Bonanza Creek Energy Reports Financial Results and Increased Crude Oil Production in Third Quarter 2012

Thu Nov 8, 2012 4:59pm EST

* Reuters is not responsible for the content in this press release.

DENVER, November 8, 2012 - Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported its third quarter 2012 operating and financial results.

Third quarter 2012 highlights, as compared to third quarter 2011, include:

  • Production grew by 117% to 9,545 Boe/d, or 878.2 MBoe 

  • Crude oil production was up 140% to 6,306 Bo/d  

  • Net revenues increased by 118% to $59.6 million 

  • Adjusted net income increased 527% to $14.6 million, or $0.37 per diluted share 

  • EBITDAX was up 148% to $39.6 million, or $1.00 per diluted share  

Adjusted net income and EBITDAX are non-GAAP financial measures. For a reconciliation of adjusted net income to net income and EBITDAX to net income, see Schedules 4 and 5 below.

Other highlights include:

  • Ongoing leasing efforts added approximately 5,600 net acres in the Wattenberg Field in the third quarter (previously announced)  

  • Drilled and completed the Company's first horizontal Codell well and spudded the Company's first Niobrara "C" Bench horizontal well and Niobrara "B" Bench extended reach lateral in October 

  • Borrowing base increased on October 30, 2012 from $245 million to $325 million, resulting in pro forma liquidity as of September 30, 2012 of $159.5 million 

"During third quarter, the Company continued to execute on our growth plan achieving record levels of production, even though we experienced flat natural gas sales and higher costs compared to second quarter as a result of maintenance at our Mid-Continent gas processing facility and gathering and processing issues in the Wattenberg Field. While natural gas sales were flat during third quarter, crude sales increased 13% over second quarter driving an 11% increase in revenue and 7% EBITDAX growth. Based on our results through third quarter, we reiterate our 2012 production and capital expenditure guidance," said Michael Starzer, Bonanza Creek's President and Chief Executive Officer.  

Mr. Starzer continued, "We are pleased to see our Niobrara "B" Bench wells continue to improve; in fact the most recent 8 wells have achieved a 30-day average rate of 522 Boe/d, compared to the previously reported 16 well 30-day average of 470 Boe/d. We have de-risked the horizontal Niobrara "B" Bench inventory at 80-acre spacing across our Wattenberg position and are now drilling an extended reach lateral in the Niobrara "B" Bench and horizontal wells into the Niobrara "C" Bench and Codell formation. We are encouraged by the initial results from our first Codell horizontal well and the potential for down-spacing to 40-acres in the Niobrara "B" Bench and will continue to evaluate these upside opportunities over the coming year. These growth catalysts in the Wattenberg, along with down-spacing potential in the oily Cotton Valley sands in Arkansas, could materially increase Bonanza Creek's development runway."

Third Quarter 2012 Financial Results

All amounts discussed below reflect total operations, including discontinued operations.

Average realized prices for the third quarter 2012, before the effect of commodity derivatives, were $87.96 per Bbl of oil, $3.36 per Mcf of natural gas and $56.43 per Bbl of NGLs, compared to $84.79 per Bbl of oil, $5.15 per Mcf of natural gas and $69.49 per Bbl of NGLs for the third quarter 2011.

Net revenue for the third quarter 2012 was $59.6 million, compared to $27.4 million for the third quarter 2011, a 118% increase. Crude oil and liquids revenue accounted for approximately 92% of total revenue for the third quarter 2012.

Lease operating expense ("LOE") for the third quarter 2012 was $8.9 million, or $10.13 per Boe, compared to $5.5 million, or $13.56 per Boe, for the third quarter 2011. The decrease in per unit LOE is primarily attributable to increased volumes. LOE was impacted during the quarter by a $0.7 million charge to the Dorcheat gas plant to procure and install replacement equipment; excluding this charge, LOE was $9.33 per Boe. The Company reaffirms its annual guidance for unit LOE, but expects its full year results to be in the upper end of the range.

