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| 8-K - 8-K - Bonanza Creek Energy, Inc. | a8-k3x31x16.htm |
Bonanza Creek Energy Announces First Quarter 2016 Financial and Operating Results
• | First quarter production volumes averaged 24.3 MBoe per day, compared to guidance of 23.9 MBoe per day at the midpoint |
• | Adjusted EBITDAX(1) of $18.5 million; adjusted net loss(1) of $0.46 per diluted share |
• | First quarter CAPEX of $20.7 million, a 33% sequential decrease from the fourth quarter of 2015 |
(1) | Non-GAAP measure, see attached Reconciliation Schedules. |
DENVER, May 5, 2016 – Bonanza Creek Energy, Inc. (NYSE: BCEI) (the "Company") today announces its first quarter 2016 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 May 6, 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, "I am proud to announce our first quarter operational results which have exceeded expectations for the third consecutive quarter. While the commodity price environment continues to be challenging for the Company financially, our underlying Wattenberg assets continue to outperform. For the balance of 2016, the Company will continue its efforts to maximize its liquidity position through potential asset sales and putting intense focus into maximizing the productivity of base production and optimizing cost structure."
First Quarter 2016 Results
For the first quarter of 2016, the Company reported average daily production of 24.3 MBoe per day, a 12% decrease from the first quarter of 2015, and a 15% sequential decrease from the fourth quarter of 2015. The reduction in production volumes is a result of decreased activity and timing of completions within the quarter. Product mix for the first quarter of 2016 was 58% oil, 17% NGLs, and 25% natural gas.
Net revenue for the first quarter of 2016 was $44.2 million, compared to $73.1 million for the first quarter of 2015. Crude oil accounted for approximately 78% of total revenue. Differentials for the Company's Rocky Mountain oil production during the quarter averaged approximately $8.36 per Bbl. Average realized prices for the first quarter of 2016 are presented below.
Average Realized Prices | |||||
Three Months Ended March 31, 2016 | |||||
Before Derivatives | After Derivatives | ||||
Oil (per Bbl) | 27.02 | 32.87 | |||
Gas (per Mcf) | 1.39 | 1.39 | |||
NGL (per Bbl) | 12.98 | 12.98 | |||
Boe (Per Boe) | 19.96 | 23.35 | |||
LOE for the first quarter of 2016 was $13.3 million, or $6.01 per Boe, compared to $17.0 million or $6.86 per Boe in the first quarter of 2015. Throughout 2015 and into 2016, the Company has executed on multiple cost saving initiatives which have resulted in absolute and per unit LOE reductions of 22% and 12%, respectively from the first quarter of 2015 to the first quarter of 2016.
Starting in 2016, the Company changed the presentation of its consolidated statement of operations to provide more granular disclosure of its LOE by separating out the operating costs of its non-E&P assets. The Company's gas plant and midstream operating expenses includes the operating costs of both gas plants located in the Company's Mid-Continent region and the Company's Rocky Mountain Infrastructure assets located on its Wattenberg acreage. Below is a breakout of the Company's regional LOE and gas plant and midstream operating expense for the first quarter of 2016.
Lease Operating Expense | |||||||||||||||||||||||
Three Months Ended March 31, 2016 | |||||||||||||||||||||||
Rocky Mountain | Mid-Continent | Total Company | |||||||||||||||||||||
($M) | ($/Boe) | ($M) | ($/Boe) | ($M) | ($/Boe) | ||||||||||||||||||
LOE | $ | 10,466 | $ | 5.79 | $ | 2,832 | $ | 6.98 | $ | 13,298 | $ | 6.01 | |||||||||||
Gas plant and Midstream Operating Expense | 1,846 | 1.02 | 1,943 | 4.79 | 3,789 | 1.71 | |||||||||||||||||
Total | $ | 12,312 | $ | 6.81 | $ | 4,775 | $ | 11.77 | $ | 17,087 | $ | 7.72 | |||||||||||
Cash general and administrative ("G&A") expense for the first quarter of 2016 was $14.7 million, or $6.63 per Boe. At the end of the first quarter, the Company underwent a workforce reorganization to better align its employee base and organization with further tempered activity levels. As a result of this reorganization, the Company expects its cash G&A expense to be reduced by approximately $7.6 million annually. Also as a result of the reorganization, the Company incurred a one-time cash charge of approximately $2.2 million related to severance payments. Since September of 2015, the Company has materially reduced and restructured its organization to leverage operating efficiencies and match its workforce to activity levels, resulting in aggregated estimated annual reductions in cash G&A of approximately $13.0 million. When adjusting for one-time severance payments, cash G&A expense was $12.5 million or $5.66 per Boe, for the first quarter of 2016 compared to cash G&A expense of $13.4 million or $5.43 per Boe in the first quarter of 2015.
