Attached files
| file | filename |
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| 8-K - 8-K - Bonanza Creek Energy, Inc. | a8-k6x30x18.htm |
Exhibit 99.1
NEWS RELEASE
Bonanza Creek Energy Announces
Second Quarter 2018 Financial Results and Operational Update
DENVER, August 8, 2018 – Bonanza Creek Energy, Inc. (NYSE: BCEI) (the "Company" or "Bonanza Creek") today announced its second quarter 2018 financial results and operating outlook and has posted an updated investor presentation on its corporate website.
Bonanza Creek delivered solid performance in the second quarter driven by strong production growth and lower capital spend. The Company is on track to grow Wattenberg production by approximately 25% year-over-year and 50% when comparing the fourth quarter of 2018 to the fourth quarter of 2017.
• | Second quarter sales volumes averaged 18.0 MBoe per day including the negative effects of a prior-period adjustment of 0.6 Mboe per day related to non-operated wells |
• | Rapidly improving well performance yields over 1,000 economic drilling locations in Wattenberg |
• | Full year 2018 Wattenberg production guidance raised while lowering full year capex guidance |
• | Accretive Mid-Continent divestiture of $117 million(1) bolsters balance sheet, improves unit operating costs and focuses operations on highest returning opportunities |
• | Well head pressures effectively managed via Rocky Mountain Infrastructure’s ("RMI") multiple third-party gas processing optionality |
• | Second quarter GAAP net income of $4.9 million, or $0.24 per diluted share; Adjusted net income(1) of $24.2 million, or $1.18 per diluted share |
• | Adjusted EBITDAX(2) of $34.8 million, 17% growth over first quarter 2018 |
(1) Effective date of February 1, 2018.
(2) Non-GAAP measures, see attached reconciliation schedules at the end of this release.
"Bonanza Creek delivered a solid quarter, marked by consistently improving operational and financial performance. We continue to be encouraged by the strong well performance across our Wattenberg position. Through a combination of improving well productivity from more recent completion designs, and attention to our base, we are able to raise our full year 2018 production guidance while lowering our full-year capex," said Eric Greager, President and CEO.
"As we look further into this year and next, we expect to see strong production growth, improving unit costs and increased operating cash flow as we accelerate our pace of development. Our balance sheet remains
strong. We are well-funded to execute on our capital plan which provides for approximately 25% Rockies production growth in 2018 and greater than 50% growth in 2019."
Second Quarter 2018 Results
During the second quarter of 2018, the Company reported average daily sales of 18.0 MBoe per day, which was at the low end of the Company's guidance range of 18.0 – 18.6 MBoe per day. Otherwise strong production during the quarter was impacted by a negative adjustment of 0.6 MBoe per day related to our interest in several months of production from two outside-operated pads. If not for this adjustment, second quarter production would have been at the high-end of guidance. The Company's second quarter reported sales increased 7% sequentially as we continue to see strong well performance from the recent completion designs and consistently low wellhead gathering pressures on the Company's RMI system. As a result of these factors, we are raising our full-year production guidance, pro-forma for the Mid-Continent divestiture, as detailed below. Product mix for the second quarter of 2018 was 58% oil, 20% NGLs, and 22% residue natural gas.
Net revenue for the second quarter of 2018 was $71.9 million, compared to $44.1 million for the second quarter of 2017. The increase in second quarter 2018 net revenue compared to 2017 was primarily a result of increased production and improved commodity pricing. Crude oil accounted for approximately 85% of total revenue. Differentials for the Company's Wattenberg oil production during the quarter averaged approximately $6.39 per barrel off of NYMEX WTI. Corporate average realized prices for the second quarter of 2018 are presented below.
Average Realized Prices (Before Derivatives) | |
Three Months Ended June 30, 2018 | |
Oil (per Bbl) | $63.67 |
Gas (per Mcf) | $2.13 |
NGL (per Bbl) | $19.05 |
Boe (Per Boe) | $43.57 |
Lease operating expenses ("LOE") for the second quarter of 2018 were $11.3 million, compared to $9.4 million in the second quarter of 2017. LOE on a unit basis for the second quarter of 2018 increased by 6.6% to $6.90 per Boe from $6.47 per Boe in the second quarter of 2017. Gas plant and midstream expenses for the second quarter of 2018 were $3.2 million, compared to $2.6 million in the second quarter of 2017. On a unit basis, gas plant and midstream expenses increased 10% to $1.98 per Boe for the second quarter of 2018 from $1.80 per Boe in the second quarter of 2017. Unit operating costs were impacted by decisions to pull forward certain planned activities and to pursue high-returning maintenance opportunities. They were also impacted by some cost inflation and environmental compliance costs required by the air emissions consent order in the Wattenberg Field. The Company’s accelerated compressor replacement program is now largely complete and will continue to ensure Bonanza Creek’s product flows while helping to reduce future operating costs. Additional spending on the company’s base optimization efforts (e.g. pipeline pigging and well servicing) have helped improve base production volumes. Cost pressures due to a busier operating environment and air emissions compliance costs are expected to continue through 2018 and are reflected in our revised LOE, gas plant and midstream expense guidance.
