ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Virginia | 23-1184320 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) |
Large accelerated filer | o | Accelerated filer | o | |
Non-accelerated filer | o | (Do not check if a smaller reporting company) | Smaller reporting company | ý |
Emerging growth company | o |
Part I - Financial Information | ||
Item | Page | |
1. | Financial Statements: | |
Condensed Consolidated Statements of Operations | ||
Condensed Consolidated Statements of Comprehensive Income | ||
Condensed Consolidated Balance Sheets | ||
Condensed Consolidated Statements of Cash Flows | ||
Notes to Condensed Consolidated Financial Statements: | ||
1. Nature of Operations | ||
2. Basis of Presentation | ||
3. Bankruptcy Proceedings and Emergence | ||
4. Accounts Receivable and Major Customers | ||
5. Derivative Instruments | ||
6. Property and Equipment | ||
7. Long-Term Debt | ||
8. Income Taxes | ||
9. Exit Activities | ||
10. Additional Balance Sheet Detail | ||
11. Fair Value Measurements | ||
12. Commitments and Contingencies | ||
13. Shareholders’ Equity | ||
14. Share-Based Compensation and Other Benefit Plans | ||
15. Interest Expense | ||
16. Earnings (Loss) per Share | ||
Forward-Looking Statements | ||
2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations: | |
Overview and Executive Summary | ||
Key Developments | ||
Financial Condition | ||
Results of Operations | ||
Critical Accounting Estimates | ||
3. | Quantitative and Qualitative Disclosures About Market Risk | |
4. | Controls and Procedures | |
Part II - Other Information | ||
1. | Legal Proceedings | |
1A. | Risk Factors | |
6. | Exhibits | |
Signatures |
Item 1. | Financial Statements |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended | Three Months Ended | Six Months Ended | Six Months Ended | ||||||||||||||
June 30, 2017 | June 30, 2016 | June 30, 2017 | June 30, 2016 | ||||||||||||||
Revenues | |||||||||||||||||
Crude oil | $ | 32,351 | $ | 32,019 | $ | 62,424 | $ | 57,985 | |||||||||
Natural gas liquids | 2,043 | 2,431 | 4,345 | 4,384 | |||||||||||||
Natural gas | 1,880 | 1,917 | 4,223 | 4,319 | |||||||||||||
(Loss) gain on sales of assets, net | (134 | ) | 910 | (69 | ) | 757 | |||||||||||
Other, net | 142 | (125 | ) | 345 | 204 | ||||||||||||
Total revenues | 36,282 | 37,152 | 71,268 | 67,649 | |||||||||||||
Operating expenses | |||||||||||||||||
Lease operating | 5,370 | 5,225 | 10,286 | 11,417 | |||||||||||||
Gathering, processing and transportation | 2,555 | 4,650 | 5,106 | 8,468 | |||||||||||||
Production and ad valorem taxes | 2,119 | 2,163 | 4,098 | 2,916 | |||||||||||||
General and administrative | 3,721 | 14,948 | 7,848 | 32,050 | |||||||||||||
Exploration | — | 4,320 | — | 5,647 | |||||||||||||
Depreciation, depletion and amortization | 11,076 | 11,746 | 20,886 | 25,558 | |||||||||||||
Total operating expenses | 24,841 | 43,052 | 48,224 | 86,056 | |||||||||||||
Operating income (loss) | 11,441 | (5,900 | ) | 23,044 | (18,407 | ) | |||||||||||
Other income (expense) | |||||||||||||||||
Interest expense | (1,274 | ) | (32,221 | ) | (1,812 | ) | (56,655 | ) | |||||||||
Derivatives | 11,061 | (21,759 | ) | 28,077 | (17,267 | ) | |||||||||||
Other, net | 101 | (6 | ) | 101 | (1,030 | ) | |||||||||||
Reorganization items, net | — | (7,380 | ) | — | (7,380 | ) | |||||||||||
Income (loss) before income taxes | 21,329 | (67,266 | ) | 49,410 | (100,739 | ) | |||||||||||
Income tax benefit (expense) | — | — | — | — | |||||||||||||
Net income (loss) | 21,329 | (67,266 | ) | 49,410 | (100,739 | ) | |||||||||||
Preferred stock dividends | — | (2,820 | ) | — | (5,972 | ) | |||||||||||
