells, consisting of 51.5 net SRLs, 9.6 net medium reach laterals ("MRLs"), and 15.2 net extended reach laterals ("XRLs"). For the fourth quarter, upstream capital costs for the region were approximately $21 million.

During the fourth quarter of 2015, production from the Rocky Mountain region averaged 23.6 MBoe/d, or 83% of total Company volumes. The production was comprised of 58% crude oil, 20% NGLs and 22% natural gas. On a 3-stream basis, sales volumes increased by 11% compared to the fourth quarter of 2014 and were essentially unchanged compared to the third quarter of 2015.

Rocky Mountain Region – Well Productivity

During 2015, Bonanza Creek tested many aspects of its well design including plug-and-perf completions, mono-bores, and increased sand loading. In 2016, the Company plans to continue evaluating its completion fluid design to further reduce well costs while maintaining well performance.

As of November 2015, the Company was executing SRL wells for $3.4 million and XRL wells for $5.0 million. The Company is currently executing SRLs for $2.6 million and expects current XRL well costs to be $4.5 million. The Company's contemplated 2016 drilling program will be in areas with existing infrastructure and as such, expected well costs will be unburdened by field level infrastructure. The Company has approximately 1,400 drilling locations that can access existing field level infrastructure, such as gas gathering, centralized compression, and centralized production facilities owned by RMI. The Company expects 2016 well cost execution of approximately $2.5 million for SRLs and $4.3 million for XRLs through continued cost reduction efforts and applying changes to well design as discussed below.

In 2016, the Company is implementing a mono-bore well design. This design removes the cost of the intermediate string of casing while also decreasing drilling time by approximately one day. Among other operational advantages of mono-bore design, the observed savings in materials and time reduces the completed well cost of an SRL by approximately $100,000. To date, the Company has executed seven successful mono-bore wells and plans to utilize this well design for the remainder of its program in 2016. As part of the design change to mono-bore, the Company has also moved to a plug-and-perf completion method which is more conducive to downhole well construction associated with mono-bore drilling operations. The Company expects completed well costs of plug-and-perf wells on multi-well pads to be similar to those of sliding sleeves.

During the third quarter of 2015, the Company initiated a completion design test, comparing well performance of plug-and-perf completions to sliding sleeves. Previous to this test, the Company had utilized a sliding sleeve design. The test included two well pads adjacent to each other, with one 3-well pad utilizing plug-and-perf design and the adjacent 2-well pad utilizing sliding sleeves. After approximately 180 days of production, the wells completed utilizing plug-and-perf completions appear to be performing significantly better than the sliding sleeve completions. Given the negligible cost increase of plug-and-perf, the applicability to mono-bore well construction, and the resulting potential increase in well productivity, the Company plans to execute a majority of its 2016 program with plug-and-perf completions.

During the first quarter of 2015, Bonanza Creek initiated an increased sand loading test that involved 6 wells using 1,500 pounds of sand per lateral foot. These wells demonstrated a 22% uplift in cumulative production for the first 300 days of production. The Company continues to monitor these test wells and has since observed a 24% uplift in cumulative production in the first 480 days of production. From a cost perspective, the Company expects the additional sand loading in today's environment to be negligibly different from a well completed in 2015 using 1,000 pounds of sand per lateral foot.

In the second half of 2015, the Company observed lower line pressures in both its field and regional system. These reduced pressures coupled with additional gas evacuation routes and base decline management initiatives, have led to lower base decline rates in the Company's eastern acreage. As of year-end 2015, when comparing 2015 vintage wells to wells completed in 2014, the Company has observed lower decline rates, which have resulted in an increase of approximately 15% in cumulative first-year production

Rocky Mountain Region – Northern Delineation

Bonanza Creek has been monitoring the results of its third northern delineation well, which was completed in the third quarter of 2015. The well was drilled with a 9,000 foot lateral but encountered unexpected faulting in the lateral, resulting in approximately 50% of the wellbore lateral landing in the unproductive A Marl. After the initial 150 days of production, the well produced 21.7 MBoe. Adjusting for unproductive lateral length in the A Marl, the Company estimates an EUR of 410 MBoe, further validating the productivity of the Niobrara chalk in the northern acreage. The Company has taken the data from this well to calibrate its models for faulting to improve future lateral placement and well performance of its northern acreage wells which it intends to drill as prices recover and activity accelerates.

Mid-Continent Region – Cotton Valley Development

During the fourth quarter of 2015, Bonanza Creek tied 2 gross and net wells into sales and performed 7 gross (6.2 net) re-completions. For the fourth quarter, capital costs incurred for the region were approximately $2.8 million.