Below is a breakout of the Company's regional operating expenses for the second quarter of 2018.
Three Months Ended June 30, 2018 | |||||||||||||||||||||||
Wattenberg | Mid-Continent | Total Company | |||||||||||||||||||||
($M) | ($/Boe) | ($M) | ($/Boe) | ($M) | ($/Boe) | ||||||||||||||||||
Lease operating expense | $ | 8,247 | $ | 6.01 | $ | 3,069 | $ | 11.45 | $ | 11,316 | $ | 6.90 | |||||||||||
Gas plant and midstream operating expense | $ | 2,181 | $ | 1.59 | $ | 1,066 | $ | 3.98 | $ | 3,247 | $ | 1.98 | |||||||||||
Total | $ | 10,428 | $ | 7.60 | $ | 4,135 | $ | 15.43 | $ | 14,563 | $ | 8.88 | |||||||||||
The Company's general and administrative ("G&A") expense was $9.9 million for the second quarter of 2018, which includes $2.2 million in stock compensation. This represents a 48% decrease from the second quarter of 2017. Cash G&A expense, which excludes stock compensation, was $7.7 million for the quarter and is tracking at the low-end of the Company's full year 2018 guidance.
Reported net income for the second quarter of 2018 was $4.9 million, or $0.24 per diluted share. Adjusted net income for the second quarter of 2018 was $24.2 million, or $1.18 per diluted share.
Adjusted EBITDAX for the second quarter of 2018 was $34.8 million.
Cash G&A, Adjusted net income, and Adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures.
The table below summarizes the Company's annual results as compared to previously provided guidance.
Guidance vs Actual Summary | |||
2Q18 Guidance | 2Q18 Actual | ||
Production (MBoe/d) | 18.0 - 18.6 | 18.0 | |
Annual Guidance | YTD Actual | ||
Lease operating expense ($/Boe) | $5.00 - $6.00 | $6.92 | |
Gas plant and midstream operating expense ($/Boe) | $1.40 - $1.80 | $2.18 | |
Cash G&A ($MM)* | $33 - $35 | $16 | |
Production taxes (% of pre-derivative realization) | 7% - 8% | 8% | |
CAPEX ($MM) | $280 - $320 | $95 | |
* Cash G&A guidance is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. Please refer to the non-GAAP disclosure at the end of this release for information regarding cash G&A. | |||
Production, Capital, and Expense Outlook
The Company is updating its 2018 annual guidance to account for strong well performance in the Wattenberg and the sale of the Mid-Continent operations on August 6, 2018. Third quarter 2018 production and operating expense guidance is also being provided for the full company and pro-forma for the sale of the Mid-Continent operations. Below is a table summarizing the Company's production, capital, and expense guidance for the remainder of 2018.
Guidance Summary | ||||||
Three Months Ended September 30, 2018 (Pro-forma)(1) | Three Months Ended September 30, 2018 | Twelve Months Ended December 31, 2018 | ||||
Production (MBoe/d) | 16.6 - 17.2 | 17.4 - 18.0 | 17.4 - 18.0 | |||
LOE ($/Boe) | $4.40 - $4.80 | $4.75 - $5.15 | $5.50 - $5.90 | |||
Midstream expense ($/Boe) | $1.25 - $1.45 | $1.45 - $1.65 | $1.70 - $1.90 | |||
Recurring cash G&A* ($MM) | $32.5 - $33.5 | |||||
Production taxes (% of pre-derivative realization) | 7% - 8% | |||||
Total CAPEX ($MM) | $275 - $295 | |||||
* Recurring Cash G&A is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. | ||||||
(1) Pro-forma is the Company estimate for the third quarter of 2018 excluding results from the Mid-Continent operations. | ||||||
Operational Highlights
During the second quarter of 2018, the Company spud 12 gross (8.1 net) operated wells, ten of which were extended reach lateral ("XRL") wells, and completed 11 gross (11.0 net) operated wells, six of which were XRL wells.
The Company continues to be encouraged by its eight-well F26 pad on its western legacy acreage. These eight standard reach lateral ("SRL") wells have average cumulative production of 18.3 MBoe per 1,000 feet of lateral after 178 days of production. Additionally, the Company has finished completing and turned to production all eight XRL wells in the French Lake area. While two of the wells are currently hindered by mechanical issues, the Company is very pleased with the early results of the remaining six XRLs with results meeting or exceeding expectations.
The Company has provided updated production results for these wells in its August Investor Presentation, which is available on the Company's website.
The Company continued to benefit from multiple delivery points on the RMI system in the second quarter, including the Sterling interconnect which came online in the fourth quarter 2017. This delivery point flexibility, combined with consistent low line pressures on RMI, helped ensure minimal production curtailments. The Company entered into a new agreement with Cureton Front Range LLC (“Cureton”) whereby Cureton will gather and process gas from the Company’s northern acreage. In addition to gathering and processing services, the new agreement provides flow assurance by adding 15 MMcf per day of firm gas processing capacity for up to twenty-five years. The Company also secured three years of downstream residue transportation from Cureton in order to support upcoming production needs. This improves the Company’s flexibility to manage system pressures across its Wattenberg position and provides the backbone infrastructure system to allow development of the northern acreage.
