Exhibit 99.1
News Release | 
|
For Immediate Release
March 14, 2013
Bonanza Creek Energy Announces Fourth Quarter and Full Year 2012 Operational and Financial Results
DENVER, March 14, 2012 — Bonanza Creek Energy, Inc. (NYSE: BCEI) today reported its fourth quarter and full year 2012 operating and financial results.
Key highlights for fourth quarter 2012 include:
· 107% increase in production to 11,994 Boe/d; 74% crude oil and liquids
· 100% increase in revenue to $74.0 million; net income of $13.0 million
· 77% increase in adjusted net income per share (non-GAAP) to $0.39
· 138% increase in EBITDAX (non-GAAP) to $54.1 million
Reconciliations of all non-GAAP financial measures stated in this release are made to the most directly comparable GAAP financial measures are included at the end of this release.
Operational highlights include:
· The Company’s first horizontal Niobrara “C” Bench well achieved a 30-day average production rate of 444 Boe/d at 79% crude oil
· The Company’s first extended reach lateral targeting the Niobrara “B” Bench achieved a 30-day average production rate in early 2013 of 795 Boe/d at 76% crude oil
· The Company’s first horizontal Codell well achieved a 30-day average production rate of 370 Boe/d at 81% crude oil, and a 60-day average production rate of 367 Boe/d at 75% crude oil
· During 2012, the Company’s proved reserves increased 21% to 53 MMBoe
Michael Starzer, Bonanza Creek’s President and Chief Executive Officer, commented, “I am pleased with our Company’s performance during 2012 executing on the development plan and identifying significant oil-weighted upside, particularly in the Wattenberg Field. With our expanding development runway and excellent well performance, the foundation for realizing Bonanza Creek’s top tier growth potential has been assembled. The Company expanded Niobrara “B” Bench horizontal drilling across our acreage in Wattenberg, achieving strong results, and initiated testing of significant upside catalysts. The Mid-Continent Region also performed very well in 2012 executing its development plan, including the installation of our third gas processing facility, ahead of schedule and under budget. I am proud of our team and that Bonanza Creek’s culture of continuous improvement has produced solid results for our stockholders.”
Fourth Quarter 2012 Financial Results
Bonanza Creek began the divestiture process of its California properties in the second quarter 2012. Under generally accepted accounting principles, the results of operations for the California properties are presented as “discontinued operations” for 2012 and for the prior-year
in our accompanying condensed financial statements. Consequently, production, revenue and expenses associated with the California properties have been removed from continuing operations and reported separately as discontinued operations in our accompanying condensed financial statements. In this release, the Condensed Statement of Operations in Schedule 1 and the 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. The following 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 otherwise noted, all comparisons discussed in the text of this release include the California operations as continuing operations in the current year and the prior year periods as previously reported.
Average realized prices for fourth quarter 2012, before the effect of commodity derivatives, were $84.26 per Bbl of oil, $4.36 per Mcf of natural gas and $54.60 per Bbl of NGLs, compared to $91.43 per Bbl of oil, $4.37 per Mcf of natural gas and $64.11 per Bbl of NGLs for fourth quarter 2011.
Net revenue for fourth quarter 2012 was $74.0 million, compared to $36.9 million for fourth quarter 2011, a 100% increase. Crude oil and liquids revenue accounted for approximately 89% of total revenue for fourth quarter 2012.
Lease operating expense (“LOE”) for fourth quarter 2012 was $8.6 million, or $7.81 per Boe, compared to $7.0 million, or $13.20 per Boe, for fourth quarter 2011. The decrease in per unit LOE is primarily attributable to increased sales volumes and lower per unit operating costs for horizontal wells.
General and administrative expense (“G&A”) for fourth quarter 2012 was $9.0 million, or $8.15 per Boe, compared to $8.5 million, or $15.96 per Boe, for fourth quarter 2011. The decrease in per unit G&A is attributed primarily to increased sales volumes. G&A for fourth quarter 2012 also includes $1.6 million of non-cash stock compensation expense and approximately $0.4 million of legal fees.