The Mid-Continent region contributed 5.0 MBoe/d, or 17% of total Company net sales volumes for the fourth quarter of 2015, which was comprised of 53% crude oil, 15% NGLs and 32% natural gas. Sales volumes decreased by 24% compared to the fourth quarter of 2014 and were down by approximately 6% sequentially from the third quarter.

During the fourth quarter of 2015, the Company released its last remaining drilling rig in its Mid-Continent region. As of December 31, 2015 the Company classified this asset as held for sale.

Financial and Risk Management Update

Debt and Liquidity

Bonanza Creek has a $1.0 billion revolving credit facility, which has an approved borrowing base and commitment amount of $475 million. As of December 31, 2015, the Company had borrowings under its credit facility of $79.0 million, a letter of credit totaling $12.0 million, and cash totaling $21.3 million, resulting in total liquidity of $405 million under its current commitment amount. 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. As of December 31, 2015, the Company was in compliance with all financial covenants, with a senior secured debt to EBITDAX ratio of 0.3x, an interest coverage ratio of 4.8x, and a current ratio of 3.5x.

Commodity Derivatives Positions

The following table summarizes the Company’s crude oil commodity derivative positions as of December 31, 2015:

Settlement Period Collar Volume (Bbls/d) Average Short Floor Average Floor Average Ceiling
FY 2016 5,500 $70.00 $85.00 $96.83


2016 Outlook, 1Q16 CAPEX, Production, and Cost Guidance

Bonanza Creek announced the termination of its membership interest purchase agreement to divest its RMI subsidiary. In connection with the termination, Meritage Midstream is obligated to pay Bonanza Creek $6.0 million. Bonanza Creek plans to re-market the assets. With respect to its Mid-Continent asset, the Company currently has the asset held for sale and will provide an update on the divestiture process once it has entered into a definitive agreement related to the sale.

The Company is providing CAPEX, production, and cost guidance for the first quarter of 2016 and expects to issue additional guidance for the remainder of 2016 at a later date. During the first quarter, the Company expects to operate one rig in its Rocky Mountain region and connect approximately 12 gross and net wells into sales. Upon completion of these 12 wells the Company expects to cease drilling and completion activities and focus on base production optimization. The Company will re-evaluate its rig program and provide additional guidance for the remainder of the year upon the conclusion of a contemplated sale of RMI or material changes to the pricing or service cost environment.

1Q16 Guidance
Production (MBoe/d)23.7 – 24.0
LOE ($/Boe)$7.50 – $7.60
Midstream ($/Boe)$2.25 – $2.35
Cash G&A ($/Boe)$5.80 – $5.90
Production taxes (% of pre-derivative realization)6% – 7%
E&P CAPEX (in millions)$35 – $40

Conference Call Information

Bonanza Creek will host a conference call to discuss these financial and operating results on March 1, 2016 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). A webcast of this event will be available on the Company’s website at www.bonanzacrk.com, for one year after the event. Dial-in information for the conference call is included below.

TypePhone NumberPasscode
Domestic Participant877-311-325540521008
International Participant916-582-359440521008
Replay855-859-205640521008

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; the closing of any divestiture transaction and 2016 outlook and guidance. 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, 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 December 31, Twelve Months Ended December 31,
2015 2014 2015 2014
Operating net revenues:
Oil and gas sales$57,032 $123,185 $292,679 $558,633
Operating expenses:
Lease operating expense16,011 19,095 76,406 72,411
Severance and ad valorem taxes5,574 8,083 18,629 50,430
Exploration2,602 876 15,827 5,346
Depreciation, depletion and amortization57,357 70,300 244,921 228,789
Impairment of oil and gas properties573,698 167,592 740,478 167,592
Abandonment and impairment of unproved properties11,916 33,543
General and administrative (including $3,601, $3,404, $14,552, and $12,638 respectively, of stock compensation)14,027 18,496 70,319 81,571
Total operating expenses681,185 284,442 1,200,123 606,139
Income (loss) from operations(624,153) (161,257) (907,444) (47,506)
Other income (expense):
Derivative gain (loss)5,286 106,854 56,558 121,615
Interest expense(14,273) (14,450) (57,052) (46,447)
Other income (loss)(574) (52) (2,503) 345
Total other income (expense)(9,561) 92,352 (2,997) 75,513
Income (loss) from continuing operations before taxes(633,714) (68,905) (910,441) 28,007
Income tax benefit (expense)60,051 26,155 164,894 (11,025)
Income (loss) from continuing operations$(573,663) $(42,750) $
(745,547) $16,982
Discontinued operations:
Loss from operations associated with oil and gas properties held for sale (85)
Gain (loss) on sale of oil and gas properties (717) 5,496
Income tax benefit (expense) 279 (2,110)
Gain (loss) from discontinued operations (438) 3,301
Net income (loss)$(573,663) $(43,188) $(745,547) $20,283
Basic income (loss) per share:
Income (loss) from continuing operations$(12.08) $(1.04) $(15.57) $0.42
Income from discontinued operations$ $(0.01) $ $0.08
Net income (loss) per common share$(12.08) $(1.05) $(15.57) $0.50
Diluted income (loss) per share:
Income (loss) from continuing operations$(12.08) $(1.05) $(15.57) $0.41
Income (loss) from discontinued operations$ (0.01) $ $0.08
Net income (loss) per common share$(12.08) $(1.06) $(15.57) $0.49
Basic weighted-average common shares outstanding49,030 40,665 47,874 40,139
Diluted weighted-average common shares outstanding49,030 40,842 47,874 40,290

