- Second quarter production volumes averaged 23.2 MBoe per day, compared to guidance of 23.0 MBoe per day at the midpoint
- GAAP cash used in operating activities of $11.8 million; adjusted EBITDAX(1) of $27.7 million; GAAP net loss of $1.00 per diluted share; adjusted net loss(1) of $0.40 per diluted share
- Improving operational efficiency resulted in reductions in LOE and midstream expense; the Company is updating its 2016 guidance, reducing the full-year midpoint for LOE, midstream, and CAPEX
- Suspending asset sale processes and focusing on other liquidity enhancing and debt reducing measures
(1) Non-GAAP measure, see attached Reconciliation Schedules.
DENVER, Aug. 01, 2016 (GLOBE NEWSWIRE) — Bonanza Creek Energy, Inc. (NYSE:BCEI) (the “Company”) today announces its second quarter 2016 financial and operating results.
Richard Carty, President and Chief Executive Officer, commented, “Our operations team continues to exceed expectations and is focused on increasing efficiencies and reducing costs. The second quarter marked the fourth consecutive quarter of asset outperformance in the Rockies since the full field implementation of RMI in the third quarter of 2015, demonstrating a repeated pattern of higher production volumes and lower LOE. Our efficiency mandates have yielded a 41% decrease in second quarter LOE from a year ago, and a 39% decrease in second quarter G&A from the prior year. The second quarter also marked an important milestone of two million work-hours completed without a lost time injury, a commendable record for our health, safety, and environmental initiatives. While the operating assets continue to perform, our balance sheet and access to capital remain a major headwind. In an effort to enhance the liquidity position of the Company, in the first and second quarter of 2016 we targeted divestitures of both our RMI and MidCon assets. Although we received strong economic bids for both of these asset packages, conditions included in the bid proposals require that the Company improve its liquidity and its balance sheet. As a result, we have suspended the divestiture efforts to focus on other liquidity enhancing and debt restructuring options. To assist in evaluating all alternatives, we have retained (as previously announced) Perella Weinberg Partners as restructuring advisors and Davis Polk & Wardwell as legal advisors.”
Mr. Carty further commented, “Lastly, I want to express our gratitude to Tony Buchanon, Executive Vice President and Chief Operating Officer, for his contributions in building a strong and capable operations team since 2013. Tony recently decided to step down from his position in order to pursue another opportunity in the industry. We wish him the very best. Our Board of Directors is confident that our experienced engineering and operations managers reporting to Dean Tinsley, Vice President, Rocky Mountain Asset Management, Kerry McCowen, Vice President, Rocky Mountain Operations, John Larson, Vice President, Mid-Continent Operations, and David Stewart, Vice President, Environmental, Health, Safety and Regulatory Compliance, and other talented Bonanza leaders will ensure that our company doesn’t miss a beat. In addition, Jeff Wojahn, a member of our Board and the former President of Encana Oil & Gas (USA) Inc., has graciously volunteered to serve as Senior Operations Advisor, to be done in his continued capacity as a director of the Company. Although our drilling and completion program is currently suspended while we address our balance sheet, Jeff’s significant experience in the Wattenberg Field will be extremely valuable as the Company prepares to resume more typical operational activity levels.”
Second Quarter 2016 Results
For the second quarter of 2016, the Company reported average daily production of 23.2 MBoe per day, a 4% sequential decrease from the first quarter of 2016, and a 17% decrease from the second quarter of 2015. The reduction in production volumes is a result of suspended drilling and completion operations at the end of the first quarter. Product mix for the second quarter of 2016 was 56% oil, 19% NGLs, and 25% natural gas.
Net revenue for the second quarter of 2016 was $54.5 million, a 23% sequential increase from the first quarter of 2016 and a 40% decrease from the second quarter of 2015. Crude oil accounted for approximately 83% of total revenue. Differentials for the Company’s Rocky Mountain oil production during the quarter averaged approximately $8.99 per Bbl. Average realized prices for the second quarter of 2016 are presented below.
| Average Realized Prices | |||||
| Three Months Ended June 30, 2016 | |||||
| Before Derivatives | After Derivatives | ||||
| Oil (per Bbl) | 38.21 | 41.51 | |||
| Gas (per Mcf) | 1.48 | 1.48 | |||
| NGL (per Bbl) | 11.53 | 11.53 | |||
| Boe (Per Boe) | 25.78 | 27.62 | |||
LOE for the second quarter of 2016 was $10.7 million, or $5.08 per Boe, compared to $13.3 million, or $6.01 per Boe in the first quarter of 2016, and $18.2 million, or $7.12 per Boe in the second quarter of 2015. The Company continues to execute on cost saving metrics resulting in a 19% sequential decrease and a 41% year over year decrease in total LOE. Below is a breakout of the Company’s regional LOE and gas plant and midstream operating expense for the second quarter of 2016.