Net income for fourth quarter 2012 was $13.0 million, or $0.32 per diluted share, compared to a net loss of $176 thousand, or $(0.01) per diluted share, for fourth quarter 2011. Adjusted net income (a non-GAAP financial measure) for fourth quarter 2012 was $15.7 million, or $0.39 per diluted share, compared to adjusted net income of $6.7 million, or $0.22 per diluted share, for fourth quarter 2011.
Full Year 2012 Financial Results
All amounts discussed below reflect total operations, including our discontinued California operations.
Key highlights for full year 2012 include:
· 115% increase in production to 9,403 Boe/d; 73% crude oil and liquids
· 267% increase in net income to $46.5 million
· 118% increase in adjusted net income per share (non-GAAP) to $1.31
· 136% increase in EBITDAX (non-GAAP) to $162.1 million
Average realized prices for 2012, before the effect of commodity derivatives, were $89.37 per Bbl of oil, $3.62 per Mcf of natural gas and $55.53 per Bbl of NGLs, compared to $90.57 per Bbl of oil, $4.84 per Mcf of natural gas and $67.23 per Bbl of NGLs for 2011.
Net revenue for 2012 was $236.6 million, compared to $112.5 million for 2011, a 110% increase. Crude oil and liquids revenue accounted for approximately 91% of total revenue for 2012.
LOE for 2012 was $33.0 million, or $9.58 per Boe, compared to $21.5 million, or $13.43 per Boe, for 2011. The decrease in per unit LOE is primarily attributable to increased sales volumes and lower per unit operating costs for horizontal wells.
G&A for 2012 was $31.4 million, or $9.13 per Boe, compared to $17.6 million, or $11.01 per Boe, for 2011. The decrease in per unit G&A is attributed primarily to increased sales volumes. G&A for 2012 also includes $4.5 million of non-cash stock compensation expense and approximately $3.0 million of legal fees.
Net income for 2012 was $46.5 million, or $1.17 per diluted share, compared to $12.7 million, or $0.43 per diluted share, for 2011. Adjusted net income for 2012 was $52.2 million, or $1.31 per diluted share, compared to adjusted net income of $17.8 million, or $0.60 per diluted share, for 2011.
As of December 31, 2012, Bonanza Creek has one remaining California property, located in the Midway-Sunset Field, which is in the process of being sold.
Operations Update
During 2012, the Company achieved an average production rate of 9,403 Boe/d, comprised of 65% crude oil, 8% NGLs, and 27% natural gas, increasing crude oil as a percentage of production by 5% and increasing total production by 115% over 2011. For fourth quarter 2012, the Company’s average daily production was 11,994 Boe/d, a 107% increase over fourth quarter 2011.
Rocky Mountain Region — Wattenberg Horizontal Development
The Rocky Mountain region contributed approximately 4,568 Boe/d, or 49% of total company net sales volumes for 2012, comprised of 75% crude oil and 25% liquid-rich natural gas. Approximately 2,223 Boe/d came from horizontal wells. During fourth quarter 2012, the Rocky Mountain region contributed approximately 6,549 Boe/d, or 55% of total company net sales volumes for the quarter with approximately 3,683 Boe/d coming from horizontal wells.
During 2012, the Company drilled 32 horizontal Niobrara “B” Bench wells for an average total well cost of approximately $4.5 million to an average 4,000 feet lateral length. The average well cost was negatively affected by drilling difficulties associated with four wells. Since Bonanza Creek began its horizontal Niobrara “B” Bench development program in July 2011, the Company has 30-day average production rates on 36 wells and 60-day average production rates on 28 wells. These wells have averaged the following rates:
30-day production rates: | | 503 Boe/d (76% oil; 24% liquid-rich gas) |
60-day production rates: | | 405 Boe/d (75% oil; 25% liquid-rich gas) |
In addition, the Company drilled three horizontal wells testing additional resource potential, including:
1) Niobrara “C” Bench: 30-day average production rate of 444 Boe/d, at 79% crude oil, for a total well cost of $4.4 million
2) Extended reach lateral in the Niobrara “B” Bench: 30-day average production rate of 795 Boe/d, at 76% crude oil, for a total well cost of $7.4 million
3) Codell: 30-day average production rate of 370 Boe/d, at 81% crude oil, and a 60-day average production rate of 367 Boe/d, at 75% crude oil, for a total well cost of $4.5 million
Mid-Continent Cotton Valley Program
The Mid-Continent region contributed 4,689 Boe/d, or 50% of total company net sales volumes for 2012, comprised of 54% crude oil, 17% natural gas liquids and 29% natural gas. Production volumes increased by approximately 90% over 2011. During fourth quarter 2012, the Mid-Continent region contributed approximately 5,402 Boe/d, a 67% increase over fourth quarter 2011.