Depreciation, depletion and amortization ("DD&A") for first quarter of 2016 was $26.4 million, or $11.92 per Boe, a 55% decrease from $59.0 million in the first quarter 2015. The material decrease to DD&A expense in the first quarter is primarily due to the proved property impairments realized in the fourth quarter of 2015 and the cessation of depletion for assets classified as held for sale in the first quarter.
Total CAPEX for the first quarter of 2016 was $20.7 million, of which $4.8 million was attributable to RMI. In an effort to preserve liquidity in a period of depressed commodity prices, the Company has lowered its completed well costs and drilling and completion activity over the past year, reducing total costs incurred by over 80% from the first quarter of 2015.
Reported GAAP net loss for the first quarter of 2016 was $47.2 million, or $0.96 per diluted share, compared to a net loss of $18.4 million, or $0.41 per diluted share, for the first quarter of 2015. Adjusted net loss for the first quarter of 2016 was $22.4 million, or $0.46 per diluted share, compared to an adjusted net loss of $2.7 million, or $0.06 per diluted share for the first quarter of 2015, and an adjusted net loss of $8.4 million, or $0.17 per diluted share for the fourth quarter of 2015.
Adjusted EBITDAX for the first quarter of 2016 was $18.5 million, a 73% decrease compared to $69.3 million for the first quarter of 2015 and a 72% sequential decrease from the fourth quarter of 2015.
Adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures.
The table below summarizes the Company's quarterly results as compared to provided guidance.
Guidance vs Actual Summary | |||||
Three Months Ended March 31, 2016 | |||||
Guidance | Actual | ||||
Production (MBoe/d) | 23.7 – 24.0 | 24.3 | |||
LOE ($/Boe) | $8.55 – $8.65 | $ | 6.01 | ||
Midstream ($/Boe) | $2.25 – $2.35 | $ | 1.71 | ||
Cash G&A ($/Boe)* | $5.80 – $5.90 | $ | 5.66 | ||
Production taxes (% of pre-derivative realization) | 6% – 7% | 7.1 | % | ||
E&P CAPEX ($MM) | $35 – $40 | $ | 21 | ||
* Cash G&A as presented, excludes one time severance charges related to workforce reorganization during the first quarter of 2016. Cash G&A for the quarter, including these costs were $6.63 per Boe. | |||||
Operations Update
Rocky Mountain Region – Wattenberg Horizontal Development
During the quarter, the Company connected 17 gross (11.4 net) horizontal wells into sales, consisting of 8.8 net standard reach laterals ("SRLs"), and 2.6 net medium reach laterals ("MRLs"). Of the 17 gross wells connected in the first quarter, 12 were operated by the Company. For the first quarter, upstream capital CAPEX for the region was approximately $16 million.
Production from the Rocky Mountain region during the first quarter of 2016, averaged 19.9 MBoe/d, or 82% of total Company volumes. The production was comprised of 59% crude oil, 17% NGLs and 24% natural gas. Rocky Mountain sales volumes decreased by 9% compared to the first quarter of 2015 and decreased sequentially by 16% compared to the fourth quarter of 2015 due to decreased activity levels.
During the first quarter, the Company drilled and completed its first pad of wells that incorporated plug-and-perf completions, increased sand loading of 1,500 pounds per lateral foot, and monobore construction. Completed well costs for these wells were approximately $2.5 million per SRL, meeting the Company's well cost expectations. The Company is monitoring the results of these enhanced wells designs and plans to discuss their performance in the second half of 2016.
At the end of the first quarter, the Company released its remaining operated rig and has halted drilling and completion activity in its Rocky Mountain region. As of March 31, 2016 the Company had 6 drilled uncompleted wells, 4 SRLs and 2 extended reach laterals ("XRLs"). The Company plans to revisit its activity levels on a quarterly basis or as pending asset sales are completed or material changes to commodity price fundamentals occur.
Mid-Continent Region – Cotton Valley Development
During the first quarter of 2016, the Company executed 12 gross (11.3 net) Cotton Valley re-completions.