| Lease Operating Expense | |||||||||||||||||||||||
| Three Months Ended June 30, 2016 | |||||||||||||||||||||||
| Rocky Mountain | Mid-Continent | Total Company | |||||||||||||||||||||
| ($M) | ($/Boe) | ($M) | ($/Boe) | ($M) | ($/Boe) | ||||||||||||||||||
| LOE | $ | 8,657 | $ | 4.99 | $ | 2,080 | $ | 5.46 | $ | 10,737 | $ | 5.08 | |||||||||||
| Gas plant and midstream operating expense | 1,526 | 0.88 | 2,009 | 5.27 | 3,535 | 1.67 | |||||||||||||||||
| Total | $ | 10,183 | $ | 5.87 | $ | 4,089 | $ | 10.73 | $ | 14,272 | $ | 6.75 | |||||||||||
General and administrative (“G&A”) expense for the second quarter of 2016 was $13.2 million, or $6.26 per Boe. This compares to G&A expense of $21.6 million, or $8.47 per Boe in the second quarter of 2015 and $17.7 million, or $7.99 per Boe in the first quarter of 2016. On a sequential basis, total G&A expense has decreased by 25% and has decreased by 39% from the second quarter of 2015. Cash G&A expense, which excludes stock compensation, for the second quarter of 2016 was $10.9 million, or $5.13 per Boe. This compares to cash G&A expense, excluding severance charges, of $12.5 million, or $5.66 per Boe in the first quarter of 2016. The decrease in cash G&A is a result of the previously announced reduction in force which occurred at the end of the first quarter.
Depreciation, depletion and amortization (“DD&A”) for second quarter of 2016 was $30.9 million, or $14.62 per Boe, a 23% sequential increase on a per unit basis from the first quarter of 2016 and a 47% decrease on a per unit basis from the second quarter 2015. The increase in total DD&A expense in the second quarter is primarily due to the resumption of DD&A expense for the Rocky Mountain Infrastructure (“RMI”) assets, which were previously classified as held for sale and not depreciated pursuant to GAAP. Upon moving these assets back into Proved Properties on the balance sheet, DD&A expense was calculated and recorded for the three quarters during which the RMI assets were classified as held for sale. The Company’s Arkansas (“MidCon”) assets were also moved out of the held for sale classification. As the MidCon assets were impaired to market value while they were classified as held for sale, however, a DD&A catch-up is unnecessary for these assets.
As of the end of the second quarter, year to date 2016 total CAPEX was $17.5 million, of which $2.3 million was attributable to RMI. A downward adjustment of $3.1 million in CAPEX was recorded in the second quarter as a result of estimated costs which exceeded actual costs.
Reported GAAP net loss for the second quarter of 2016 was $49.5 million, or $1.00 per diluted share, compared to a net loss of $41.2 million, or $0.83 per diluted share, for the second quarter of 2015. Adjusted net loss for the second quarter of 2016 was $19.7 million, or $0.40 per diluted share, compared to an adjusted net loss of $6.9 million, or $0.14 per diluted share for the second quarter of 2015, and an adjusted net loss of $22.4 million, or $0.46 per diluted share for the first quarter of 2016. Adjusted EBITDAX for the second quarter of 2016 was $27.7 million, a 63% decrease compared to $74.0 million for the second quarter of 2015 and a 50% sequential increase from the first quarter of 2016.
Cash G&A, adjusted net income and adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures. Cash G&A is defined as GAAP G&A expense excluding the stock compensation portion of the expense. See Schedule 1 for general and administrative break-out of stock-based compensation.
The table below summarizes the Company’s quarterly and year to date results as compared to guidance provided in the first quarter earnings release. Updated twelve month guidance is included in the Third Quarter Guidance and Update section of this release.
| Guidance vs Actual Summary | |||||
| Three Months Ended June 30, 2016 | |||||
| Guidance | Actual | ||||
| Production (MBoe/d) | 22.7 – 23.3 | 23.2 | |||
| Twelve Months Ended December 31, 2016 |
Six Months Ended June 30, 2016 |
||||
| Guidance | Actual | ||||
| LOE ($MM) | $52 – $56 | $ | 24.0 | ||
| Midstream ($MM) | $15 – $17 | $ | 7.3 | ||
| Cash G&A ($MM)* | $40 – $44 | $ | 23.4 | ||
| Production taxes (% of pre-derivative realization) | 6% – 7% | 7.5 | % | ||
| CAPEX ($MM) | $35 – $45 | $ | 17.5 | ||
| * Cash G&A guidance is a non-GAAP measure that is exclusive of the Company’s stock based compensation and one-time severance charges of $2.2 million in the first quarter of 2016. The Company does not guide to GAAP G&A expense as it has less certainty to the stock based compensation portion of GAAP G&A. | |||||
Operations Update
Rocky Mountain Region – Wattenberg
Production from the Rocky Mountain region during the second quarter of 2016, averaged 19.1 MBoe/d, or 82% of total Company volumes. The production was comprised of 56% crude oil, 20% NGLs, and 24% natural gas. Rocky Mountain average daily sales volumes decreased sequentially by 4% from the first quarter of 2016 and decreased 16% compared to the second quarter of 2015 due to suspended drilling and completion activity.