During 2012, Bonanza Creek drilled 42 Cotton Valley wells in the Mid-Continent region, including 11 wells in the fourth quarter 2012. Also during the year, the Company performed 80 recompletions that added upper Cotton Valley oil sands to production. At the McKamie-Patton Field, the Company successfully tested the Cotton Valley oil sands in four wells with an average 30-day production rate of 137 Bbl/d, at 100% crude oil.
The Company invested $16.2 million constructing a third gas processing facility in the region, expanding its total processing capacity to approximately 40 MMcf/d. This facility, located in the Dorcheat-Macedonia field, began processing natural gas and natural gas liquids in February 2013.
Capital Expenditures
The Company’s capital expenditures in 2012 equaled $340.9 million, versus a budget of $298.0 million. The over-expenditure was due to a number of events, notably:
1) Participation in eight non-operated horizontal Niobrara wells successfully drilled by an offset operator in the Wattenberg Field late in the year for which production will be largely matched against such expenditures in first quarter 2013
2) Augmented 2012 projects such as micro-seismic acquisition, gas gathering system improvements and acreage leasing
3) Additional rig costs in the late stages of transitioning out of the legacy 2012 vertical drilling program
4) Drilling difficulties in four horizontal wells
5) The addition of two incremental frac stages on 24 horizontal wells resulting in increased well productivity
The Company believes that most of these costs were the result of the rapid transition in the Wattenberg Field from a vertical well program to a horizontal well program. Revised costs have been incorporated into the 2013 capital budget.
2012 Proved Reserves
The Company reported its year-end 2012 proved reserves as prepared by its independent third party reserve engineer, Cawley Gillespie & Associates. Proved reserves increased 21% over year-end 2011 to approximately 53.0 MMBoe and the before tax PV-10 (non-GAAP) was approximately $835 million. During 2012, successful execution of the development program resulted in a 47% increase in PDP reserves and a 51% increase in PDP PV-10 (non-GAAP), notwithstanding lower oil and gas prices. Total Company reserve replacement for 2012 was 371%. The Rocky Mountain region added 12.8 MMBoe net proved reserves at a cost of $18.68 per Boe as a result of its horizontal drilling program during 2012. In addition, proved reserves for the Niobrara “B” Bench increased from 6.5 MMBoe to 22 MMBoe, or 41% of total company proved reserves.
The following table summarizes the Company’s 2012 proved reserves and PV-10:
Reserve Category | | % of
Reserves | | Oil
(MBbls) | | Gas
(MMcf) | | NGL
(MBbls) | | 2012
MBOE | | 2011
MBOE | | %
Change | | 2012
PV-10
(millions) | |
Proved Developed Producing | | 31 | % | 10,193.9 | | 33,604.3 | | 784.3 | | 16,578.9 | | 11,244.3 | | 47 | % | $ | 445.5 | |
Proved Developed Non-Producing | | 14 | % | 4,135.9 | | 15,337.4 | | 561.0 | | 7,253.1 | | 5,816.2 | | 25 | % | $ | 151.8 | |
Proved Undeveloped | | 55 | % | 15,829.1 | | 69,606.5 | | 1,762.0 | | 29,192.2 | | 26,652.1 | | 10 | % | $ | 237.4 | |
Total Proved | | 100 | % | 30,158.9 | | 118,548.2 | | 3,107.3 | | 53,024.2 | | 43,712.6 | | 21 | % | $ | 834.7 | |
A reconciliation of PV-10 to Standardized Measure is included in Schedule 7.