  • 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,
2015 2014 2015 2014
Cash flows from operating activities:
Net income (loss)$(573,663) $(43,188) $(745,547) $20,283
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization57,357 70,300 244,921 228,856
Deferred income taxes(60,072) (26,383) (165,667) 12,986
Impairment of oil and gas properties573,698 167,592 740,478 167,592
Abandonment and impairment of unproved properties11,916 33,543
Dry hole expense(1,998) 5,630
Stock-based compensation3,601 3,404 14,552 20,716
Amortization of deferred financing costs and debt premium588 556 2,280 1,588
Accretion of contractual obligation for land acquisition 582 814 1,153
Derivative (gain) loss(5,286) (106,854) (56,558) (121,615)
Gain on sale of oil and gas properties 891 (5,322)
Other1,146 1,429 (12)
Changes in current assets and liabilities:
Accounts receivable6,977 2,461 35,230 (21,376)
Prepaid expenses and other assets7,450 (8,598) 8,444 (10,884)
Accounts payable and accrued liabilities(11,750) (7,742) (23,655) 35,392
Settlement of asset retirement obligations(89) (1,263) (867) (1,637)
Net cash provided by operating activities9,875 51,758 95,027 327,720
Cash flows from investing activities:
Acquisition of oil and gas properties(2,668) (683) (16,270) (179,566)
Deposits for acquisitions1,549 (1,549) 1,549 (1,549)
Proceeds from sale of oil and gas properties 700 6,700
Payments of contractual obligation (12,000) (12,000)
Exploration and development of oil and gas properties(64,900) (192,618) (425,918) (641,204)
Natural gas plant capital expenditures1 (1) (112) (282)
Derivative cash settlements42,624 21,374 130,996 12,238
(Increase) decrease in restricted cash61 2,987 (3,062)
Additions to property and equipment - non oil and gas(419) (818) (2,809) (6,269)
Net cash used in investing activities(23,752) (173,595) (321,577) (824,994)
Cash flows from financing activities:
Proceeds from credit facility22,000 33,000 137,000 263,000
Payments to credit facility(12,000) (91,000) (230,000)
Proceeds from sale of common stock8 209,308
Offering costs related to sale of common stock (6,620)
Proceeds from sale of Senior Notes 300,000
Offering costs related to sale of Senior Notes (203) (99) (7,070)
Payment of employee tax withholdings in exchange for the return of common stock(90) (688) (2,683) (6,007)
Deferred financing costs(26) (306) (599) (647)
Net cash provided by financing activities9,892 31,803 245,307 319,276
Net change in cash and cash equivalents(3,985) (90,034) 18,757 (177,998)
Cash and cash equivalents:
Beginning of period25,326 92,618 2,584 180,582
End of period$21,341 $2,584 $21,341 $2,584

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

December 31, December 31,
2015 2014
ASSETS
Current assets$120,074 $208,475
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $636,917 in 2015 and $- in 2014214,922
Total property and equipment, net922,344 1,756,477
Other assets16,027 41,137
Total Assets$1,273,367 $2,006,089
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities$135,973 $198,447
Long-term debt885,392 840,619
Deferred income taxes 165,667
Other long-term liabilities42,595 61,285
Total Liabilities1,063,960 1,266,018
Stockholders’ Equity209,407 740,071
Total Liabilities and Stockholders’ Equity$1,273,367 $2,006,089