The Mid-Continent region contributed 4.5 MBoe/d, or 18% of total Company net sales volumes for the first quarter of 2016, and was comprised of 55% crude oil, 16% NGLs and 29% natural gas. Sales volumes decreased by 20% compared to the first quarter of 2015 and decreased approximately 10% from the fourth quarter of 2015 as a result of decreased activity levels.
Financial and Risk Management Update
Debt and Liquidity
The Company has a $1.0 billion revolving credit facility, which was redetermined in October of 2015 with an approved borrowing base and commitment amount of $475 million. As of March 31, 2016, the Company had borrowings under its credit facility of $288.0 million, a letter of credit totaling $12.0 million, and cash totaling $218.6 million. Bonanza Creek has two outstanding issues of unsecured high-yield bonds which consist of $500 million of 6.75% senior notes due in 2021 and $300 million of 5.75% senior notes due in 2023. As of March 31, 2016, the Company was in compliance with all financial covenants, with a senior secured debt to TTM EBITDAX ratio of 1.3x, an interest coverage ratio of 3.9x, and a current ratio of 2.3x.
Please review the Company's quarterly report on Form 10-Q filed with the Securities Exchange Commission on May 5, 2016 for further information regarding the Company's debt and liquidity.
Commodity Derivatives Positions
During the first quarter, the Company restructured its hedge position for 2016. The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of March 31, 2016 and settling quarterly:
Settlement Period | Volume (Bbls/d) | Contract Type | Swap Price | |||
2Q 2016 | 3,103 | Fixed Price Swap | $49.87 | |||
3Q 2016 | 2,704 | Fixed Price Swap | $51.78 | |||
4Q 2016 | 2,303 | Fixed Price Swap | $52.83 | |||
Settlement Period | Volume (Bbls/d) | Contract Type | Floor Price | |||
2Q 2016 | 5,430 | Floor (Long Put) | $51.01 | |||
3Q 2016 | 4,733 | Floor (Long Put) | $51.01 | |||
4Q 2016 | 4,031 | Floor (Long Put) | $51.01 | |||
Second Quarter Guidance and Update
During the quarter the Company engaged an adviser to market its Rocky Mountain Infrastructure assets. The marketing processes for these assets along with its Mid-Continent assets are currently ongoing. Results from these marketing processes will be announced at the earlier of the execution of a definitive purchase agreement or the Company's second quarter earnings conference call.
The table below provides updated guidance for the second quarter and full year of 2016.
Guidance Summary | |||
Three Months Ended June 30, 2016 | Twelve Months Ended December 31, 2016 | ||
Production (MBoe/d) | 22.7 – 23.3 | 19.7 – 21.7 | |
LOE ($MM) | $52 – $56 | ||
Midstream expense ($MM) | $15 – $17 | ||
Cash G&A ($/Boe)* | $40 – $44 | ||
Production taxes (% of pre-derivative realization) | 6% – 7% | ||
CAPEX (in millions) | |||
E&P CAPEX | |||
Total CAPEX | $35 – $45 | ||
* Cash G&A guidance is exclusive of one-time severance payment of $2.2 million in 1Q16. | |||
Conference Call Information
Bonanza Creek will host a conference call to discuss these financial and operating results on May 6, 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.
Type | Phone Number | Passcode |
Domestic Participant | 877-783-4362 | 97177175 |
International Participant | 615-247-0186 | 97177175 |
Replay | 855-859-2056 | 97177175 |
About Bonanza Creek Energy, Inc.
Bonanza Creek Energy, Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company’s assets and operations are concentrated primarily in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations, and in southern Arkansas, focused on oily Cotton Valley sands. The Company’s common shares are listed for trading on the NYSE under the symbol: “BCEI.” For more information about the Company, please visit www.bonanzacrk.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.