Net income (loss) attributable to common shareholders | $ | 21,329 | $ | (70,086 | ) | $ | 49,410 | $ | (106,711 | ) | |||||||
Net income (loss) per share: | |||||||||||||||||
Basic | $ | 1.42 | $ | (0.79 | ) | $ | 3.30 | $ | (1.22 | ) | |||||||
Diluted | $ | 1.42 | $ | (0.79 | ) | $ | 3.27 | $ | (1.22 | ) | |||||||
Weighted average shares outstanding – basic | 14,992 | 89,051 | 14,992 | 87,496 | |||||||||||||
Weighted average shares outstanding – diluted | 15,050 | 89,051 | 15,097 | 87,496 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended | Three Months Ended | Six Months Ended | Six Months Ended | ||||||||||||||
June 30, 2017 | June 30, 2016 | June 30, 2017 | June 30, 2016 | ||||||||||||||
Net income (loss) | $ | 21,329 | $ | (67,266 | ) | $ | 49,410 | $ | (100,739 | ) | |||||||
Other comprehensive loss: | |||||||||||||||||
Change in pension and postretirement obligations, net of tax $0 and $0 in 2016 | — | (11 | ) | — | (38 | ) | |||||||||||
— | (11 | ) | — | (38 | ) | ||||||||||||
Comprehensive income (loss) | $ | 21,329 | $ | (67,277 | ) | $ | 49,410 | $ | (100,777 | ) |
June 30, | December 31, | ||||||
2017 | 2016 | ||||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 10,105 | $ | 6,761 | |||
Accounts receivable, net of allowance for doubtful accounts | 42,807 | 29,095 | |||||
Derivative assets | 2,672 | — | |||||
Other current assets | 3,100 | 3,028 | |||||
Total current assets | 58,684 | 38,884 | |||||
Property and equipment, net (full cost method) | 272,461 | 247,473 | |||||
Derivative assets | 584 | — | |||||
Other assets | 5,423 | 5,329 | |||||
Total assets | $ | 337,152 | $ | 291,686 | |||
Liabilities and Shareholders’ Equity | |||||||
Current liabilities | |||||||
Accounts payable and accrued liabilities | $ | 59,263 | $ | 49,697 | |||
Derivative liabilities | — | 12,932 | |||||
Total current liabilities | 59,263 | 62,629 | |||||
Other liabilities | 4,103 | 4,072 | |||||
Derivative liabilities | 90 | 14,437 | |||||
Long-term debt | 37,000 | 25,000 | |||||
Commitments and contingencies (Note 12) | |||||||
Shareholders’ equity: | |||||||
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued | — | — | |||||
Common stock of $0.01 par value – 45,000,000 shares authorized; 14,992,018 shares issued as of June 30, 2017 and December 31, 2016 | 150 | 150 | |||||
Paid-in capital | 192,359 | 190,621 | |||||
Retained earnings (accumulated deficit) | 44,114 | (5,296 | ) | ||||
Accumulated other comprehensive income | 73 | 73 | |||||
Total shareholders’ equity | 236,696 | 185,548 | |||||
Total liabilities and shareholders’ equity | $ | 337,152 | $ | 291,686 |
Successor | Predecessor | |||||||
Six Months Ended | Six Months Ended | |||||||
June 30, 2017 | June 30, 2016 | |||||||
Cash flows from operating activities | ||||||||
Net income (loss) | $ | 49,410 | $ | (100,739 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 20,886 | 25,558 | ||||||
Accretion of firm transportation obligation | — | 317 | ||||||
Derivative contracts: | ||||||||
Net (gains) losses | (28,077 | ) | 17,267 | |||||
Cash settlements, net | (2,458 | ) | 46,952 | |||||
Loss (gain) on sales of assets, net | 69 | (757 | ) | |||||
Non-cash exploration expense | — | 1,713 | ||||||
Non-cash interest expense | 988 | 22,189 | ||||||
Share-based compensation (equity-classified) | 1,694 | 1,364 | ||||||
Other, net | 38 | (13 | ) | |||||
Changes in operating assets and liabilities, net | (6,533 | ) | 31,922 | |||||
Net cash provided by operating activities | 36,017 | 45,773 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (43,583 | ) | (14,575 | ) | ||||
Proceeds from sales of assets, net | — | 126 | ||||||
Other, net | — | 1,186 | ||||||
Net cash used in investing activities | (43,583 | ) | (13,263 | ) | ||||