Upon completing the 2018 resource assessment and as a result of rapidly improving well performance, the Company has identified over 1,000 economic SRL equivalent locations in its Wattenberg position.
Financial Highlights
As of the end of the second quarter, the Company had liquidity of $153.7 million, which included cash on hand of $22.0 million and $131.7 million of borrowing capacity under its credit facility. Pro forma for the Mid-Continent divestiture which closed on August 6, 2018, the Company had $256.6 million in liquidity. The balance sheet strength and Wattenberg inventory provide the company with a strong position from which to deliver disciplined, return-oriented growth.
Commodity Derivative Position
The Company's current hedge position is summarized in the table below and reflects additional hedges the Company entered into through August 8, 2018. Subsequent to quarter-end, the Company entered into natural gas basis swaps between NYMEX Henry Hub price and the Colorado Interstate Gas (CIG) Rockies Natural Gas price, the index on which the majority of the Company's natural gas is sold.
Crude Oil (NYMEX WTI) | Natural Gas (NYMEX Henry Hub) | Natural Gas (NYMEX Henry Hub) | |||||||||
Bbls/day | Weighted Avg. Price per Bbl | MMBtu/day | Weighted Avg. Price per MMBTU | MMBtu/day | Weighted Avg. Basis Differential to NYMEX Henry Hub Price per MMBtu | ||||||
3Q18 | |||||||||||
Cashless Collar | 2,000 | $43.00/$53.50 | 13,600 | $2.75/$3.32 | — | — | |||||
Swap | 5,000 | $57.87 | — | — | — | — | |||||
Basis Swap | — | — | — | — | 8,354 | $0.67 | |||||
4Q18 | |||||||||||
Cashless Collar | 2,000 | $43.00/$53.50 | 12,600 | $2.75/$3.35 | — | — | |||||
Swap | 5,000 | $58.07 | — | — | — | — | |||||
Basis Swap | — | — | — | — | 12,600 | $0.67 | |||||
1Q19 | |||||||||||
Cashless Collar | 2,000 | $43.00/$54.53 | 7,600 | $2.75/$3.22 | — | — | |||||
Swap | 5,000 | $59.33 | — | — | — | — | |||||
Basis Swap | — | — | — | — | 7,600 | $0.67 | |||||
2Q19 | |||||||||||
Cashless Collar | 3,330 | $51.81/$64.23 | 2,505 | $2.75/$3.22 | — | — | |||||
Swap | 4,500 | $58.32 | — | — | — | — | |||||
3Q19 | |||||||||||
Swap | 3,000 | $55.00 | — | — | — | — | |||||
4Q19 | |||||||||||
Swap | 3,000 | $55.00 | — | — | — | — | |||||
Conference Call Information
The Company will host a conference call to discuss these financial and operating results on August 9, 2018 at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Time). A webcast of the live event, as well as a replay, will
be available on the Investor Relations section of the Company’s website at www.bonanzacrk.com. Dial-in information for the conference call is included below.
Type | Phone Number | Passcode |
Live Participant | 877-793-4362 | 3289067 |
Replay | 855-859-2056 | 3289067 |
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 in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations. 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 development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company's reorganization; and updated 2018 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, 2017, filed on March 15, 2018, 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:
Doug Atkinson
Senior Manager, Investor Relations
720-225-6690
datkinson@bonanzacrk.com
Schedule 1: Statements of Operations
(in thousands, expect for per share amounts, unaudited)
Successor | Predecessor | |||||||||||
Three Months Ended June 30, 2018 | April 29, 2017 through June 30, 2017 | April 1, 2017 through April 28, 2017 | ||||||||||
Operating net revenues: | ||||||||||||
Oil and gas sales | $ | 71,872 | $ | 28,114 | $ | 16,030 | ||||||
Operating expenses: | ||||||||||||
Lease operating expense | 11,316 | 6,153 | 3,203 | |||||||||
Gas plant and midstream operating expense | 3,247 | 1,762 | 836 | |||||||||
Gathering, transportation and processing | 1,660 | — | — | |||||||||
Severance and ad valorem taxes | 6,071 | 2,408 | 1,352 | |||||||||
Exploration | 221 | 359 | 292 | |||||||||
Depreciation, depletion and amortization | 9,564 | 4,836 | 6,853 | |||||||||
Abandonment and impairment of unproved properties(1) | 2,477 | — | — | |||||||||
General and administrative (including $2,184, $7,949 and $391, respectively, of stock-based compensation) | 9,917 | 16,139 | 2,998 | |||||||||
Total operating expenses | 44,473 | 31,657 | 15,534 | |||||||||
Income (loss) from operations | 27,399 | (3,543 | ) | 496 | ||||||||
Other income (expense): | ||||||||||||
Derivative loss | (22,012 | ) | — | — | ||||||||
Interest expense | (805 | ) | (195 | ) | (1,088 | ) | ||||||
Reorganization items, net | — | — | 97,811 | |||||||||
Other income (expense) | 277 | 158 | (283 | ) | ||||||||
Total other income (expense) | (22,540 | ) | (37 | ) | 96,440 | |||||||
Income (loss) from operations before taxes | 4,859 | (3,580 | ) | 96,936 | ||||||||
Income tax benefit (expense) | — | — | — | |||||||||
Net income (loss) | $ | 4,859 | $ | (3,580 | ) | $ | 96,936 | |||||
Comprehensive income (loss) | $ | 4,859 | $ | (3,580 | ) | $ | 96,936 | |||||
Basic net income (loss) per common share | $ | 0.24 | $ | (0.18 | ) | $ | 1.88 | |||||
Diluted net income (loss) per common share | $ | 0.24 | $ | (0.18 | ) | $ | 1.85 | |||||
Basic weighted-average common shares outstanding | 20,488 | 20,369 | 49,902 | |||||||||
Diluted weighted-average common shares outstanding | 20,603 | 20,369 | 50,486 | |||||||||
Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which
allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury
stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q,
for a detailed calculation.