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

Three Months Ended
December 31,
2015 3-Stream
2014 (1)
2-Stream
2014
Wellhead Volumes and Prices
Crude Oil and Condensate Sales Volumes (Bbl/d)
Rocky Mountains13,655 13,520 13,520
Mid-Continent2,627 3,367 3,367
Total16,282 16,887 16,887
Crude Oil and Condensate Realized Prices ($/Bbl)
Rocky Mountains33.90 61.54
Mid-Continent41.69 70.84
Composite (before derivatives)35.15 63.39
Composite (after derivatives)63.15 76.71
Natural Gas Liquids Sales Volumes (Bbl/d)
Rocky Mountains4,745 3,430 54
Mid-Continent765 1154 1154
Total5,510 4,584 1,208
Natural Gas Liquids Realized Prices ($/Bbl)
Rocky Mountains (2)12.82 22.00
Mid-Continent (2)(65.98) 43.45
Composite (before derivatives)(2)1.88 42.48
Composite (after derivatives)1.88 42.48
Natural Gas Sales Volumes (Mcf/d)
Rocky Mountains31,236 26,417 34,682
Mid-Continent9,441 12,106 12,106
Total40,677 38,523 46,787
Natural Gas Realized Prices ($/Mcf)
Rocky Mountains (3)0.49 4.93
Mid-Continent2.32 3.81
Composite (before derivatives)(3)0.91 4.64
Composite (after derivatives)1.10 4.80
Crude Oil Equivalent Sales Volumes (Boe/d)
Rocky Mountains23,606 21,353 19,355
Mid-Continent4,966 6,538 6,538
Total28,572 27,891 25,893
Crude Oil Equivalent Sales Prices ($/Boe)
Rocky Mountains22.83 51.89
Mid-Continent16.29 51.20
Composite (before derivatives)21.70 51.71
Composite (after derivatives)37.91 60.68
Total Sales Volumes (MBoe)2,628,581.3 2,566.0 2,346.4
(1) Fourth 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 10 for estimates of Rocky Mountain region 3-stream sales volumes by quarter for 2014.
(2) 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.
(3) 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 Three Months Ended
December 31,
2015 2014
2-Stream
Percent
Change
2015 2014
3-Stream(1)
Percent
Change
Production
Oil (MBbl)1,497.9 1,553.6 (4)% 1,497.9 1,553.6 (4)%
Gas (MMcf)3,742.3 4,304.4 (13)% 3,742.3 3,544.1 6%
NGL (MBbl)506.9 111.1 356% 506.9 421.7 20%
Equivalent (MBoe)2,628.6 2,382.1 10% 2,628.6 2,566.0 2%
Realized pricing (before derivatives)
Oil ($/Bbl)$35.15 $63.39 (45)%
Gas ($/Mcf)$0.91 $4.64 (80)%
NGL ($/Bbl)$1.88 $42.48 (96)%
Equivalent ($/Boe)$21.70 $51.71 (58)%
Per Unit Costs ($/Boe)
Realized price (before derivatives)$21.70 $51.71 (58)%
LOE$6.09 $8.02 (24)% $6.09 $7.44 (18)%
Severance and Ad Valorem$2.12 $3.39 (37)% $2.12 $3.15 (33)%
Cash General and Administrative (2)$3.97 $6.34 (37)% $3.97 $5.88 (32)%
Total cash operating costs$12.18 $17.75 (31)% $12.18 $16.47 (26)%
Cash operating margin (before derivatives)$9.52 $33.96 (72)%
Derivative Cash Settlements$16.21 $8.97 81%
Cash operating margin (after derivatives)$25.73 $42.93 (40)%
Non-cash items
Depreciation Depletion and Amortization$21.82 $29.51 (26)% $21.82 $27.40 (20)%
Non-cash General and Administrative$1.37 $1.43 (4)% $1.37 $1.33 3%
(1) Volumes and prices are adjusted to reflect estimated 3-stream volumes to provide appropriate comparison to current 3-stream reporting convention. See Schedule 10 for estimated Rocky Mountain region 3-stream sales volumes by quarter for 2014.
(2) Cash general and administrative expense excludes stock based compensation of $3.6 million and $3.4 million for the three-month periods ended December 31, 2015 and 2014, respectively.