Cash flows from financing activities | ||||||||
Proceeds from credit facility borrowings | 14,000 | — | ||||||
Repayment of credit facility borrowings | (2,000 | ) | (5,468 | ) | ||||
Debt issuance costs paid | (1,090 | ) | — | |||||
Proceeds received from rights offering, net | 55 | — | ||||||
Other, net | (55 | ) | — | |||||
Net cash provided by (used in) financing activities | 10,910 | (5,468 | ) | |||||
Net increase in cash and cash equivalents | 3,344 | 27,042 | ||||||
Cash and cash equivalents – beginning of period | 6,761 | 11,955 | ||||||
Cash and cash equivalents – end of period | $ | 10,105 | $ | 38,997 | ||||
Supplemental disclosures: | ||||||||
Cash paid for: | ||||||||
Interest, net of amounts capitalized | $ | 795 | $ | 2,765 | ||||
Income taxes, net of (refunds) | $ | — | $ | (35 | ) | |||
Reorganization items, net | $ | 901 | $ | 174 | ||||
Non-cash investing and financing activities: | ||||||||
Changes in accrued liabilities related to capital expenditures | $ | 2,322 | $ | (10,555 | ) | |||
Derivatives settled to reduce outstanding debt | $ | — | $ | 51,979 |
1. | Nature of Operations |
2. | Basis of Presentation |
3. | Bankruptcy Proceedings and Emergence |
June 30, | December 31, | |||||||
2017 | 2016 | |||||||
Customers | $ | 22,920 | $ | 20,489 | ||||
Joint interest partners | 21,598 | 7,238 | ||||||
Other 1 | 670 | 3,789 | ||||||
45,188 | 31,516 | |||||||
Less: Allowance for doubtful accounts | (2,381 | ) | (2,421 | ) | ||||
$ | 42,807 | $ | 29,095 |
5. | Derivative Instruments |
Average | Weighted | |||||||||||||||
Volume Per | Average | Fair Value | ||||||||||||||
Instrument | Day | Swap Price | Asset | Liability | ||||||||||||
Crude Oil: | (barrels) | ($/barrel) | ||||||||||||||
Third quarter 2017 | Swaps | 4,408 | $ | 48.59 | $ | 903,636 | $ | — | ||||||||
Fourth quarter 2017 | Swaps | 4,408 | $ | 48.59 | 591,129 | — | ||||||||||
First quarter 2018 | Swaps | 3,476 | $ | 49.10 | 419,761 | — | ||||||||||
Second quarter 2018 | Swaps | 3,476 | $ | 49.10 | 299,826 | — | ||||||||||
Third quarter 2018 | Swaps | 3,476 | $ | 49.10 | 193,534 | — | ||||||||||
Fourth quarter 2018 | Swaps | 3,476 | $ | 49.10 | 82,328 | — | ||||||||||
First quarter 2019 | Swaps | 2,916 | $ | 49.75 | 160,594 | — | ||||||||||
Second quarter 2019 | Swaps | 2,916 | $ | 49.75 | 88,824 | — | ||||||||||
Third quarter 2019 | Swaps | 2,916 | $ | 49.75 | 24,775 | — | ||||||||||
Fourth quarter 2019 | Swaps | 2,916 | $ | 49.75 | — | 56,550 | ||||||||||
Settlements to be received in subsequent period | 457,245 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months Ended | Three Months Ended | Six Months Ended | Six Months Ended | ||||||||||||||
June 30, 2017 | June 30, 2016 | June 30, 2017 | June 30, 2016 | ||||||||||||||
Derivative gains (losses) | $ | 11,061 | $ | (21,759 | ) | $ | 28,077 | $ | (17,267 | ) |
Fair Values as of | |||||||||||||||||
June 30, 2017 | December 31, 2016 | ||||||||||||||||
Derivative | Derivative | Derivative | Derivative | ||||||||||||||
Type | Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||||
Commodity contracts | Derivative assets/liabilities – current | $ | 2,672 | $ | — | $ | — | $ | 12,932 | ||||||||
Commodity contracts | Derivative assets/liabilities – noncurrent | 584 | 90 | — | 14,437 | ||||||||||||
$ | 3,256 | $ | 90 | $ | — | $ | 27,369 |
6. | Property and Equipment |
June 30, | December 31, | ||||||
2017 | 2016 | ||||||
Oil and gas properties: | |||||||
Proved | $ | 297,390 | $ | 251,083 | |||
Unproved | 4,122 | 4,719 | |||||
Total oil and gas properties | 301,512 | 255,802 | |||||
Other property and equipment | 3,696 | 3,575 | |||||
Total properties and equipment | 305,208 | 259,377 | |||||