The Company did not drill or complete any wells during the second quarter as it idled its development program at the end of the first quarter. At the end of the second quarter, the Company had six drilled uncompleted wells, consisting of four standard reach and two extended reach laterals. The Company does not have any current plans to restart drilling or completion activity in the second half of 2016.
Mid-Continent Region – Cotton Valley
The Mid-Continent region contributed 4.2 MBoe/d, or 18% of total Company net sales volumes for the second quarter of 2016, and was comprised of 54% crude oil, 16% NGLs, and 30% natural gas. Sales volumes decreased sequentially by 6% from the first quarter of 2016 and decreased 21% compared to the second quarter of 2015 as a result of suspended drilling and completions activity.
Financial and Risk Management Update
Debt and Liquidity
The Company has a $1.0 billion revolving credit facility, which was redetermined in May of 2016 to an approved borrowing base and commitment amount of $200 million. As of June 30, 2016, the Company had borrowings under its credit facility of $273.3 million and cash totaling $170.2 million. Upon redetermination of the Company’s credit facility, its borrowings exceeded its borrowing base by $88 million. The Company has elected to pay this deficiency in six monthly installments as allowed under the terms of the credit facility agreement. During the quarter the Company paid off its remaining $12.0 million letter of credit and made its first credit facility deficiency payment of $14.7 million. The Company has subsequently paid its second deficiency payment of $14.7 million in July and has four remaining payments to be made on a monthly basis to remedy its credit facility deficiency. The Company’s next redetermination is expected to happen in the fourth quarter of 2016. As of June 30, 2016, the Company was in compliance with all financial covenants under its credit facility, with a senior secured debt to TTM EBITDAX ratio of 1.5x, an interest coverage ratio of 3.2x, and a current ratio of 2.7x.
In addition to the credit facility, 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. The Company is subject to certain covenants under the respective indentures governing the senior notes that, among other things, limit its ability to incur additional indebtedness. Specifically, the incurrence by the Company (or any of the guarantors under the indentures) of additional indebtedness and letters of credit under the revolving credit facility in an aggregate principal amount at any one time outstanding is not to exceed the greater of (a) $300.0 million or (b) 35% of the Company’s Adjusted Consolidated Net Tangible Assets (“ACNTA”) determined as of the date of the incurrence of such indebtedness. ACNTA is defined as the Company’s PV-10 value plus capitalized costs for unproved properties plus consolidated net working capital and other tangible assets. At June 30, 2016, 35% of the Company’s ACNTA was equal to approximately $380 million.
While the Company currently has sufficient cash on hand to make its upcoming bond interest payment, it has made the election to not pay the interest payment for its $300 million 5.75% senior unsecured notes, which was due on August 1, 2016. By not paying the interest due, the Company has entered into a 30-day grace period during which it retains the right to pay the interest due to the holders of its 5.75% notes and thereby remain within compliance of the bond indenture. The 30-day grace period also applies to any potential cross-default under the Company’s credit facility with respect to the bond interest payment.
Asset Sale Processes – RMI and Mid-Continent
During the second quarter of 2016, the Company re-launched a marketing effort to divest its RMI assets. The Company engaged a third party advisor to assist in locating a purchaser for these assets by performing a widely marketed process. While the Company received economically strong bids for the assets, they all contained significant conditions that required the Company to remedy its debt burden and its limited access to capital. With regard to the MidCon assets, the Company also performed a widely marketed process to divest the assets with the assistance of a third party advisor. Bids received for these assets also contained significant going concern representations resulting from the Company’s liquidity constraints. Upon reviewing these bids, given the significant conditions and, in the absence of improvement to the Company’s balance sheet, the unlikely sale for either package, the Company’s management and board have decided to suspend these asset sale processes and focus efforts on alternative methods to reduce debt and increase liquidity.
Please review the Company’s quarterly report on Form 10-Q filed with the Securities Exchange Commission on August 1, 2016 for further information regarding the Company’s debt and liquidity.