General and administrative expense ("G&A") for the third quarter 2012 was $9.3 million, or $10.63 per Boe, compared to $4.2 million, or $10.34 per Boe, for the third quarter 2011. The increase in G&A expense is attributed primarily to the accelerated hiring of new personnel as the Company continues to expand its oil and gas operations. G&A for the third quarter 2012 also includes $1.4 million of non-cash stock compensation expense and $1.4 million of legal fees. Because of uncertainty with respect to the recovery of certain legal expenses and the timing of anticipated additions to its staff during the fourth quarter, the Company is currently reviewing its annual guidance for unit G&A.

EBITDAX for the third quarter 2012 was $39.6 million, or $1.00 per diluted share, compared to $16.0 million for the third quarter 2011, a 148% increase.

Net income for the third quarter 2012 was $3.4 million, or $0.09 per diluted share, compared to $4.8 million, or $0.17 per diluted share, for the third quarter 2011. Adjusted net income for the third quarter 2012 was $14.6 million, or $0.37 per diluted share, compared to adjusted net income of $2.3 million, or $0.08 per diluted share, for the third quarter 2011.

Bonanza Creek began the divestiture process of its California properties in the second quarter 2012. Under generally accepted accounting principles, the California properties are presented as "discontinued operations" for the third quarter 2012 and for the prior-year comparable periods. As a result, production, revenue and expenses associated with these properties have been removed from continuing operations and reported as discontinued operations. In this release, the unaudited Condensed Statement of Operations in Schedule 1 and the unaudited Condensed Balance Sheet in Schedule 3 state the changes to the current period and the prior-year period for the disclosure of the discontinued operations. This supplemental non-GAAP information presents the reported GAAP amounts as compared to the amounts that would have been reported if the California operations were included in continuing operations. Except as noted, all comparisons discussed in this release include the California operations as continuing operations in the current year and the prior year periods as previously reported.

On August 31, 2012, the Company sold the Kern River property in California for approximately $5.1 million and recorded a gain on the sale of oil and gas properties in the amount of $4.3 million related to this transaction. Subsequently, on October 15, 2012, the Company sold its Sargent property in California for approximately $3.2 million, equivalent to its book value. The remaining California assets, the Midway-Sunset and Greeley fields, are in the process of being sold.

Operations Update

During the third quarter 2012, the Company achieved an average production rate of 9,545 Boe/d, comprised of 66% crude oil, 8% NGLs, and 26% natural gas, increasing crude oil as a percentage of production by 3% over the second quarter 2012. Total production for the quarter increased 8% over the prior quarter, and increased 117% over the third quarter 2011. For the nine months ended September 30, 2012, the Company's average daily production was 8,533 Boe/d.

During the third quarter 2012, the Company drilled a total of 39 wells, completed 51 wells and recompleted 27 wells. During the nine months ended September 30, 2012, the Company drilled 131 wells, completed 129 wells and recompleted 74 wells. At September 30, 2012, the Company was drilling 5 wells and had 6 wells waiting on completion. Bonanza Creek also had two horizontal rigs operating in the Wattenberg Field and two rigs active in southern Arkansas.  

Rocky Mountain Region - Wattenberg Horizontal Development

The Rocky Mountain region contributed approximately 5,063 Boe/d, or 53% of total company net sales volumes for the third quarter 2012, comprised of 72% crude oil and 28% liquid-rich natural gas. Approximately 3,000 Boe/d came from horizontal Niobrara wells.

Since Bonanza Creek began its horizontal Niobrara development program in July 2011, the Company has spud 31 wells, completed 25 wells, and has 30-day average production rates on 24 wells and 60-day average production rates on 20 wells. These wells have averaged the following rates:

30-day production rates:        487 Boe/d (75% oil; 25% liquid-rich gas)
60-day production rates:        377 Boe/d (73% oil; 27% liquid-rich gas)

During the third quarter, the Company drilled 9 and completed 8 horizontal wells. These wells were drilled and completed for an average well cost of $4.2 million to an average 4,000 feet lateral length and fracture stimulated with 18 stages, two more than the original design.