Financial Update
Credit Agreement and Liquidity
As of December 31, 2012, Bonanza Creek had a $600 million revolving credit facility with a $325 million borrowing base and $158.0 million outstanding, and cash of $4.3 million. The Company’s total liquidity was $123.3 million after reducing the borrowing base by $48.0 million to account for a letter of credit required to facilitate the Company’s acquisition of leasehold acreage in the Wattenberg Field. Schedule 8 provides a calculation of total liquidity.
Commodity Derivatives Positions
The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of February 28, 2013:
Settlement Period | | Derivative
Instrument | | Total Notional
Amount
(Bo/MMBtu) | | Average
Floor
Price | | Average
Ceiling
Price | |
| | | | | | | | | |
Oil | | | | | | | | | |
2013 | | Collar | | 1,163,116 | | $ | 88.38 | | $ | 102.29 | |
| | Swap | | 1,035,417 | | 88.54 | | | |
2014 | | Collar | | 1,310,000 | | 86.72 | | 95.56 | |
| | Swap | | 228,000 | | 90.80 | | | |
Gas | | | | | | | | | |
2013 | | Swap | | 154,806 | | 6.40 | | | |
| | | | | | | | | | | |
Conference Call Information
Bonanza Creek will host a conference call on Friday, March 15, 2013 at 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time). To access the live interactive call, please dial (866) 700-6293 or (617) 213-8835 and use the passcode 38172270. 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 statements regarding the nonrecurring nature of the additional capital expenditures in 2012 and estimated reserves. 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, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions. 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, 2012, expected to be filed on or about March 15, 2013, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
For further information, please contact:
Mr. Ryan Zorn
Vice President – Finance
720-440-6172
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
December 31, | | Twelve Months Ended
December 31, | |
| | 2012 | | 2011 | | 2012 | | 2011 | |
NET REVENUES | | | | | | | | | |
Oil and gas sales | | $ | 73,592 | | $ | 35,115 | | $ | 231,205 | | $ | 105,724 | |
OPERATING EXPENSES: | | | | | | | | | |
Lease operating | | 8,189 | | 6,212 | | 30,695 | | 18,253 | |
Severance and ad valorem taxes | | 4,287 | | 2,140 | | 13,674 | | 5,919 | |
Exploration | | 1,151 | | 311 | | 10,715 | | 877 | |
Depreciation, depletion and amortization | | 24,451 | | 9,541 | | 66,202 | | 28,014 | |
Impairment of proved properties | | 343 | | — | | 611 | | 623 | |
General and administrative | | 8,995 | | 8,497 | | 31,405 | | 17,613 | |
Total operating expenses | | 47,416 | | 26,701 | | 153,302 | | 71,299 | |
INCOME FROM OPERATIONS | | 26,176 | | 8,414 | | 77,903 | | 34,425 | |
OTHER INCOME (EXPENSE): | | | | | | | | | |
Other (loss) | | (49 | ) | (9 | ) | (133 | ) | (110 | ) |
Interest expense | | (1,791 | ) | (1,330 | ) | (4,133 | ) | (4,017 | ) |
Unrealized gain (loss) in fair value of commodity derivatives | | (1,336 | ) | (6,871 | ) | 1,650 | | 225 | |
Realized gain (loss) in fair value of commodity derivatives | | 448 | | (671 | ) | (725 | ) | (3,024 | ) |
Total other (loss) | | (2,728 | ) | (8,881 | ) | (3,341 | ) | (6,926 | ) |
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES | | $ | 23,448 | | $ | (467 | ) | $ | 74,562 | | $ | 27,499 | |
Income tax benefit (expense) | | (10,194 | ) | 286 | | (29,991 | ) | (12,890 | ) |
INCOME FROM CONTINUING OPERATIONS | | 13,254 | | (181 | ) | 44,571 | | 14,609 | |
DISCONTINUED OPERATIONS | | | | | | | | | |