Commodity Derivatives Positions
The following table summarizes the Company’s crude oil and natural gas commodity derivative positions as of June 30, 2016 and settling quarterly:
| Settlement Period | Volume (Bbls/d) | Contract Type | Swap Price | |||||
| 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 | |||||
| 3Q 2016 | 4,733 | Floor (Long Put) | $ | 51.01 | ||||
| 4Q 2016 | 4,031 | Floor (Long Put) | $ | 51.01 | ||||
Third Quarter Guidance and Update
The Company is providing updated cost and CAPEX guidance for the remainder of 2016 that reflects a lower cost structure that the Company implemented during the first half of the year. As a result of efficiency gains in its operations and service cost reductions, the Company has reduced the midpoint of its full year guidance for LOE and Midstream expense by 15% and 6%, respectively. The Company attributes approximately 80% of the cost savings to efficiency gains that it expects to be repeatable irrespective of service costs. The Company has also reduced its full year CAPEX guidance midpoint by 25% due to reductions in previous well costs estimates. The table below provides updated guidance for the third quarter and full year of 2016.
| Guidance Summary | |||
| Three Months Ended September 30, 2016 | Twelve Months Ended December 31, 2016 | ||
| Production (MBoe/d) | 19.6 – 20.2 | 19.7 – 21.7 | |
| LOE ($MM) | $44 – $48 | ||
| Midstream expense ($MM) | $14 – $16 | ||
| Cash G&A ($/Boe)* | $40 – $44 | ||
| Production taxes (% of pre-derivative realization) | 6% – 7% | ||
| Total CAPEX | $25 – $35 | ||
| * Cash G&A guidance is a non-GAAP measure that is exclusive of the Company’s stock based compensation and one-time severance charges of $2.2 million in the first quarter of 2016. The Company does not guide to GAAP G&A expense as it has less certainty to the stock based compensation portion of GAAP G&A. | |||
Conference Call Information
The Company will not be hosting a conference call to discuss its second quarter results.
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 updated 2016 guidance; drilling expectations; timing of future redeterminations of the Company’s borrowing base under its revolving credit facility and anticipated efficiency gains. 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.
| Schedule 1: Statement of Operations | |||||||||||||||
| (in thousands, expect for per share amounts, unaudited) |
|||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Operating net revenues: | |||||||||||||||
| Oil and gas sales | $ | 54,530 | $ | 90,422 | $ | 98,704 | $ | 163,498 | |||||||
| Operating expenses: | |||||||||||||||
| Lease operating expense | 10,737 | 18,169 | 24,035 | 35,142 | |||||||||||
| Gas plant and midstream operating expense | 3,535 | 2,726 | 7,324 | 5,017 | |||||||||||
| Severance and ad valorem taxes | 4,277 | 4,148 | 7,431 | 10,644 | |||||||||||
| Exploration | 677 | 5,748 | 943 | 6,246 | |||||||||||
| Depreciation, depletion and amortization | 30,927 | 69,925 | 57,306 | 128,929 | |||||||||||
| Impairment of oil and gas properties | — | — | 10,000 | — | |||||||||||
| Abandonment and impairment of unproved properties | 9,875 | 14,527 | 16,781 | 19,996 | |||||||||||
| General and administrative (including $2,380, $4,359, $5,384 and $7,787, respectively, of stock-based compensation) | 13,235 | 21,602 | 30,920 | 38,474 | |||||||||||
| Total operating expenses | 73,263 | 136,845 | 154,740 | 244,448 | |||||||||||
| Loss from operations | (18,733 | ) | (46,423 | ) | (56,036 | ) | (80,950 | ) | |||||||
| Other income (expense): | |||||||||||||||
| Derivative gain (loss) | (12,923 | ) | (5,478 | ) | (13,930 | ) | 13,378 | ||||||||
| Interest expense | (16,527 | ) | (14,468 | ) | (31,074 | ) | (28,706 | ) | |||||||
| Gain on termination fee | — | — | 6,000 | — | |||||||||||
| Other gain (loss) | (1,294 | ) | 198 | (1,674 | ) | 148 | |||||||||