Accumulated depreciation, depletion and amortization | (32,747 | ) | (11,904 | ) | |||
$ | 272,461 | $ | 247,473 |
7. | Long-Term Debt |
8. | Income Taxes |
9. | Exit Activities |
10. | Additional Balance Sheet Detail |
June 30, | December 31, | |||||||
2017 | 2016 | |||||||
Other current assets: | ||||||||
Tubular inventory and well materials | $ | 2,100 | $ | 2,125 | ||||
Prepaid expenses | 1,000 | 903 | ||||||
$ | 3,100 | $ | 3,028 | |||||
Other assets: | ||||||||
Deferred issuance costs of the Credit Facility | $ | 2,887 | $ | 2,785 | ||||
Other | 2,536 | 2,544 | ||||||
$ | 5,423 | $ | 5,329 | |||||
Accounts payable and accrued liabilities: | ||||||||
Trade accounts payable | $ | 10,166 | $ | 9,825 | ||||
Drilling costs | 4,802 | 2,479 | ||||||
Royalties and revenue – related | 33,231 | 26,116 | ||||||
Compensation – related | 1,739 | 2,557 | ||||||
Interest | 84 | 55 | ||||||
Reserve for bankruptcy claims | 3,922 | 3,922 | ||||||
Other | 5,319 | 4,743 | ||||||
$ | 59,263 | $ | 49,697 | |||||
Other liabilities: | ||||||||
Asset retirement obligations (“AROs”) | $ | 2,506 | $ | 2,459 | ||||
Defined benefit pension obligations | 972 | 1,025 | ||||||
Postretirement health care benefit obligations | 525 | 488 | ||||||
Other | 100 | 100 | ||||||
$ | 4,103 | $ | 4,072 |
11. | Fair Value Measurements |
June 30, 2017 | ||||||||||||||||
Fair Value | Fair Value Measurement Classification | |||||||||||||||
Description | Measurement | Level 1 | Level 2 | Level 3 | ||||||||||||
Assets: | ||||||||||||||||
Commodity derivative assets – current | $ | 2,672 | $ | — | $ | 2,672 | $ | — | ||||||||
Commodity derivative assets – noncurrent | 584 | — | 584 | — | ||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivative liabilities – current | $ | — | $ | — | $ | — | $ | — | ||||||||
Commodity derivative liabilities – noncurrent | (90 | ) | — | (90 | ) | — |
December 31, 2016 | ||||||||||||||||
Fair Value | Fair Value Measurement Classification | |||||||||||||||
Description | Measurement | Level 1 | Level 2 | Level 3 | ||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivative liabilities – current | $ | (12,932 | ) | $ | — | $ | (12,932 | ) | $ | — | ||||||
Commodity derivative liabilities – noncurrent | (14,437 | ) | — | (14,437 | ) | — |
• | Commodity derivatives: We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input. |
12. | Commitments and Contingencies |
December 31, | All Other | June 30, | |||||||||||||
2016 | Net Income | Changes 1 | 2017 | ||||||||||||
Common stock | $ | 150 | $ | — | $ | — | $ | 150 | |||||||
Paid-in capital | 190,621 | — | 1,738 | 192,359 | |||||||||||
Retained earnings (accumulated deficit) | (5,296 | ) | 49,410 | — | 44,114 | ||||||||||
Accumulated other comprehensive income | 73 | — | — | 73 | |||||||||||
$ | 185,548 | $ | 49,410 | $ | 1,738 | $ | 236,696 | ||||||||
14. | Share-Based Compensation and Other Benefit Plans |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months | Three Months | Six Months | Six Months | ||||||||||||||
Ended | Ended | Ended | Ended | ||||||||||||||
June 30, 2017 | June 30, 2016 | June 30, 2017 | June 30, 2016 | ||||||||||||||
Equity-classified awards 1 | $ | 848 | $ | 1,965 | $ | 1,694 | $ | 1,364 | |||||||||
Liability-classified awards | — | (12 | ) | — | (19 | ) | |||||||||||
$ | 848 | $ | 1,953 | $ | 1,694 | $ | 1,345 |
15. | Interest Expense |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months | Three Months | Six Months | Six Months | ||||||||||||||
Ended | Ended | Ended | Ended | ||||||||||||||
June 30, 2017 | June 30, 2016 | June 30, 2017 | June 30, 2016 | ||||||||||||||
Interest on borrowings and related fees 1 | $ | 515 | $ | 11,344 | $ | 905 | $ | 34,649 | |||||||||