(1) The Company incurred impairment charges relating to the standard amortization of unproved properties within the Wattenberg Field during the Current Successor quarter.
Successor | Predecessor | |||||||||||
Six Months Ended June 30, 2018 | April 29, 2017 through June 30, 2017 | January 1, 2017 through April 28, 2017 | ||||||||||
Operating net revenues: | ||||||||||||
Oil and gas sales | $ | 136,064 | $ | 28,114 | $ | 68,589 | ||||||
Operating expenses: | ||||||||||||
Lease operating expense | 21,775 | 6,153 | 13,128 | |||||||||
Gas plant and midstream operating expense | 6,860 | 1,762 | 3,541 | |||||||||
Gathering, transportation and processing | 3,998 | — | — | |||||||||
Severance and ad valorem taxes | 11,303 | 2,408 | 5,671 | |||||||||
Exploration | 250 | 359 | 3,699 | |||||||||
Depreciation, depletion and amortization | 17,072 | 4,836 | 28,065 | |||||||||
Abandonment and impairment of unproved properties(1) | 4,979 | — | — | |||||||||
Unused commitments | 21 | — | 993 | |||||||||
General and administrative (including $3,192, $7,949 and $2,116, respectively, of stock-based compensation) | 19,451 | 16,139 | 15,092 | |||||||||
Total operating expenses | 85,709 | 31,657 | 70,189 | |||||||||
Income (loss) from operations | 50,355 | (3,543 | ) | (1,600 | ) | |||||||
Other income (expense): | ||||||||||||
Derivative loss | (30,754 | ) | — | — | ||||||||
Interest expense | (1,162 | ) | (195 | ) | (5,656 | ) | ||||||
Reorganization items, net | — | — | 8,808 | |||||||||
Other income | 290 | 158 | 1,108 | |||||||||
Total other income (expense) | (31,626 | ) | (37 | ) | 4,260 | |||||||
Income (loss) from operations before taxes | 18,729 | (3,580 | ) | 2,660 | ||||||||
Income tax benefit (expense) | — | — | — | |||||||||
Net income (loss) | $ | 18,729 | $ | (3,580 | ) | $ | 2,660 | |||||
Comprehensive income (loss) | $ | 18,729 | $ | (3,580 | ) | $ | 2,660 | |||||
Basic net income (loss) per common share | $ | 0.91 | $ | (0.18 | ) | $ | 0.05 | |||||
Diluted net income (loss) per common share | $ | 0.91 | $ | (0.18 | ) | $ | 0.05 | |||||
Basic weighted-average common shares outstanding | 20,471 | 20,369 | 49,559 | |||||||||
Diluted weighted-average common shares outstanding | 20,538 | 20,369 | 50,971 | |||||||||
Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which
allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury
stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q,
for a detailed calculation.
(1) The Company incurred impairment charges relating to non-core leases expiring and the standard amortization of unproved properties within the Wattenberg Field during the Current Successor Period.