| Total other income (expense) | (30,744 | ) | (19,748 | ) | (40,678 | ) | (15,180 | ) | |||||||
| Loss from operations before taxes | (49,477 | ) | (66,171 | ) | (96,714 | ) | (96,130 | ) | |||||||
| Income tax benefit | — | 25,007 | — | 36,544 | |||||||||||
| Net loss | $ | (49,477 | ) | $ | (41,164 | ) | (96,714 | ) | $ | (59,586 | ) | ||||
| Basic net loss per common share | $ | (1.00 | ) | $ | (0.83 | ) | $ | (1.97 | ) | $ | (1.25 | ) | |||
| Diluted net loss per common share | $ | (1.00 | ) | $ | (0.83 | ) | $ | (1.97 | ) | $ | (1.25 | ) | |||
| Basic weighted-average common shares outstanding | 49,277 | 48,923 | 49,204 | 46,734 | |||||||||||
| Diluted weighted-average common shares outstanding | 49,277 | 48,923 | 49,204 | 46,734 | |||||||||||
| 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 June 30, | Six Months Ended June 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Cash flows from operating activities: | |||||||||||||||
| Net loss | $ | (49,477 | ) | $ | (41,164 | ) | $ | (96,714 | ) | $ | (59,586 | ) | |||
| Adjustments to reconcile net loss to net cash provided by operating activities: | |||||||||||||||
| Depreciation, depletion and amortization | 30,927 | 69,925 | 57,306 | 128,929 | |||||||||||
| Deferred income tax benefit | — | (25,007 | ) | — | (36,544 | ) | |||||||||
| Impairment of oil and gas properties | — | — | 10,000 | — | |||||||||||
| Abandonment and impairment of unproved properties | 9,875 | 14,527 | 16,781 | 19,996 | |||||||||||
| Dry hole expense | 734 | 5,680 | 966 | 5,680 | |||||||||||
| Stock-based compensation | 2,380 | 4,359 | 5,384 | 7,787 | |||||||||||
| Amortization of deferred financing costs and debt premium | 1,671 | 703 | 2,279 | 1,226 | |||||||||||
| Accretion of contractual obligation for land acquisition | — | 349 | — | 698 | |||||||||||
| Derivative (gain) loss | 12,923 | 5,478 | 13,930 | (13,378 | ) | ||||||||||
| Derivative cash settlements | 3,893 | 15,189 | 11,401 | 50,655 | |||||||||||
| Other | 4 | (16 | ) | (112 | ) | (43 | ) | ||||||||
| Changes in current assets and liabilities: | |||||||||||||||
| Accounts receivable | 371 | 2,021 | 23,415 | 18,319 | |||||||||||
| Prepaid expenses and other assets | 274 | 525 | (1,348 | ) | (1,348 | ) | |||||||||
| Accounts payable and accrued liabilities | (25,316 | ) | (21,073 | ) | (28,457 | ) | (23,054 | ) | |||||||
| Settlement of asset retirement obligations | (34 | ) | (234 | ) | (75 | ) | (519 | ) | |||||||
| Net cash provided by (used in) operating activities | (11,775 | ) | 31,262 | 14,756 | 98,818 | ||||||||||
| Cash flows from investing activities: | |||||||||||||||
| Acquisition of oil and gas properties | (284 | ) | (532 | ) | (816 | ) | (11,914 | ) | |||||||
| Payments of contractual obligation | (12,000 | ) | — | (12,000 | ) | — | |||||||||
| Exploration and development of oil and gas properties | (7,881 | ) | (128,694 | ) | (42,753 | ) | (283,106 | ) | |||||||
| Increase in restricted cash | (2 | ) | — | (2,535 | ) | — | |||||||||
| Additions to property and equipment – non oil and gas | (8 | ) | 841 | 39 | (649 | ) | |||||||||
| Net cash used in investing activities | (20,175 | ) | (128,385 | ) | (58,065 | ) | (295,669 | ) | |||||||
| Cash flows from financing activities: | |||||||||||||||
| Proceeds from credit facility | — | 43,000 | 209,000 | 87,000 | |||||||||||
| Payments to credit facility | (14,667 | ) | — | (14,667 | ) | (77,000 | ) | ||||||||
| Proceeds from sale of common stock | — | — | — | 209,300 | |||||||||||
| Offering costs related to sale of common stock | — | (115 | ) | — | (6,607 | ) | |||||||||
| Offering costs related to sale of Senior Notes | — | (74 | ) | — | (93 | ) | |||||||||
| Payment of employee tax withholdings in exchange for the return of common stock | (44 | ) | (321 | ) | (273 | ) | (2,448 | ) | |||||||