Bonanza Creek completed its first horizontal Codell well in October. The well was drilled and completed using the same technology as the Niobrara "B" Bench horizontal wells and early flowback rates are consistent with expectations. Also during the month of October, the Company drilled its first horizontal Niobrara "C" Bench well and spudded its first extended reach horizontal lateral into the Niobrara "B" Bench. The Company plans to drill the extended reach well to approximately 9,100 feet and fracture stimulate it with approximately 40 stages. The total drill and complete cost of this well is estimated to be approximately $8.0 million.

Production in the third quarter from the Wattenberg Field was negatively impacted by approximately 400 Boe/d, 55% crude oil, as a result of temporary gas flaring, high line pressures and delayed completions over quarter-end.

 

Mid-Continent Cotton Valley Program

The Mid-Continent region contributed 4,339 Boe/d, or 45% of total company net sales volumes for the third quarter 2012, comprised of 58% crude oil, 17% natural gas liquids and 25% natural gas.

During the third quarter 2012, Bonanza Creek drilled 9 wells and completed 12 wells in the Cotton Valley formation. For the nine months ended September 30, 2012, Bonanza Creek drilled 34 wells and completed 36 wells. Of the 33 wells completed in 2012 that have over 30 days of production, the average 30-day production rate is 108 Boe/d, exceeding the planned rate. Also during the third quarter, the Company drilled wells in the McKamie-Patton field with early results coming in as expected.

The Company was unable to sell natural gas and natural gas liquids for the equivalent of 29 days during the quarter due to mechanical issues at the Dorcheat gas plant, which were remedied later in the quarter by the replacement of a faulty heat exchanger. Sales volumes were negatively impacted by 338 Boe/d for the quarter, of which 35% was natural gas liquids and the remaining 65% was natural gas.

Financial Update

Credit Agreement and Liquidity

As of September 30, 2012, Bonanza Creek had a $600 million revolving credit facility with a $245 million borrowing base and $122.3 million outstanding. The Company's total liquidity was $79.5 million after reducing the borrowing base by $48 million to account for a letter of credit required to facilitate the Company's acquisition of leasehold acreage in the Wattenberg Field. On October 30, 2012, the Company's borrowing base was increased to $325 million, increasing the Company's liquidity to $159.5 million. See Schedule 6 below for the Company's calculation of "liquidity."

The Company believes it has adequate liquidity from cash generated from operations and unused borrowing capacity under its revolving credit facility to fully fund its 2012 capital plan and meet working capital needs.

Commodity Derivatives Positions

The following table summarizes the Company's crude oil and natural gas commodity derivative positions at September 30, 2012:

Settlement Period Derivative
Instrument
Total
Notional
Amount
(Bbl/Mmbtu)
Average
Floor
Price
Average
Ceiling
Price
Oil       
2012   Collar 233,868 $        90.00 $       106.05
2012   Swap 148,200 88.78 88.78
2013   Collar 530,616 91.61 106.46
2013   Swap 915,417 88.08 88.08
Gas       
2012   Swap 969,308 3.33 3.33
2013   Swap 154,806 6.40 6.40

Conference Call Information

Bonanza Creek will host a conference call on Friday, November 9, 2012 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). To access the live interactive call, please dial (800) 561-2813 or (617) 614-3529 and use the passcode 10720973. This call is being webcast and can be accessed at Bonanza Creek's website www.bonanzacrk.com for one year after the event.

About Bonanza Creek Energy, Inc.