Income (loss) from operations associated with oil and gas properties held for sale | | (135 | ) | 25 | | (927 | ) | (3,610 | ) |
Gain (loss) on sale of oil and gas properties | | (88 | ) | | | 4,192 | | — | |
Income tax (expense) benefit | | 18 | | (20 | ) | (1,313 | ) | 1,692 | |
Income (loss) associated with oil and gas properties held for sale | | (205 | ) | 5 | | 1,952 | | (1,918 | ) |
NET INCOME (LOSS) | | $ | 13,049 | | (176 | ) | $ | 46,523 | | $ | 12,691 | |
BASIC AND DILUTED INCOME (LOSS) PER SHARE | | | | | | | | | |
Income (loss) from continuing operations | | $ | 0.32 | | $ | (0.01 | ) | $ | 1.12 | | $ | 0.49 | |
Income (loss) from discontinued operations | | $ | — | | $ | 0.00 | | $ | 0.05 | | $ | (0.06 | ) |
Net income (loss) per common share | | $ | 0.32 | | $ | (0.01 | ) | $ | 1.17 | | $ | 0.43 | |
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED | | 40,065 | | 30,923 | | 39,788 | | 29,576 | |
Schedule 2: Condensed Statement of Cash Flows
(in thousands, unaudited)
| | Twelve Months Ended | |
| | December 31, | |
| | 2012 | | 2011 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | |
Net income (loss) | | $ | 46,523 | | $ | 12,691 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
Depreciation, depletion and amortization | | 68,445 | | 31,508 | |
Impairment of proved properties | | 2,259 | | 4,067 | |
Deferred income taxes | | 30,773 | | 11,198 | |
Non-cash stock compensation | | 4,483 | | 4,437 | |
Exploration | | 8,379 | | — | |
Amortization of deferred financing costs | | 700 | | 1,004 | |
Valuation (increase) decrease in commodity derivatives | | (1,650 | ) | (225 | ) |
Gain on sale of oil and gas properties | | (4,192 | ) | — | |
Accretion of contractual obligation for land acquisition | | 317 | | — | |
Other charges | | 168 | | (40 | ) |
(Increase) decrease in operating assets: | | | | | |
Accounts receivable | | (20,738 | ) | (11,712 | ) |
Prepaid expenses and other assets | | (1,164 | ) | (1,165 | ) |
(Decrease) increase in operating liabilities: | | | | | |
Accounts payable and accrued liabilities | | 22,769 | | 5,996 | |
Settlement of asset retirement obligations | | (162 | ) | (156 | ) |
Net cash provided by operating activities | | 156,910 | | 57,603 | |
| | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | |
Proceeds from sale of oil and gas properties | | 9,337 | | — | |
Acquisition of oil and gas properties | | (13,920 | ) | (1,809 | ) |
Exploration and development of oil and gas properties | | (281,326 | ) | (134,184 | ) |
Natural gas plant capital expenditures | | (15,788 | ) | (22,687 | ) |
Proceeds from note receivable | | — | | 987 | |
Decrease in restricted cash | | 253 | | — | |
Additions to property and equipment-non oil and gas | | (3,107 | ) | (1,209 | ) |
Net cash used in investing activities | | (304,551 | ) | (158,902 | ) |
| | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | |
Increase in bank revolving credit | | 151,400 | | 108,100 | |
Payment on bank revolving credit | | — | | (156,900 | ) |
Proceeds from sale of common stock | | — | | 155,878 | |
Deferred financing costs | | (1,111 | ) | (2,284 | ) |
Offering costs related to sale of common stock | | (3 | ) | — | |
Common stock returned for tax withholdings | | (467 | ) | (1,405 | ) |
Net cash provided by financing activities | | 149,819 | | 103,389 | |
Net increase (decrease) in cash and cash equivalents | | 2,178 | | 2,090 | |
| | | | | |
Cash and cash equivalents, beginning of period | | $ | 2,090 | | — | |
Cash and cash equivalents, end of period | | $ | 4,268 | | $ | 2,090 | |
Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)
| | December 31, | | December 31, | |
| | 2012 | | 2011 | |