Amortization of debt issuance costs 2 | 800 | 20,920 | 988 | 22,189 | |||||||||||||
Capitalized interest | (41 | ) | (43 | ) | (81 | ) | (183 | ) | |||||||||
$ | 1,274 | $ | 32,221 | $ | 1,812 | $ | 56,655 |
1 | Absent the bankruptcy proceedings and the corresponding suspension of the accrual of interest on unsecured debt, we would have recorded total contractual interest expense of $23.5 million and $46.9 million for the three and six months ended June 30, 2016, including $5.4 million and $10.9 million attributable to the 7.25% Senior Notes due 2019 (“2019 Senior Notes”) and $16.5 million and $32.9 million attributable to the 8.5% Senior Notes due 2020 (together with the 2019 Senior Notes, the “Senior Notes”). |
2 | Includes a $0.6 million write-off in June 2017 attributable to a change in the composition of financial institutions comprising the Credit Facility’s bank group (see Note 7). Includes $20.5 million related to the accelerated write-off of unamortized debt issuance costs associated with the RBL and Senior Notes for the six months ended June 30, 2016. |
16. | Earnings (Loss) per Share |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||
Three Months | Three Months | Six Months | Six Months | ||||||||||||||
Ended | Ended | Ended | Ended | ||||||||||||||
June 30, 2017 | June 30, 2016 | June 30, 2017 | June 30, 2016 | ||||||||||||||
Net income (loss) | $ | 21,329 | $ | (67,266 | ) | $ | 49,410 | $ | (100,739 | ) | |||||||
Less: Preferred stock dividends 1 | — | (2,820 | ) | — | (5,972 | ) | |||||||||||
Net income (loss) attributable to common shareholders – basic and diluted | $ | 21,329 | $ | (70,086 | ) | $ | 49,410 | $ | (106,711 | ) | |||||||
Weighted-average shares – basic | 14,992 | 89,051 | 14,992 | 87,496 | |||||||||||||
Effect of dilutive securities 2 | 58 | — | 105 | — | |||||||||||||
Weighted-average shares – diluted | 15,050 | 89,051 | 15,097 | 87,496 |
• | timing, costs and unknown risks related to the pending acquisition, our ability to realize expected benefits of the pending acquisition and the risk that the acquisition is not consummated as expected; |
• | potential adverse effects of the completed Chapter 11, or bankruptcy, proceedings on our liquidity, results of operations, business prospects, ability to retain financing and other risks and uncertainties related to our emergence from bankruptcy; |
• | our ability to satisfy our short-term and long-term liquidity needs, including our inability to generate sufficient cash flows from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs; |
• | negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties; |
• | our post-bankruptcy capital structure and the adoption of Fresh Start Accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting; |
• | plans, objectives, expectations and intentions contained in this report that are not historical; |
• | our ability to execute our business plan in volatile and depressed commodity price environments; |
• | the decline in and volatility of commodity prices for oil, natural gas liquids, or NGLs, and natural gas; |
• | our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production; |
• | our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; |
• | any impairments, write-downs or write-offs of our reserves or assets; |
• | the projected demand for and supply of oil, NGLs and natural gas; |
• | our ability to contract for drilling rigs, frac crews, supplies and services at reasonable costs; |
• | our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell our production at, or at reasonable discounts to, market prices; |
• | the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; |