| Deferred restructuring charges | (1,684 | ) | — | (1,684 | ) | — | |||||||||
| Deferred financing costs | (83 | ) | (541 | ) | (237 | ) | (545 | ) | |||||||
| Net cash provided by (used in) financing activities | (16,478 | ) | 41,949 | 192,139 | 209,607 | ||||||||||
| Net change in cash and cash equivalents | (48,428 | ) | (55,174 | ) | 148,830 | 12,756 | |||||||||
| Cash and cash equivalents: | |||||||||||||||
| Beginning of period | 218,599 | 70,514 | 21,341 | 2,584 | |||||||||||
| End of period | $ | 170,171 | $ | 15,340 | $ | 170,171 | $ | 15,340 | |||||||
| Schedule 3: Condensed Balance Sheet | |||||||
| (in thousands, unaudited) | |||||||
| June 30, | December 31, | ||||||
| 2016 | 2015 | ||||||
| ASSETS | |||||||
| Current assets | $ | 221,685 | $ | 120,074 | |||
| Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion and amortization of $636,917 in 2015 | — | 214,922 | |||||
| Total property and equipment, net | 1,071,501 | 922,344 | |||||
| Other noncurrent assets | 4,980 | 2,301 | |||||
| Total Assets | $ | 1,298,166 | $ | 1,259,641 | |||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
| Current liabilities | $ | 1,147,269 | $ | 135,973 | |||
| Long-term debt | — | 871,666 | |||||
| Other long-term liabilities | 33,093 | 42,595 | |||||
| Total Liabilities | 1,180,362 | 1,050,234 | |||||
| Stockholders’ Equity | 117,804 | 209,407 | |||||
| Total Liabilities and Stockholders’ Equity | $ | 1,298,166 | $ | 1,259,641 | |||
| Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges) | |||||||||||||||
| (unaudited) | |||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Wellhead Volumes and Prices | |||||||||||||||
| Crude Oil and Condensate Sales Volumes (Bbl/d) | |||||||||||||||
| Rocky Mountains | 10,715 | 14,079 | 11,190 | 13,877 | |||||||||||
| Mid-Continent | 2,270 | 2,768 | 2,353 | 2,827 | |||||||||||
| Total | 12,985 | 16,847 | 13,543 | 16,704 | |||||||||||
| Crude Oil and Condensate Realized Prices ($/Bbl) | |||||||||||||||
| Rocky Mountains | $ | 36.74 | $ | 48.72 | $ | 30.70 | $ | 43.60 | |||||||
| Mid-Continent | $ | 45.18 | $ | 55.93 | $ | 40.41 | $ | 51.60 | |||||||
| Composite (before derivatives) | $ | 38.21 | $ | 49.90 | $ | 32.39 | $ | 44.96 | |||||||
| Composite (after derivatives) | $ | 41.51 | $ | 59.37 | $ | 37.01 | $ | 61.26 | |||||||
| Natural Gas Liquids Sales Volumes (Bbl/d) | |||||||||||||||
| Rocky Mountains | 3,772 | 3,696 | 3,594 | 3,579 | |||||||||||
| Mid-Continent | 675 | 1,020 | 697 | 1,007 | |||||||||||
| Total | 4,447 | 4,716 | 4,291 | 4,586 | |||||||||||
| Natural Gas Liquids Realized Prices ($/Bbl) | |||||||||||||||
| Rocky Mountains | $ | 10.59 | $ | 16.21 | $ | 11.80 | $ | 14.99 | |||||||
| Mid-Continent | $ | 16.75 | $ | 16.56 | $ | 14.48 | $ | 16.16 | |||||||
| Composite (before derivatives) | $ | 11.53 | $ | 16.28 | $ | 12.23 | $ | 15.25 | |||||||
| Composite (after derivatives) | $ | 11.53 | $ | 16.28 | $ | 12.23 | $ | 15.25 | |||||||
| Natural Gas Sales Volumes (Mcf/d) | |||||||||||||||
| Rocky Mountains | 27,450 | 29,782 | 28,044 | 29,299 | |||||||||||
| Mid-Continent | 7,444 | 9,075 | 7,648 | 9,612 | |||||||||||
| Total | 34,894 | 38,857 | 35,692 | 38,911 | |||||||||||
| Natural Gas Realized Prices ($/Mcf) | |||||||||||||||
| Rocky Mountains | $ | 1.34 | $ | 1.65 | $ | 1.27 | $ | 1.80 | |||||||
| Mid-Continent | $ | 2.01 | $ | 2.99 | $ | 2.05 | $ | 3.10 | |||||||
| Composite (before derivatives) | $ | 1.48 | $ | 1.96 | $ | 1.44 | $ | 2.12 | |||||||
| Composite (after derivatives) | $ | 1.48 | $ | 2.15 | $ | 1.44 | $ | 2.31 | |||||||
| Crude Oil Equivalent Sales Volumes (Boe/d) | |||||||||||||||
| Rocky Mountains | 19,062 | 22,739 | 19,458 | 22,339 | |||||||||||
| Mid-Continent | 4,186 | 5,300 | 4,325 | 5,436 | |||||||||||
| Total | 23,248 | 28,039 | 23,783 | 27,775 | |||||||||||
| Crude Oil Equivalent Sales Prices ($/Boe) | |||||||||||||||