Schedule 2: Statements of Cash Flows
(in thousands, unaudited)
Successor | Successor | Predecessor | ||||||||||
Three Months Ended June 30, 2018 | April 29, 2017 through June 30, 2017 | April 1, 2017 through April 28, 2017 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income (loss) | $ | 4,859 | $ | (3,580 | ) | $ | 96,936 | |||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||
Depreciation, depletion and amortization | 9,564 | 4,836 | 6,853 | |||||||||
Non-cash reorganization items | — | — | (101,501 | ) | ||||||||
Abandonment and impairment of unproved properties | 2,477 | — | — | |||||||||
Well abandonment costs and dry hole expense | — | 64 | 230 | |||||||||
Stock-based compensation | 2,184 | 7,949 | 391 | |||||||||
Amortization of deferred financing costs and debt premium | — | — | 374 | |||||||||
Derivative loss | 22,012 | — | — | |||||||||
Derivative cash settlements | (7,310 | ) | — | — | ||||||||
Other | — | 5 | (365 | ) | ||||||||
Changes in current assets and liabilities: | ||||||||||||
Accounts receivable | (4,618 | ) | 6,420 | (2,826 | ) | |||||||
Prepaid expenses and other assets | (2,467 | ) | 270 | 1,499 | ||||||||
Accounts payable and accrued liabilities | (323 | ) | (19,338 | ) | (36,972 | ) | ||||||
Settlement of asset retirement obligations | (132 | ) | (459 | ) | (155 | ) | ||||||
Net cash provided by (used in) operating activities | 26,246 | (3,833 | ) | (35,536 | ) | |||||||
Cash flows from investing activities: | ||||||||||||
Acquisition of oil and gas properties | (1,197 | ) | (4,982 | ) | (6 | ) | ||||||
Exploration and development of oil and gas properties | (53,818 | ) | (4,913 | ) | (1,698 | ) | ||||||
Proceeds from sale of oil and gas properties | — | — | — | |||||||||
Additions to property and equipment - non oil and gas | (177 | ) | (161 | ) | (253 | ) | ||||||
Net cash used in investing activities | (55,192 | ) | (10,056 | ) | (1,957 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Proceeds from credit facility | 45,000 | — | — | |||||||||
Payments to credit facility | — | — | (191,667 | ) | ||||||||
Proceeds from sale of common stock | — | — | 207,500 | |||||||||
Proceeds from exercise of stock options | 968 | — | — | |||||||||
Payment of employee tax withholdings in exchange for the return of common stock | (794 | ) | (2,080 | ) | (92 | ) | ||||||
Net cash provided by (used in) financing activities | 45,174 | (2,080 | ) | 15,741 | ||||||||
Net change in cash, cash equivalents and restricted cash | 16,228 | (15,969 | ) | (21,752 | ) | |||||||
Cash, cash equivalents and restricted cash: | ||||||||||||
Beginning of period | 5,840 | 68,406 | 90,158 | |||||||||
End of period | $ | 22,068 | $ | 52,437 | $ | 68,406 | ||||||
Successor | Predecessor | |||||||||||
Six Months Ended June 30, 2018 | April 29, 2017 through June 30, 2017 | January 1, 2017 through April 28, 2017 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income (loss) | $ | 18,729 | $ | (3,580 | ) | $ | 2,660 | |||||
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||||||||||||
Depreciation, depletion and amortization | 17,072 | 4,836 | 28,065 | |||||||||
Non-cash reorganization items | — | — | (44,160 | ) | ||||||||
Abandonment and impairment of unproved properties | 4,979 | — | — | |||||||||
Well abandonment costs and dry hole expense | — | 64 | 2,931 | |||||||||
Stock-based compensation | 3,192 | 7,949 | 2,116 | |||||||||
Amortization of deferred financing costs and debt premium | — | — | 374 | |||||||||
Derivative loss | 30,754 | — | — | |||||||||
Derivative cash settlements | (11,622 | ) | — | — | ||||||||
Other | 172 | 5 | 18 | |||||||||
Changes in current assets and liabilities: | ||||||||||||
Accounts receivable | (20,376 | ) | 6,420 | (6,640 | ) | |||||||
Prepaid expenses and other assets | 935 | 270 | 963 | |||||||||
Accounts payable and accrued liabilities | (889 | ) | (19,338 | ) | (5,880 | ) | ||||||
Settlement of asset retirement obligations | (797 | ) | (459 | ) | (331 | ) | ||||||
Net cash provided by (used in) operating activities | 42,149 | (3,833 | ) | (19,884 | ) | |||||||
Cash flows from investing activities: | ||||||||||||
Acquisition of oil and gas properties | (1,295 | ) | (4,982 | ) | (445 | ) | ||||||
Exploration and development of oil and gas properties | (91,482 | ) | (4,913 | ) | (5,123 | ) | ||||||
Proceeds from sale of oil and gas properties | 20 | — | — | |||||||||
Additions to property and equipment - non oil and gas | (280 | ) | (161 | ) | (454 | ) | ||||||