• | drilling and operating risks; |
• | our ability to compete effectively against other oil and gas companies; |
• | leasehold terms expiring before production can be established and our ability to replace expired leases; |
• | environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance; |
• | the timing of receipt of necessary regulatory permits; |
• | the effect of commodity and financial derivative arrangements; |
• | the occurrence of unusual weather or operating conditions, including force majeure events; |
• | our ability to retain or attract senior management and key employees; |
• | counterparty risk related to the ability of these parties to meet their future obligations; |
• | compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; |
• | physical, electronic and cybersecurity breaches; |
• | uncertainties relating to general domestic and international economic and political conditions; |
• | the impact and costs associated with litigation or other legal matters; and |
• | other factors set forth in our periodic filings with the Securities and Exchange Commission, including the risks set forth in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2016. |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
• | Production increased approximately eight percent to 925 thousand barrels of oil equivalent, or MBOE, from 855 MBOE due primarily to the expansion of our drilling program partially offset by natural declines. |
• | Product revenues increased approximately five percent to $36.3 million from $34.7 million due to higher crude oil and NGL volumes partially offset by lower natural gas volumes and lower pricing for all commodity products. |
• | Production and lifting costs increased on an absolute basis to $7.9 million from $7.5 million, but declined on a per unit basis to $8.58 per BOE from $8.73 per BOE due primarily to the increase in production volume despite higher surface and other repair and maintenance costs. |
• | Production and severance taxes were relatively consistent on an absolute basis and declined to $2.29 per BOE from $2.31 per BOE on a per unit basis due to lower overall product pricing. |
• | General and administrative expenses declined on an absolute and per unit basis to $3.7 million and $4.03 per BOE from $4.1 million and $4.83 per BOE, respectively, due primarily to continuing efforts to manage our support cost structure and the effect of higher production volume. |
• | Our operating income was relatively consistent at $11.4 million for the three months ended June 30, 2017 compared to $11.6 million for the three months ended March 31, 2017. |
Successor | Successor | Predecessor | Successor | Predecessor | |||||||||||||||||
Three Months | Three Months | Three Months | Six Months | Six Months | |||||||||||||||||
Ended | Ended | Ended | Ended | Ended | |||||||||||||||||
June 30, | March 31, | June 30, | June 30, | June 30, | |||||||||||||||||
2017 | 2017 | 2016 | 2017 | 2016 | |||||||||||||||||
Total production (MBOE) | 925 | 855 | 1,156 | 1,779 | 2,551 | ||||||||||||||||
Average daily production (BOEPD) | 10,159 | 9,495 | 12,706 | 9,829 | 14,014 | ||||||||||||||||
Crude oil production (MBbl) | 685 | 608 | 791 | 1,293 | 1,764 | ||||||||||||||||
Crude oil production as a percent of total | 74 | % | 71 | % | 68 | % | 73 | % | 69 | % | |||||||||||
Product revenues | $ | 36,274 | $ | 34,718 | $ | 36,367 | $ | 70,992 | $ | 66,688 | |||||||||||
Crude oil revenues | $ | 32,351 | $ | 30,073 | $ | 32,019 | $ | 62,424 | $ | 57,985 | |||||||||||
Crude oil revenues as a percent of total | 89 | % | 87 | % | 88 | % | 88 | % | 87 | % | |||||||||||
Realized prices: | |||||||||||||||||||||