Forward-Looking Statements
This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include statements regarding IRRs; future reserves; impacts of the Company’s development plan and spacing and pattern wells; development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company's reorganization; the closing and impact of the RMI transaction; optimization of midstream capabilities; updated 2016 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: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2015, filed on February 29, 2016, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
For further information, please contact:
James R. Edwards
Director - Investor Relations
720-440-6136
jedwards@bonanzacrk.com
Schedule 1: Statement of Operations
(in thousands, expect for per share amounts, unaudited)
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Operating net revenues: | |||||||
Oil and gas sales | $ | 44,174 | $ | 73,076 | |||
Operating expenses: | |||||||
Lease operating expense | 13,298 | 16,973 | |||||
Gas plant and midstream operating expense | 3,789 | 2,291 | |||||
Severance and ad valorem taxes | 3,154 | 6,496 | |||||
Exploration | 266 | 498 | |||||
Depreciation, depletion and amortization | 26,379 | 59,004 | |||||
Impairment of oil and gas properties | 10,000 | — | |||||
Abandonment and impairment of unproved properties | 6,906 | 5,469 | |||||
General and administrative (including $3,004 and $3,427, respectively, of stock-based compensation) | 17,685 | 16,872 | |||||
Total operating expenses | 81,477 | 107,603 | |||||
Loss from operations | (37,303 | ) | (34,527 | ) | |||
Other income (expense): | |||||||
Derivative gain (loss) | (1,007 | ) | 18,856 | ||||
Interest expense | (14,547 | ) | (14,238 | ) | |||
Gain on termination fee | 6,000 | — | |||||
Other loss | (380 | ) | (49 | ) | |||
Total other income (expense) | (9,934 | ) | 4,569 | ||||
Loss from operations before taxes | (47,237 | ) | (29,958 | ) | |||
Income tax benefit | — | 11,537 | |||||
Net loss | $ | (47,237 | ) | $ | (18,421 | ) | |
Basic net loss per common share | $ | (0.96 | ) | $ | (0.41 | ) | |
Diluted net loss per common share | $ | (0.96 | ) | $ | (0.41 | ) | |
Basic weighted-average common shares outstanding | 49,131 | 44,520 | |||||
Diluted weighted-average common shares outstanding | 49,131 | 44,520 | |||||
• | The Company follows the two-class method when computing the basic and diluted loss per share, which allocates earnings between common shareholders and participating securities. Please refer to Note 10 – Earnings per Share in the Form 10-Q, for a detailed calculation. |
Schedule 2: Statement of Cash Flows
(in thousands, unaudited)
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Cash flows from operating activities: | |||||||
Net loss | $ | (47,237 | ) | $ | (18,421 | ) | |
Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 26,379 | 59,004 | |||||
Deferred income benefit | — | (11,537 | ) | ||||
Impairment of oil and gas properties | 10,000 | — | |||||
Abandonment and impairment of unproved properties | 6,906 | 5,469 | |||||
Dry hole expense | 232 | — | |||||
Stock-based compensation | 3,004 | 3,427 | |||||
Amortization of deferred financing costs and debt premium | 608 | 523 | |||||
Accretion of contractual obligation for land acquisition | — | 349 | |||||
Derivative (gain) loss | 1,007 | (18,856 | ) | ||||
Derivative cash settlements | 7,508 | 35,466 | |||||
Other | (116 | ) | (27 | ) | |||
Changes in current assets and liabilities: | |||||||
Accounts receivable | 23,044 | 16,298 | |||||
Prepaid expenses and other assets | (1,622 | ) | (1,873 | ) | |||
Accounts payable and accrued liabilities | (3,141 | ) | (1,981 | ) | |||
Settlement of asset retirement obligations | (41 | ) | (285 | ) | |||
Net cash provided by operating activities | 26,531 | 67,556 | |||||
Cash flows from investing activities: | |||||||
Acquisition of oil and gas properties | (532 | ) | (11,382 | ) | |||