Bonanza Creek Energy, Inc. is an independent oil and natural gas Company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company's assets and operations are concentrated primarily in the Rocky Mountains in the Wattenberg Field, focused on the Niobrara oil shale, and in southern Arkansas, focused on the oily Cotton Valley sands. The Company's common shares are listed for trading on the NYSE under the symbol: "BCEI." For more information about the Company, please visit www.bonanzacrk.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of management regarding the Company's expected capital budget, capital expenditures, drilling program, drilling locations, drilling results, guidance, production, operating costs and expenses, development program, impact of high line pressures, testing and recompletion activities, acquisitions and market perception of the Company. 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. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. 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 Part I, Item 1A-"Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the Securities Exchange Commission on March 22, 2012. The Company's SEC filings are available on the Company's website at www.bonanzacrk.com and on the SEC's website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

For further information, please contact:

Mr. James Masters
Investor Relations Manager
720-440-6121

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

Three Months Ended  Nine Months Ended
September 30, September 30,
2012 2011 2012 2011
NET REVENUES
Oil and gas sales    $    58,328  $    25,915  $  157,613  $    70,609
OPERATING EXPENSES:
Lease operating             8,444           4,686         22,506         12,041
Severance and ad valorem taxes             3,022           1,343           9,387           3,779
Exploration             6,359                 19           9,564              566
Depreciation, depletion and amortization           17,716           6,330         41,751         18,472
Impairment of proved properties              269              623              269              623
General and administrative           9,335           4,179         22,410           9,116
Total operating expenses           45,145         17,180      105,887         44,597
INCOME FROM OPERATIONS           13,183           8,735         51,726         26,012
OTHER INCOME (EXPENSE):
Other loss                 (91)                 (3)               (83)             (101)
Interest expense           (1,125)         (1,122)         (2,342)         (2,687)
Unrealized gain (loss) in fair value of commodity derivatives           (9,007)           8,268           2,985           7,096
Realized gain (loss) in fair value of commodity derivatives                 (93)             (519)         (1,173)         (2,353)
Total other income (loss)         (10,316)           6,624             (613)           1,955
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES    $       2,867  $    15,359  $    51,113  $    27,967
Income tax expense         (1,223)         (8,528)       (19,797)       (13,176)
INCOME FROM CONTINUING OPERATIONS             1,644           6,831         31,316         14,791
DISCONTINUED OPERATIONS
Loss from operations associated with oil and gas properties held for sale         (1,410)         (3,755)             (792)         (3,635)
Gain on sale of oil and gas properties           4,280                    -           4,280                    -
Income tax (expense) benefit         (1,093)           1,757         (1,331)           1,713
Income (loss) associated with oil and gas properties held for sale           1,777         (1,998)           2,157         (1,922)
NET INCOME  $       3,421  $       4,833  $    33,473  $    12,869
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations  $         0.04  $         0.23  $        0.79  $        0.51
Income (loss) from discontinued operations  $         0.05  $      (0.06)  $        0.06  $     (0.07)
Net income per common share  $         0.09  $         0.17  $        0.85  $        0.44
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK-BASIC AND DILUTED         39,477         29,123         39,476         29,123

Schedule 2: Condensed Statement of Cash Flows

(in thousands, unaudited)

Nine Months Ended
September 30,
2012 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income  $  33,473  $  12,868
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization       43,901       21,083
Impairment of proved properties         1,917         4,067
Deferred income taxes       20,557       11,464
Non-cash stock compensation         2,912                  -
Exploration         7,379                  -
Amortization of deferred financing costs            500            702
Valuation (increase) decrease in commodity derivatives       (2,985)       (7,096)
Gain on sale of oil and gas properties       (4,280)                  -
Other               71               92
Changes in operating assets and liabilities     (10,797)       (5,847)
Net cash provided by operating activities       92,648       37,333
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties         5,212                  -
Acquisition of oil and gas properties     (12,809)       (1,383)
Exploration and development of oil and gas properties   (183,357)     (91,907)
Natural gas plant capital expenditures     (12,009)     (18,064)
Proceeds from note receivable                  -            987
Decrease in restricted cash            252                  -
Additions to property and equipment-non oil and gas       (2,203)           (485)
Net cash used in investing activities   (204,914)   (110,852)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit    115,700    145,900
Payment on bank revolving credit                  -     (69,200)
Deferred financing costs           (678)       (3,029)
Net cash provided by financing activities    115,022       73,671
Net increase in cash and cash equivalents         2,756            152
Cash and cash equivalents, beginning of period         2,090                  -
Cash and cash equivalents, end of period  $     4,846  $        152