| Rocky Mountains | $ | 24.68 | $ | 34.96 | $ | 21.66 | $ | 31.84 | |||||||
| Mid-Continent | $ | 30.78 | $ | 37.50 | $ | 27.94 | $ | 35.32 | |||||||
| Composite (before derivatives) | $ | 25.78 | $ | 35.44 | $ | 22.80 | $ | 32.52 | |||||||
| Composite (after derivatives) | $ | 27.62 | $ | 41.39 | $ | 25.44 | $ | 42.60 | |||||||
| Total Sales Volumes (MBoe) | 2,115.5 | 2,551.5 | 4,328.7 | 5,027.3 | |||||||||||
| Schedule 5: Per unit operating margins | |||||||||||||||||||||||||||
| (unaudited) | |||||||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||
| 2016 | 2015 | Percent Change | 2016 | 2015 | Percent Change | ||||||||||||||||||||||
| Production | |||||||||||||||||||||||||||
| Oil (MBbl) | 1,181.7 | 1,533.0 | (23 | )% | 2,465.0 | 3,023.5 | (18 | )% | |||||||||||||||||||
| Gas (MMcf) | 3,175.3 | 3,535.9 | (10 | )% | 6,496.0 | 7,042.8 | (8 | )% | |||||||||||||||||||
| NGL (MBbl) | 404.7 | 429.2 | (6 | )% | 781.0 | 830.0 | (6 | )% | |||||||||||||||||||
| Equivalent (MBoe) | 2,115.5 | 2,551.5 | (17 | )% | 4,328.7 | 5,027.3 | (14 | )% | |||||||||||||||||||
| Realized pricing (before derivatives) | |||||||||||||||||||||||||||
| Oil ($/Bbl) | $ | 38.21 | $ | 49.90 | (23 | )% | $ | 32.38 | $ | 44.96 | (28 | )% | |||||||||||||||
| Gas ($/Mcf) | $ | 1.48 | $ | 1.96 | (24 | )% | 1.44 | 2.12 | (32 | )% | |||||||||||||||||
| NGL ($/Bbl) | $ | 11.53 | $ | 16.28 | (29 | )% | 12.23 | 15.25 | (20 | )% | |||||||||||||||||
| Equivalent ($/Boe) | $ | 25.78 | $ | 35.44 | (27 | )% | $ | 22.80 | $ | 32.52 | (30 | )% | |||||||||||||||
| Per Unit Costs ($/Boe) | |||||||||||||||||||||||||||
| Realized price (before derivatives) | $ | 25.78 | $ | 35.44 | (27 | )% | $ | 22.80 | 32.52 | (30 | )% | ||||||||||||||||
| LOE | 5.08 | 7.12 | (29 | )% | $ | 5.55 | $ | 6.99 | (21 | )% | |||||||||||||||||
| Gas plant and midstream operating expense | 1.67 | 1.07 | 56 | % | $ | 1.69 | $ | 1.00 | 69 | % | |||||||||||||||||
| Severance and Ad Valorem | 2.02 | 1.63 | 24 | % | $ | 1.72 | $ | 2.12 | (19 | )% | |||||||||||||||||
| Cash General and Administrative | 5.13 | 6.76 | (24 | )% | $ | 5.90 | $ | 6.10 | (3 | )% | |||||||||||||||||
| Total cash operating costs | $ | 13.90 | $ | 16.58 | (16 | )% | $ | 14.86 | $ | 16.21 | (8 | )% | |||||||||||||||
| Cash operating margin (before derivatives) | $ | 11.88 | $ | 18.86 | (37 | )% | $ | 7.94 | $ | 16.31 | (51 | )% | |||||||||||||||
| Derivative Cash Settlements | 1.84 | 5.95 | (69 | )% | $ | 2.64 | 10.08 | (74 | )% | ||||||||||||||||||
| Cash operating margin (after derivatives) | $ | 13.72 | $ | 24.81 | (45 | )% | $ | 10.58 | 26.39 | (60 | )% | ||||||||||||||||
| Non-cash items | |||||||||||||||||||||||||||
| Depreciation Depletion and Amortization | 14.62 | 27.41 | (47 | )% | $ | 13.24 | $ | 25.65 | (48 | )% | |||||||||||||||||
| Non-cash General and Administrative | $ | 1.13 | $ | 1.71 | (34 | )% | $ | 1.24 | $ | 1.55 | (20 | )% | |||||||||||||||
| 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 to present recurring profitability by excluding items which are non-recurring in nature or items which are not easily estimable. Management believes adjusted net income provides external users of the Company’s consolidated financial statements such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. 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 an applicable rate that approximates 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 June 30, | Six Months Ended June 30, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Net loss | $ | (49,477 | ) | $ | (41,164 | ) | $ | (96,714 | ) | $ | (59,586 | ) | ||||
| Adjustments to net loss: | ||||||||||||||||
| Derivative (gain) loss | 12,923 | 5,478 | 13,930 | (13,378 | ) | |||||||||||
| Derivative cash settlements | 3,893 | 15,189 | 11,401 | 50,655 | ||||||||||||
| Impairment of proved properties | — | — | 10,000 | — | ||||||||||||