Net cash used in investing activities | (93,037 | ) | (10,056 | ) | (6,022 | ) | ||||||
Cash flows from financing activities: | ||||||||||||
Proceeds from credit facility | 60,000 | — | — | |||||||||
Payments to credit facility | — | — | (191,667 | ) | ||||||||
Proceeds from sale of common stock | — | — | 207,500 | |||||||||
Proceeds from exercise of stock options | 968 | — | — | |||||||||
Payment of employee tax withholdings in exchange for the return of common stock | (794 | ) | (2,080 | ) | (427 | ) | ||||||
Net cash provided by (used in) financing activities | 60,174 | (2,080 | ) | 15,406 | ||||||||
Net change in cash, cash equivalents and restricted cash | 9,286 | (15,969 | ) | (10,500 | ) | |||||||
Cash, cash equivalents and restricted cash: | ||||||||||||
Beginning of period | 12,782 | 68,406 | 78,906 | |||||||||
End of period | $ | 22,068 | $ | 52,437 | $ | 68,406 | ||||||
Schedule 3: Condensed Consolidated Balance Sheets
Successor | |||||||
June 30, 2018 | December 31, 2017 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 21,989 | $ | 12,711 | |||
Accounts receivable: | |||||||
Oil and gas sales | 38,830 | 28,549 | |||||
Joint interest and other | 13,926 | 3,831 | |||||
Prepaid expenses and other | 5,620 | 6,555 | |||||
Inventory of oilfield equipment | 1,434 | 1,019 | |||||
Derivative assets | 39 | 488 | |||||
Total current assets | 81,838 | 53,153 | |||||
Property and equipment (successful efforts method): | |||||||
Proved properties | 552,858 | 555,341 | |||||
Less: accumulated depreciation, depletion and amortization | (29,703 | ) | (17,032 | ) | |||
Total proved properties, net | 523,155 | 538,309 | |||||
Unproved properties | 179,735 | 183,843 | |||||
Wells in progress | 52,747 | 47,224 | |||||
Oil and gas properties held for sale, net of accumulated depreciation, depletion and amortization of $2,583 in 2018 | 82,328 | — | |||||
Other property and equipment, net of accumulated depreciation of $2,722 in 2018 and $2,224 in 2017 | 4,488 | 4,706 | |||||
Total property and equipment, net | 842,453 | 774,082 | |||||
Long-term derivative assets | — | 6 | |||||
Other noncurrent assets | 3,151 | 3,130 | |||||
Total assets | $ | 927,442 | $ | 830,371 | |||
LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and accrued expenses | $ | 50,242 | $ | 62,129 | |||
Oil and gas revenue distribution payable | 20,355 | 15,667 | |||||
Derivative liability | 28,416 | 11,423 | |||||
Total current liabilities | 99,013 | 89,219 | |||||
Long-term liabilities: | |||||||
Credit facility | 60,000 | — | |||||
Ad valorem taxes | 19,803 | 11,584 | |||||
Long-term derivative liability | 4,657 | 2,972 | |||||
Asset retirement obligations for oil and gas properties | 28,154 | 38,262 | |||||
Asset retirement obligations for oil and gas properties held for sale | 5,386 | — | |||||
Total liabilities | 217,013 | 142,037 | |||||
Commitments and contingencies | |||||||
Stockholders’ equity: | |||||||
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding | — | — | |||||
Common stock, $.01 par value, 225,000,000 shares authorized, 20,534,799 and 20,453,549 issued and outstanding in 2018 and 2017, respectively | 4,286 | 4,286 | |||||
Additional paid-in capital | 692,434 | 689,068 | |||||
Retained earnings (deficit) | 13,709 | (5,020 | ) | ||||
Total stockholders’ equity | 710,429 | 688,334 | |||||
Total liabilities and stockholders’ equity | $ | 927,442 | $ | 830,371 | |||
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, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Wellhead Volumes and Prices | |||||||||||||||
Crude Oil and Condensate Sales Volumes (Bbl/d) | |||||||||||||||
Rocky Mountains | 8,866 | 6,189 | 8,575 | 6,690 | |||||||||||
Mid-Continent | 1,600 | 1,845 | 1,633 | 1,889 | |||||||||||
Total | 10,466 | 8,034 | 10,208 | 8,579 | |||||||||||
Crude Oil and Condensate Realized Prices ($/Bbl) | |||||||||||||||
Rocky Mountains | $ | 63.05 | $ | 43.94 | $ | 60.15 | $ | 45.94 | |||||||
Mid-Continent | $ | 67.12 | $ | 47.69 | $ | 64.69 | $ | 49.65 | |||||||
Composite | $ | 63.67 | $ | 44.80 | $ | 60.87 | $ | 46.76 | |||||||
Composite (after derivatives) | $ | 55.99 | $ | 44.80 | $ | 54.47 | $ | 46.76 | |||||||
Natural Gas Liquids Sales Volumes (Bbl/d) | |||||||||||||||
Rocky Mountains | 3,126 | 3,046 | 2,772 | 3,167 | |||||||||||
Mid-Continent | 441 | 452 | 444 | 471 | |||||||||||
Total | 3,567 | 3,498 | 3,216 | 3,638 | |||||||||||