Schedule 6: 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 9.5%, and 18.1% for the three and twelve-month periods ended December 31, 2015, respectively, and a tax rate of 38.5% for the three and twelve-month periods ended December 31, 2014. These rates approximate 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 provides a reconciliation of net income (loss) (GAAP) to adjusted net income (loss) (non-GAAP):

Three Months Ended Twelve Months Ended
December 31, December 31,
2015 2014 2015 2014
Net income (loss) $(573,663) $(43,188) $(745,547) $20,283
Adjustments to net income (loss):
Derivative gain (5,286) (106,854) (56,558) (121,615)
Derivative cash settlements 42,624 21,374 130,996 12,238
(Gain) loss on sale of oil and gas properties 891 (5,322)
Impairment of proved properties 573,698 167,592 740,478 167,592
Abandonment and impairment of unproved properties 11,916 33,543
Exploratory dry hole (1,998) 5,630 1,043
Stock-based compensation 3,601 3,404 14,552 20,716
Severance costs (1) 1,155
Litigation settlement (2) 1,638
Total adjustments before taxes 624,555 86,407 871,434 74,652
Income tax effect (59,333) (33,267) (157,730) (28,741)
Total adjustments after taxes $565,222 $53,140 $713,704 $45,911
Adjusted net income (loss) $(8,441) $9,952 $(31,843) $66,194
Adjusted net income (loss) per diluted share $(0.17) $0.24 $(0.67) $1.64
Diluted weighted-average common shares outstanding 49,030 40,842 47,874 40,290
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) 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,
2015 2014 2015 2014
Net Income (loss) $(573,663) $(43,188) $(745,547) $20,283
Exploration 2,602 876 15,827 5,346
Depreciation, depletion and amortization 57,357 70,300 244,921 228,856
Impairment of proved properties 573,698 167,592 740,478 167,592
Abandonment and impairment of unproved properties 11,916 33,543
Stock-based Compensation 3,601 3,404 14,552 20,716
Severance costs (1) 1,155
Litigation settlement (2) 1,638
(Gain) loss on sale of oil and Gas properties 891 (5,322)
Interest expense 14,273 14,450 57,052 46,447
Derivative (gain) loss (5,286) (106,854) (56,558) (121,615)
Derivative cash settlements 42,624 21,374 130,996 12,238
Income tax (benefit) expense (60,051) (26,434) (164,894) 13,135
Adjusted EBITDAX $67,071 $102,411 $273,163 $387,676
(1) Included as a portion of general and administrative expense on the consolidated statement of operations.
(2) Included as a portion of other income (loss) on the consolidated statement of operations.

Schedule 8: Costs Incurred

For the Year Ended
December 31,
2015
(in thousands)
Acquisition(1) $16,270
Development(2)(3) 393,187
Exploration 6,284
Total(4) $415,741
(1) Acquisition costs for unproved properties were $15.3 million. Acquisition costs for proved properties were $1.0 million.
(2) Development costs include workover costs of $10.0 million.
(3) Development costs include gas plant capital expenditures of $0.1 million.
(4) Includes amounts relating to asset retirement obligations of $2.4 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,
2015
(in millions)
PV-10 $327.8
Present value of future income taxes discounted at 10% (1)
Standardized Measure $327.8
(1) The tax basis of the Company's oil and gas properties as of December 31, 2015 provides more tax deduction than income generation when reserve estimates were prepared using 2015 SEC pricing.

Schedule 10: Estimated 2014 3-Stream Sales Volumes

The following estimates are based on internal Company 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)9,98712,16313,60613,520 12,332
NGLs (Bbl/d)2,4172,8863,4833,430 3,058
Natural Gas (Mcf/d)18,61422,22926,82226,417 23,551
Total Equivalent (Boe/d)15,50618,75421,55921,353 19,315
Total Equivalent (MBoe)1,395.61,706.61,983.41,964.5 7,050.0
Mid-Continent
Oil (Bbl/d)2,9492,9622,9653,367 3,062
NGLs (Bbl/d)1,0069191,0791,154 1,040
Natural Gas (Mcf/d)9,88711,44511,58112,106 11,261
Total Equivalent (Boe/d)5,6025,7885,9746,538 5,978
Total Equivalent (MBoe)504.2526.7549.6601.5 2,182.0
Total Company
Oil (Bbl/d)12,93615,12516,57116,887 15,394
NGLs (Bbl/d)3,4233,8054,5624,584 4,098
Natural Gas (Mcf/d)28,50133,67438,40338,523 34,812
Total Equivalent (Boe/d)21,10824,54227,53327,891 25,293
Total Equivalent (MBoe)1,899.72,233.32,533.02,566.0 9,231.9

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

Source:Bonanza Creek Energy, Inc.