Assets | | | | | |
Current assets | | $ | 55,304 | | $ | 32,127 | |
Oil and gas properties and gas plant, net | | 938,975 | | 618,229 | |
Other assets | | 7,629 | | 4,097 | |
Oil and gas properties held for sale, less accumulated depreciation, depletion, and amortization | | 582 | | 9,896 | |
Total Assets | | $ | 1,002,490 | | $ | 664,349 | |
| | | | | |
Liabilities and Stockholders’ Equity | | | | | |
Current liabilities | | 102,603 | | 38,531 | |
Bank revolving credit | | 158,000 | | 6,600 | |
Deferred taxes | | 110,377 | | 79,604 | |
Other long-term liabilities | | 52,992 | | 11,633 | |
Total Liabilities | | $ | 423,972 | | $ | 136,368 | |
Stockholders’ Equity | | 578,518 | | 527,981 | |
Total Liabilities and Stockholders’ Equity | | $ | 1,002,490 | | $ | 664,349 | |
Schedule 4: Volumes and Realized Prices
(unaudited)
| | Three Months Ended | | Twelve Months Ended | |
| | December 31, | | December 31, | |
| | 2012 | | 2011 | | 2012 | | 2011 | |
Wellhead Volumes and Prices | | | | | | | | | |
Crude Oil and Condensate Sales Volumes (Bbl/d) | | | | | | | | | |
Rocky Mountains | | 4,952 | | 1,734 | | 3,433 | | 1,227 | |
Mid-Continent | | 2,965 | | 1,556 | | 2,553 | | 1,204 | |
California | | 43 | | 172 | | 146 | | 180 | |
Total | | 7,960 | | 3,462 | | 6,132 | | 2,611 | |
| | | | | | | | | |
Crude Oil and Condensate Realized Prices ($/Bbl) | | | | | | | | | |
Rocky Mountains | | $ | 80.07 | | $ | 86.30 | | $ | 84.60 | | $ | 86.11 | |
Mid-Continent | | 90.99 | | 94.64 | | 95.12 | | 93.29 | |
California | | 102.05 | | 114.06 | | 101.19 | | 102.72 | |
Composite | | $ | 84.26 | | $ | 91.43 | | $ | 89.37 | | $ | 90.57 | |
| | | | | | | | | |
Natural Gas Liquids Sales Volumes (Bbl/d) | | | | | | | | | |
Mid-Continent | | 895 | | 598 | | 778 | | 504 | |
Total | | 895 | | 598 | | 778 | | 504 | |
| | | | | | | | | |
Natural Gas Liquids Realized Prices ($/Bbl) | | | | | | | | | |
Mid-Continent | | $ | 54.60 | | $ | 64.11 | | $ | 55.54 | | $ | 67.23 | |
Composite | | $ | 54.60 | | $ | 64.11 | | $ | 55.54 | | $ | 67.23 | |
| | | | | | | | | |
Natural Gas Sales Volumes (Mcf/d) | | | | | | | | | |
Rocky Mountains | | 9,583 | | 3,814 | | 6,808 | | 2,970 | |
Mid-Continent | | 9,249 | | 6,530 | | 8,146 | | 4,628 | |
California | | — | | 21 | | 4 | | 9 | |
Total | | 18,832 | | 10,365 | | 14,958 | | 7,607 | |
| | | | | | | | | |
Natural Gas Realized Prices ($/Mcf) | | | | | | | | | |
Rocky Mountains | | $ | 5.17 | | $ | 5.81 | | $ | 4.46 | | $ | 5.96 | |
Mid-Continent | | 3.53 | | 3.53 | | 2.91 | | 4.14 | |
California | | — | | 1.59 | | 1.11 | | 2.06 | |
Composite | | $ | 4.36 | | $ | 4.37 | | $ | 3.62 | | $ | 4.84 | |
| | | | | | | | | |
Crude Oil Equivalent Sales Volumes (Boe/d) | | | | | | | | | |
Rocky Mountains | | 6,549 | | 2,370 | | 4,567 | | 1,722 | |
Mid-Continent | | 5,402 | | 3,242 | | 4,689 | | 2,479 | |
California | | 43 | | 176 | | 147 | | 181 | |
Total | | 11,994 | | 5,788 | | 9,403 | | 4,382 | |
Total Sales Volumes (MMBoe) | | 1.1 | | 0.5 | | 3.4 | | 1.6 | |
Schedule 5: 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 in fair value of commodity derivatives, (2) stock-based compensation expense, (3) impairment of proved properties, (4) exploratory dry hole cost and (5) gain or loss on sale of oil and gas properties. 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 the timing or amount of which 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 in our SEC filings and posted on our website. The following tables provide a reconciliation of adjusted net income for the three and twelve months ended December 31, 2012 and 2011, respectively.