Natural Gas Liquids Realized Prices ($/Bbl) | |||||||||||||||
Rocky Mountains | $ | 17.06 | $ | 16.10 | $ | 19.34 | $ | 15.90 | |||||||
Mid-Continent | $ | 33.13 | $ | 20.84 | $ | 30.92 | $ | 23.32 | |||||||
Composite | $ | 19.05 | $ | 16.71 | $ | 20.94 | $ | 16.86 | |||||||
Composite (after derivatives) | $ | 19.05 | $ | 16.71 | $ | 20.94 | $ | 16.86 | |||||||
Natural Gas Sales Volumes (Mcf/d) | |||||||||||||||
Rocky Mountains | 18,511 | 20,144 | 18,385 | 20,786 | |||||||||||
Mid-Continent | 5,421 | 6,067 | 5,444 | 6,249 | |||||||||||
Total | 23,932 | 26,211 | 23,829 | 27,035 | |||||||||||
Natural Gas Realized Prices ($/Mcf) | |||||||||||||||
Rocky Mountains | $ | 1.96 | $ | 2.18 | $ | 2.29 | $ | 2.29 | |||||||
Mid-Continent | $ | 2.70 | $ | 3.06 | $ | 2.98 | $ | 3.15 | |||||||
Composite | $ | 2.13 | $ | 2.38 | $ | 2.45 | $ | 2.49 | |||||||
Composite (after derivatives) | $ | 2.13 | $ | 2.38 | $ | 2.50 | $ | 2.49 | |||||||
Crude Oil Equivalent Sales Volumes (Boe/d) | |||||||||||||||
Rocky Mountains | 15,077 | 12,592 | 14,412 | 13,322 | |||||||||||
Mid-Continent | 2,945 | 3,308 | 2,985 | 3,402 | |||||||||||
Total | 18,022 | 15,900 | 17,397 | 16,724 | |||||||||||
Crude Oil Equivalent Sales Prices ($/Boe) | |||||||||||||||
Rocky Mountains | $ | 43.02 | $ | 28.98 | $ | 42.43 | $ | 30.43 | |||||||
Mid-Continent | $ | 46.40 | $ | 35.05 | $ | 45.43 | $ | 36.60 | |||||||
Composite | $ | 43.57 | $ | 30.24 | $ | 42.95 | $ | 31.68 | |||||||
Composite (after derivatives) | $ | 39.11 | $ | 30.24 | $ | 39.26 | $ | 31.68 | |||||||
Total Sales Volumes (MBoe) | 1,640.0 | 1,446.9 | 3,148.8 | 3,026.9 | |||||||||||
Schedule 5: Per unit operating margins
(unaudited)
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||
2018 | 2017 | Percent Change | 2018 | 2017 | Percent Change | ||||||||||||||||
Production | |||||||||||||||||||||
Oil (MBbl) | 952 | 731 | 30 | % | 1,848 | 1,553 | 19 | % | |||||||||||||
Gas (MMcf) | 2,178 | 2,385 | (9 | )% | 4,313 | 4,893 | (12 | )% | |||||||||||||
NGL (MBbl) | 325 | 318 | 2 | % | 582 | 659 | (12 | )% | |||||||||||||
Equivalent (MBoe) | 1,640 | 1,447 | 13 | % | 3,149 | 3,027 | 4 | % | |||||||||||||
Realized pricing (before derivatives) | |||||||||||||||||||||
Oil ($/Bbl) | $ | 63.67 | $ | 44.80 | 42 | % | $ | 60.87 | $ | 46.76 | 30 | % | |||||||||
Gas ($/Mcf) | $ | 2.13 | $ | 2.38 | (11 | )% | $ | 2.45 | $ | 2.49 | (2 | )% | |||||||||
NGL ($/Bbl) | $ | 19.05 | $ | 16.71 | 14 | % | $ | 20.94 | $ | 16.86 | 24 | % | |||||||||
Equivalent ($/Boe) | $ | 43.57 | $ | 30.24 | 44 | % | $ | 42.95 | $ | 31.68 | 36 | % | |||||||||
Per Unit Costs ($/Boe) | |||||||||||||||||||||
Realized price equivalent (before derivatives) | $ | 43.57 | $ | 30.24 | 44 | % | $ | 42.95 | $ | 31.68 | 36 | % | |||||||||
Lease operating expense | 6.90 | 6.47 | 7 | % | 6.92 | 6.37 | 9 | % | |||||||||||||
Gathering, transportation and processing | 1.01 | — | — | % | 1.27 | — | — | % | |||||||||||||
Gas plant and midstream operating expense | 1.98 | 1.80 | 10 | % | 2.18 | 1.75 | 25 | % | |||||||||||||
Severance and ad valorem | 3.70 | 2.60 | 42 | % | 3.59 | 2.67 | 34 | % | |||||||||||||
Cash general and administrative | 4.72 | 7.46 | (37 | )% | 5.16 | 6.99 | (26 | )% | |||||||||||||
Total cash operating costs | $ | 18.31 | $ | 18.33 | — | % | $ | 19.12 | $ | 17.78 | 8 | % | |||||||||
Cash operating margin (before derivatives) | $ | 25.26 | $ | 11.91 | 112 | % | $ | 23.83 | $ | 13.90 | 71 | % | |||||||||
Derivative cash settlements | (4.46 | ) | — | — | % | (3.69 | ) | — | — | % | |||||||||||
Cash operating margin (after derivatives) | $ | 20.80 | $ | 11.91 | 75 | % | $ | 20.14 | $ | 13.90 | 45 | % | |||||||||
Non-cash items | |||||||||||||||||||||
Non-cash general and administrative | $ | 1.33 | $ | 5.76 | (77 | )% | $ | 1.01 | $ | 3.33 | (70 | )% | |||||||||
Schedule 6: Adjusted Net Income
(in thousands, except per share amounts, unaudited)
Adjusted net income is a supplemental non-GAAP financial measure that is used by management to present recurring profitability that is more comparable between periods by excluding items that 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 and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on a tax 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 to the non-GAAP financial measure of adjusted net income.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Net income (loss) | $ | 4,859 | $ | 93,356 | $ | 18,729 | $ | (920 | ) | |||||||