Exploration and development of oil and gas properties | (34,822 | ) | (154,300 | ) | |||
Natural gas plant capital expenditures | (50 | ) | (112 | ) | |||
Increase in restricted cash | (2,533 | ) | — | ||||
Additions to property and equipment - non oil and gas | 47 | (1,490 | ) | ||||
Net cash used in investing activities | (37,890 | ) | (167,284 | ) | |||
Cash flows from financing activities: | |||||||
Proceeds from credit facility | 209,000 | 44,000 | |||||
Payments to credit facility | — | (77,000 | ) | ||||
Proceeds from sale of common stock | — | 209,300 | |||||
Offering costs related to sale of common stock | — | (6,492 | ) | ||||
Offering costs related to sale of Senior Notes | — | (19 | ) | ||||
Payment of employee tax withholdings in exchange for the return of common stock | (229 | ) | (2,127 | ) | |||
Deferred financing costs | (154 | ) | (4 | ) | |||
Net cash provided by financing activities | 208,617 | 167,658 | |||||
Net change in cash and cash equivalents | 197,258 | 67,930 | |||||
Cash and cash equivalents: | |||||||
Beginning of period | 21,341 | 2,584 | |||||
End of period | $ | 218,599 | $ | 70,514 | |||
Schedule 3: Condensed Balance Sheet
(in thousands, unaudited)
March 31, | December 31, | ||||||
2016 | 2015 | ||||||
ASSETS | |||||||
Current assets | $ | 287,651 | $ | 120,074 | |||
Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion and amortization of $646,917 and $636,917 in 2016 and 2015, respectively | 209,421 | 214,922 | |||||
Total property and equipment, net | 905,976 | 922,344 | |||||
Other noncurrent assets | 17,799 | 16,027 | |||||
Total Assets | $ | 1,420,847 | $ | 1,273,367 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current liabilities | $ | 114,897 | $ | 135,973 | |||
Long-term debt | 1,094,085 | 885,392 | |||||
Other long-term liabilities | 46,920 | 42,595 | |||||
Total Liabilities | 1,255,902 | 1,063,960 | |||||
Stockholders’ Equity | 164,945 | 209,407 | |||||
Total Liabilities and Stockholders’ Equity | $ | 1,420,847 | $ | 1,273,367 | |||
Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)
Three Months Ended March 31, | |||||||
2016 | 2015 | ||||||
Wellhead Volumes and Prices | |||||||
Crude Oil and Condensate Sales Volumes (Bbl/d) | |||||||
Rocky Mountains | 11,665 | 13,674 | |||||
Mid-Continent | 2,437 | 2,887 | |||||
Total | 14,102 | 16,561 | |||||
Crude Oil and Condensate Realized Prices ($/Bbl) | |||||||
Rocky Mountains | $ | 25.15 | $ | 38.28 | |||
Mid-Continent | $ | 35.95 | $ | 47.40 | |||
Composite (before derivatives) | $ | 27.02 | $ | 39.87 | |||
Composite (after derivatives) | $ | 32.87 | $ | 63.21 | |||
Natural Gas Liquids Sales Volumes (Bbl/d) | |||||||
Rocky Mountains | 3,416 | 3,460 | |||||
Mid-Continent | 720 | 993 | |||||
Total | 4,136 | 4,453 | |||||
Natural Gas Liquids Realized Prices ($/Bbl) | |||||||
Rocky Mountains | $ | 13.12 | $ | 13.67 | |||
Mid-Continent | $ | 12.33 | $ | 15.77 | |||
Composite (before derivatives) | $ | 12.98 | $ | 14.14 | |||
Composite (after derivatives) | $ | 12.98 | $ | 14.14 | |||
Natural Gas Sales Volumes (Mcf/d) | |||||||
Rocky Mountains | 28,638 | 28,815 | |||||
Mid-Continent | 7,853 | 10,155 | |||||
Total | 36,491 | 38,970 | |||||
Natural Gas Realized Prices ($/Mcf) | |||||||
Rocky Mountains | $ | 1.20 | $ | 1.95 | |||
Mid-Continent | $ | 2.09 | $ | 3.21 | |||
Composite (before derivatives) | $ | 1.39 | $ | 2.28 | |||
Composite (after derivatives) | $ | 1.39 | $ | 2.47 | |||
Crude Oil Equivalent Sales Volumes (Boe/d) | |||||||
Rocky Mountains | 19,854 | 21,936 | |||||
Mid-Continent | 4,466 | 5,573 | |||||
Total | 24,320 | 27,509 | |||||
Crude Oil Equivalent Sales Prices ($/Boe) | |||||||
Rocky Mountains | $ | 18.77 | $ | 28.58 | |||
Mid-Continent | $ | 25.27 | $ | 33.22 | |||
Composite (before derivatives) | $ | 19.96 | $ | 29.52 | |||
Composite (after derivatives) | $ | 23.35 | $ | 43.84 | |||
Total Sales Volumes (MBoe) | 2,213 | 2,476 | |||||
Schedule 5: Per unit operating margins
(unaudited)