| | Three Months Ended | | Twelve Months Ended | |
| | December 31, | | December 31, | |
| | 2012 | | 2011 | | 2012 | | 2011 | |
Net Income | | $ | 13,049 | | $ | (176 | ) | $ | 46,523 | | $ | 12,691 | |
Unrealized (gain) loss in fair value of derivatives | | 1,336 | | 6,871 | | (1,650 | ) | (225 | ) |
Stock-based compensation | | 1,570 | | 4,244 | | 4,483 | | 4,437 | |
Impairment | | 343 | | — | | 2,259 | | 4,067 | |
Exploratory dry hole cost | | 1,000 | | — | | 8,379 | | — | |
Gain (loss) on sale of oil and gas properties | | 88 | | — | | (4,192 | ) | — | |
Total adjustments before tax | | 4,337 | | 11,115 | | 9,279 | | 8,279 | |
Adjusted for income tax effects | | 2,667 | | 6,835 | | 5,707 | | 5,091 | |
Adjusted net income | | $ | 15,716 | | $ | 6,659 | | $ | 52,230 | | $ | 17,783 | |
Adjusted net income per diluted share | | $ | 0.39 | | $ | 0.22 | | $ | 1.31 | | $ | 0.60 | |
Schedule 6: 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) impairment of proved properties, (4) stock-based compensation expense, (5) gain or loss on sale of oil and gas properties, (6) interest expense, (7) unrealized gain or loss in fair value of commodity derivatives, and (8) income taxes or benefit. 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) in our SEC filings and posted on our website. The following table provides a reconciliation of EBITDAX to net income for the three and twelve months ended December 31, 2012 and 2011, respectively.
| | Three Months Ended | | Twelve Months Ended | |
| | December 31, | | December 31, | |
| | 2012 | | 2011 | | 2012 | | 2011 | |
Net Income | | $ | 13,049 | | $ | (176 | ) | $ | 46,523 | | $ | 12,691 | |
Exploration | | 1,174 | | 311 | | 10,754 | | 884 | |
Depletion, depreciation, and amortization | | 24,544 | | 10,425 | | 68,445 | | 31,508 | |
Impairment of proved properties | | 343 | | — | | 2,259 | | 4,067 | |
Stock-based compensation | | 1,570 | | 4,244 | | 4,483 | | 4,437 | |
Gain (loss) on sale of oil and gas properties | | 88 | | — | | (4,192 | ) | — | |
Interest expense | | 1,791 | | 1,331 | | 4,133 | | 4,017 | |
Unrealized loss (gain) in fair value of commodity derivatives | | 1,336 | | 6,870 | | (1,650 | ) | (225 | ) |
Income taxes (benefit) | | 10,176 | | (265 | ) | 31,305 | | 11,198 | |
EBITDAX | | $ | 54,071 | | $ | 22,740 | | $ | 162,060 | | $ | 68,577 | |
EBITDAX per diluted share | | $ | 1.35 | | $ | 0.74 | | $ | 4.07 | | $ | 2.32 | |
Schedule 7: Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure of discounted future net cash flows, 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 oil and natural gas reserves.
The following table provides a reconciliation of PV-10 to the Standardized Measure at December 31, 2012, 2011 and 2010:
| | December 31, | |
| | 2012 | | 2011 | | 2010 | |
| | (In millions) | |
PV-10 | | $ | 834.7 | | $ | 794.0 | | $ | 461.6 | |
Present value of future income taxes discounted at 10% | | (151.3 | ) | (127.8 | ) | (86.9 | ) |
Standardized Measure | | $ | 683.4 | | $ | 666.2 | | $ | 374.7 | |
Schedule 8: 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) in our SEC filings and posted on our website. The table below summarizes our liquidity as of December 31, 2012.
| | December 31, 2012 | |
Borrowing base | | $ | 325,000 | |
Cash and cash equivalents | | 4,268 | |
Letter of credit securing contractual obligation for land acquisition | | (48,000 | ) |
Long-term debt | | (158,000 | ) |
Liquidity | | $ | 123,268 | |