Adjustments to net income: | ||||||||||||||||
Derivative loss | 22,012 | — | 30,754 | — | ||||||||||||
Derivative cash settlements | (7,310 | ) | — | (11,622 | ) | — | ||||||||||
Abandonment and impairment of unproved properties | 2,477 | — | 4,979 | — | ||||||||||||
Exploratory dry hole expense | — | 294 | — | 2,995 | ||||||||||||
Unused commitments | — | — | 21 | 993 | ||||||||||||
Stock-based compensation (1) | 2,184 | 8,340 | 3,192 | 10,065 | ||||||||||||
Reorganization items, net | — | (97,811 | ) | — | (8,808 | ) | ||||||||||
Pre-petition advisory fees (1) | — | — | — | 683 | ||||||||||||
Post-petition restructuring fees (1) | — | 1,422 | — | 1,422 | ||||||||||||
Total adjustments before taxes | 19,363 | (87,755 | ) | 27,324 | 7,350 | |||||||||||
Income tax effect | — | — | — | — | ||||||||||||
Total adjustments after taxes | $ | 19,363 | $ | (87,755 | ) | $ | 27,324 | $ | 7,350 | |||||||
Adjusted net income | $ | 24,222 | $ | 5,601 | $ | 46,053 | $ | 6,430 | ||||||||
Adjusted net income per diluted share (2) | $ | 1.18 | $ | 0.27 | $ | 2.24 | $ | 0.32 | ||||||||
Diluted weighted-average common shares outstanding (2) | 20,603 | 20,369 | 20,538 | 20,369 | ||||||||||||
(1) Included as a portion of general and administrative expense in the consolidated statements of operations. | ||||||||||||||||
(2) For the three- and six-month periods ended June 30, 2017, the Company used the Successor's diluted weighted average share count to calculate adjusted net income per diluted share. | ||||||||||||||||
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. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes adjusted EBITDAX provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, 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 (loss) 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, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
Net income (loss) | $ | 4,859 | $ | 93,356 | $ | 18,729 | $ | (920 | ) | |||||||
Exploration | 221 | 651 | 250 | 4,058 | ||||||||||||
Depreciation, depletion and amortization | 9,564 | 11,689 | 17,072 | 32,901 | ||||||||||||
Abandonment and impairment of unproved properties | 2,477 | — | 4,979 | — | ||||||||||||
Unused commitments | — | — | 21 | 993 | ||||||||||||
Stock-based compensation (1) | 2,184 | 8,340 | 3,192 | 10,065 | ||||||||||||
Interest expense | 805 | 1,283 | 1,162 | 5,851 | ||||||||||||
Derivative loss | 22,012 | — | 30,754 | — | ||||||||||||
Derivative cash settlements | (7,310 | ) | — | (11,622 | ) | — | ||||||||||
Pre-petition advisory fees (1) | — | — | — | 683 | ||||||||||||
Post-petition restructuring fees (1) | — | 1,422 | — | 1,422 | ||||||||||||
Reorganization items, net | — | (97,811 | ) | — | (8,808 | ) | ||||||||||
Adjusted EBITDAX | $ | 34,812 | $ | 18,930 | $ | 64,537 | $ | 46,245 | ||||||||
(1) Included as a portion of general and administrative expense in the consolidated statements of operations. | ||||||||||||||||
Schedule 8: Cash G&A
(in thousands, unaudited)
Cash G&A is a supplemental non-GAAP financial measure that is used by management to provide only the cash portion of its G&A expense, which can be used to evaluate cost management and operating efficiency on a comparable basis from period to period. Management believes cash G&A provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines cash G&A as GAAP general and administrative expense exclusive of the Company's stock based compensation and one-time charges, such as severance costs and advisor fees. The Company refers to cash G&A to provide typical cash G&A costs that are planned for in a given period. Cash G&A is not a fully inclusive measure of general and administrative expense as determined by GAAP.
The following table presents a reconciliation of the GAAP financial measure of general and administrative expense to the non-GAAP financial measure of cash G&A.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2018 | 2017 | 2018 | 2017 | |||||||||||||
General and administrative | $ | 9,917 | $ | 19,137 | $ | 19,451 | $ | 31,231 | ||||||||
Stock-based compensation | (2,184 | ) | (8,340 | ) | (3,192 | ) | (10,065 | ) | ||||||||
Cash G&A | $ | 7,733 | $ | 10,797 | $ | 16,259 | $ | 21,166 | ||||||||
Post-petition restructuring fees | — | (1,422 | ) | — | (1,422 | ) | ||||||||||
Other non-recurring expense | — | (184 | ) | — | (184 | ) | ||||||||||
Recurring Cash G&A | $ | 7,733 | $ | 9,191 | $ | 16,259 | $ | 19,560 | ||||||||