Three Months Ended March 31, | ||||||||||
2016 | 2015 | Percent Change | ||||||||
Production | ||||||||||
Oil (MBbl) | 1,283.3 | 1,490.5 | (14 | )% | ||||||
Gas (MMcf) | 3,320.6 | 3,506.9 | (5 | )% | ||||||
NGL (MBbl) | 376.4 | 400.8 | (6 | )% | ||||||
Equivalent (MBoe) | 2,213.1 | 2,475.8 | (11 | )% | ||||||
Realized pricing (before derivatives) | ||||||||||
Oil ($/Bbl) | $ | 27.02 | $ | 39.87 | (32 | )% | ||||
Gas ($/Mcf) | $ | 1.39 | $ | 2.28 | (39 | )% | ||||
NGL ($/Bbl) | $ | 12.98 | $ | 14.14 | (8 | )% | ||||
Equivalent ($/Boe) | $ | 19.96 | $ | 29.52 | (32 | )% | ||||
Per Unit Costs ($/Boe) | ||||||||||
Realized price (before derivatives) | $ | 19.96 | $ | 29.52 | (32 | )% | ||||
LOE | 6.01 | 6.86 | (12 | )% | ||||||
Gas plant and midstream operating expense | 1.71 | 0.93 | 84 | % | ||||||
Severance and Ad Valorem | 1.43 | 2.62 | (45 | )% | ||||||
Cash General and Administrative | 6.63 | 5.43 | 22 | % | ||||||
Total cash operating costs | $ | 15.78 | $ | 15.84 | — | % | ||||
Cash operating margin (before derivatives) | $ | 4.18 | $ | 13.68 | (69 | )% | ||||
Derivative Cash Settlements | 3.39 | 14.33 | (76 | )% | ||||||
Cash operating margin (after derivatives) | $ | 7.57 | $ | 28.01 | (73 | )% | ||||
Non-cash items | ||||||||||
Depreciation Depletion and Amortization | 11.92 | 23.83 | (50 | )% | ||||||
Non-cash General and Administrative | $1.36 | $1.38 | (1 | )% | ||||||
Schedule 6: Adjusted Net Income (Loss)
(in thousands, except per share amounts, unaudited)
Adjusted net income is a supplemental non-GAAP financial measure that is used by management 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 0% for the three-month period ended March 31, 2016, and a tax rate of 38.5% for the three-month periods ended March 31, 2015. 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 presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of adjusted net income (loss).
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Net loss | $ | (47,237 | ) | $ | (18,421 | ) | ||
Adjustments to net loss: | ||||||||
Derivative (gain) loss | 1,007 | (18,856 | ) | |||||
Derivative cash settlements | 7,508 | 35,466 | ||||||
Gain on termination fee | (6,000 | ) | — | |||||
Impairment of proved properties | 10,000 | — | ||||||
Abandonment and impairment of unproved properties | 6,906 | 5,469 | ||||||
Exploratory dry hole | 232 | — | ||||||
Stock-based compensation | 3,004 | 3,427 | ||||||
Cash severance costs (1) | 2,162 | — | ||||||
Total adjustments before taxes | 24,819 | 25,506 | ||||||
Income tax effect | — | (9,820 | ) | |||||
Total adjustments after taxes | $ | 24,819 | $ | 15,686 | ||||
Adjusted net loss | $ | (22,418 | ) | $ | (2,735 | ) | ||
Adjusted net loss per diluted share | $ | (0.46 | ) | $ | (0.06 | ) | ||
Diluted weighted-average common shares outstanding | 49,131 | 44,520 | ||||||
(1) Included as a portion of general and administrative expense on the consolidated statement of operations. | ||||||||
Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management 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 the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.
Three Months Ended March 31, | ||||||||
2016 | 2015 | |||||||
Net loss | $ | (47,237 | ) | $ | (18,421 | ) | ||
Exploration | 266 | 498 | ||||||
Depreciation, depletion and amortization | 26,379 | 59,004 | ||||||
Impairment of proved properties | 10,000 | — | ||||||
Abandonment and impairment of unproved properties | 6,906 | 5,469 | ||||||
Stock-based compensation | 3,004 | 3,427 | ||||||
Cash severance costs (1) | 2,162 | — | ||||||
Gain on termination fee | (6,000 | ) | — | |||||
Interest expense | 14,547 | 14,238 | ||||||
Derivative (gain) loss | 1,007 | (18,856 | ) | |||||
Derivative cash settlements | 7,508 | 35,466 | ||||||
Income tax benefit | — | (11,537 | ) | |||||
Adjusted EBITDAX | $ | 18,542 | $ | 69,288 | ||||
(1) Included as a portion of general and administrative expense on the consolidated statement of operations. | ||||||||