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

September 30, December 31,
2012 2011
Assets
Current assets  $           52,690  $          32,127
Oil and gas properties and gas plant, net             863,915            618,229
Other assets                  3,895                4,097
Oil and gas properties held for sale, less accumulated depreciation, depletion, and amortization                  5,038                9,896
Total Assets  $         925,538  $       664,349
Liabilities and Stockholders' Equity
Current liabilities               90,067              38,531
Bank revolving credit             122,300                6,600
Deferred taxes             100,161              79,604
Other long-term liabilities               48,645              11,633
Total Liabilities  $         361,173  $       136,368
Stockholders' Equity             564,365            527,981
Total Liabilities and Stockholders' Equity  $         925,538  $       664,349

Schedule 4: Adjusted Net Income

(in thousands, except per share amounts, unaudited)

 

This release contains the non-GAAP financial measures adjusted net income and adjusted net income per diluted share, which exclude (1) unrealized gain or loss on commodity derivatives, (2) non-cash stock compensation expense, (3) impairment of proved properties and (4) exploratory well abandonment. The amounts included in the calculation of adjusted net income and adjusted net income per diluted share, below, were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, not as an alternative for and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following tables provide a reconciliation of adjusted net income for the three and nine months ended September 30, 2012 and 2011, respectively.

Three Months Ended Nine Months Ended
September 30, September 30,
2012 2011 2012 2011
Net Income  $   3,421  $ 4,833  $ 33,473  $ 12,868
Unrealized (gain) loss in fair value of derivatives        9,007    (8,268)      (2,985)      (7,096)
Stock-based compensation        1,446         133        2,912           133
Impairment        1,917     4,067        1,917        4,067
Exploration        5,846              -        7,379                 -
Total adjustments before tax     18,216    (4,068)        9,223      (2,896)
Adjusted for income tax effects     11,203    (2,502)        5,672      (1,781)
Adjusted net income  $ 14,624  $ 2,331  $ 39,145  $ 11,087
Adjusted net income per diluted share  $     0.37  $   0.08  $     0.97  $     0.38

Schedule 5: EBITDAX
(in thousands, except per share amounts, unaudited)

 

We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) stock-based compensation expense, (4) interest expense, (5) unrealized loss (gain) on commodity derivatives, and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a Company's ability to internally fund development and exploration activities. This measure is provided in addition to, not as an alternative for and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The following table provides a reconciliation of EBITDAX to net income for the three and nine months ended September 30, 2012 and 2011, respectively.

Three Months Ended Nine Months Ended
September 30, September 30,
2012 2011 2012 2011
Net Income  $    3,421  $    4,833  $    33,473  $  12,868
Exploration        6,365             19          9,581           573
Depletion, depreciation, and amortization     18,286        7,304        43,901     21,083
Impairment of proved properties        1,917        4,067          1,917        4,067
Stock-based compensation        1,446           133          2,912           133
Gain on sale of oil and gas properties      (4,280)                 -        (4,280)                 -
Interest expense        1,126        1,122          2,342        2,687
Unrealized loss (gain) on commodity derivatives        9,007      (8,268)        (2,985)      (7,096)
Income taxes (benefit)        2,315        6,771        21,129     11,464
EBITDAX  $  39,603  $  15,981  $  107,990  $  45,779
EBITDAX per diluted share  $      1.00  $      0.55  $        2.74  $      1.57

Schedule 6: Liquidity
(in thousands, unaudited)

 

Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company's ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the measurement on a Company's financial statements. This measurement is provided in addition to, not as an alternative for and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. The table below summarizes our liquidity as of September 30, 2012, and pro forma for the borrowing base redetermination effective October 30, 2012.

Pro Forma
September 30, 2012 September 30, 2012
Borrowing Base  $                 245,000  $                325,000
Cash and cash equivalents                               4,846                                4,846
Contractual Obligation for Land Acquisition                           (48,000)                            (48,000)
Long-term debt                         (122,300)                          (122,300)
Liquidity  $                   79,546  $                159,546

  





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