| Abandonment and impairment of unproved properties | 9,875 | 14,527 | 16,781 | 19,996 | ||||||||||||
| Exploratory dry hole | 734 | 5,680 | 966 | 5,680 | ||||||||||||
| Stock-based compensation | 2,380 | 4,359 | 5,384 | 7,787 | ||||||||||||
| Cash severance costs (1) | — | — | 2,162 | — | ||||||||||||
| Gain on termination fee (2) | — | — | (6,000 | ) | — | |||||||||||
| Derivative Conversion Payment (3) | — | 10,472 | — | 10,472 | ||||||||||||
| Total adjustments before taxes | 29,805 | 55,705 | 54,624 | 81,212 | ||||||||||||
| Income tax effect | — | % | 38.5 | % | — | % | 38.5 | % | ||||||||
| Total adjustments after taxes | $ | 29,805 | $ | 34,259 | $ | 54,624 | $ | 49,945 | ||||||||
| Adjusted net loss | $ | (19,672 | ) | $ | (6,905 | ) | $ | (42,090 | ) | $ | (9,641 | ) | ||||
| Adjusted net loss per diluted share | $ | (0.40 | ) | $ | (0.14 | ) | $ | (0.86 | ) | $ | (0.21 | ) | ||||
| Diluted weighted-average common shares outstanding | 49,277 | 48,923 | 49,204 | 46,734 | ||||||||||||
| (1) Included as a portion of general and administrative expense on the consolidated statement of operations. | ||||||||||||||||
| (2) Gain resulting from termination fee on unsuccessful RMI transaction during the first quarter of 2016. | ||||||||||||||||
| (3) Conversion payment is included as a portion of Derivative cash settlements on the statement of cash flows and results from hedge restructuring in the second quarter of 2015 from 3-way collars to 2-way collars. | ||||||||||||||||
| Schedule 7: Adjusted EBITDAX | ||||||||||||||||
| (in thousands, unaudited) | ||||||||||||||||
| Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management to provide a metric of the Company’s ability to internally generate funds for exploration and development of oil and gas properties and service debt. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes adjusted EBITDAX provides and external users of the Company’s consolidated financial statements, such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. 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 June 30, | Six Months Ended June 30, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Net loss | $ | (49,477 | ) | $ | (41,164 | ) | $ | (96,714 | ) | $ | (59,586 | ) | ||||
| Exploration | 677 | 5,748 | 943 | 6,246 | ||||||||||||
| Depreciation, depletion and amortization | 30,927 | 69,925 | 57,306 | 128,929 | ||||||||||||
| Impairment of proved properties | — | — | 10,000 | — | ||||||||||||
| Abandonment and impairment of unproved properties | 9,875 | 14,527 | 16,781 | 19,996 | ||||||||||||
| Stock-based compensation | 2,380 | 4,359 | 5,384 | 7,787 | ||||||||||||
| Cash severance costs (1) | — | — | 2,162 | — | ||||||||||||
| Gain on termination fee (2) | — | — | (6,000 | ) | — | |||||||||||
| Derivative conversion payment (3) | — | 10,472 | — | 10,472 | ||||||||||||
| Interest expense | 16,527 | 14,468 | 31,074 | 28,706 | ||||||||||||
| Derivative (gain) loss | 12,923 | 5,478 | 13,930 | (13,378 | ) | |||||||||||
| Derivative cash settlements | 3,893 | 15,189 | 11,401 | 50,655 | ||||||||||||
| Income tax benefit | — | (25,007 | ) | — | (36,544 | ) | ||||||||||
| Adjusted EBITDAX | $ | 27,725 | $ | 73,995 | $ | 46,267 | $ | 143,283 | ||||||||
| (1) Included as a portion of general and administrative expense on the consolidated statement of operations. | ||||||||||||||||
| (2) Gain resulting from termination fee on unsuccessful RMI transaction during the first quarter of 2016. | ||||||||||||||||
| (3) Conversion payment is included as a portion of Derivative cash settlements on the statement of cash flows and results from hedge restructuring in the second quarter of 2015 from 3-way collars to 2-way collars. | ||||||||||||||||
CONTACT: For further information, please contact: James R. Edwards Director - Investor Relations 720-440-6136 [email protected]