Crude oil ($ per Bbl) | $ | 47.25 | $ | 49.47 | $ | 40.48 | $ | 48.29 | $ | 32.87 | |||||||||||
NGLs ($ per Bbl) | $ | 15.59 | $ | 19.34 | $ | 13.01 | $ | 17.38 | $ | 10.95 | |||||||||||
Natural gas ($ per Mcf) | $ | 2.88 | $ | 3.06 | $ | 1.79 | $ | 2.98 | $ | 1.86 | |||||||||||
Aggregate ($ per BOE) | $ | 39.24 | $ | 40.63 | $ | 31.45 | $ | 39.90 | $ | 26.15 | |||||||||||
Prices adjusted for derivatives: | |||||||||||||||||||||
Crude oil ($ per Bbl) | $ | 46.57 | $ | 46.19 | $ | 61.20 | $ | 46.39 | $ | 59.49 | |||||||||||
Aggregate ($ per BOE) | $ | 38.73 | $ | 38.30 | $ | 45.63 | $ | 38.52 | $ | 44.55 | |||||||||||
Production and lifting costs ($/BOE) | |||||||||||||||||||||
Lease operating | $ | 5.81 | $ | 5.75 | $ | 4.52 | $ | 5.78 | $ | 4.48 | |||||||||||
Gathering, processing and transportation | $ | 2.77 | $ | 2.98 | $ | 4.02 | $ | 2.87 | $ | 3.32 | |||||||||||
Production and ad valorem taxes ($ per BOE) | $ | 2.29 | $ | 2.31 | $ | 1.87 | $ | 2.30 | $ | 1.14 | |||||||||||
General and administrative ($ per BOE) 1 | $ | 4.03 | $ | 4.83 | $ | 12.92 | $ | 4.41 | $ | 12.56 | |||||||||||
Depreciation, depletion and amortization ($ per BOE) 2 | $ | 11.99 | $ | 11.47 | $ | 10.15 | $ | 11.74 | $ | 10.02 | |||||||||||
Cash provided by operating activities 3 | $ | 26,875 | $ | 9,142 | $ | 17,242 | $ | 36,017 | $ | 45,773 | |||||||||||
Cash paid for capital expenditures | $ | 25,842 | $ | 17,741 | $ | 570 | $ | 43,583 | $ | 14,575 | |||||||||||
Cash and cash equivalents at end of period | $ | 3,132 | $ | 10,105 | $ | 38,997 | |||||||||||||||
Debt outstanding at end of period | $ | 30,000 | $ | 37,000 | $ | 1,187,553 | |||||||||||||||
Credit available under credit facility at end of period 4 | $ | 97,233 | $ | 162,245 | $ | — | |||||||||||||||
Net development wells drilled and completed | 3.0 | 3.6 | — | 6.6 | 2.5 |
1 | Includes combined amounts of $0.92, $0.97 and $8.02 per BOE for the Successor and Predecessor three-month periods described above and $0.94 and $8.02 per BOE for the Successor and Predecessor six-month periods described above, respectively, attributable to equity-classified share-based compensation, liability-classified share-based compensation and significant special charges, including strategic and financial advisory costs incurred prior to our bankruptcy filing, among others, as described in the discussion of “Results of Operations - General and Administrative Expenses” that follows. |
2 | Determined using the full cost method for the Successor periods and the successful efforts method for the Predecessor periods. |
3 | Includes cash paid for derivative settlements of $0.5 million, $2.0 million and $2.5 million for the three and six-month Successor periods described above and cash received from derivative settlements of $16.4 million and $47.0 million for the three and six-month Predecessor periods described above, respectively. |
4 | As of June 30, 2016, we were unable to draw on our pre-petition credit facility, or RBL. |
Borrowings Outstanding | ||||||||||
Weighted- Average | Maximum | Weighted- Average Rate | ||||||||
Three months ended June 30, 2017 | $ | 35,522 | $ | 37,000 | 4.2315 | % | ||||
Six months ended June 30, 2017 | $ | 31,235 | $ | 37,000 | 4.0433 | % |
Successor | Predecessor | 2017 vs. | ||||||||||
Six Months Ended | Six Months Ended | 2016 | ||||||||||
June 30, | June 30, | Favorable | ||||||||||
2017 | 2016 | (Unfavorable) | ||||||||||
Cash flows from operating activities | ||||||||||||
Operating cash flows, net of working capital changes | $ | 40,171 | $ | 21,391 | $ | 18,780 | ||||||
Crude oil derivative settlements (paid) received, net | (2,458 | ) | 46,952 | (49,410 | ) | |||||||
Interest payments, net of amounts capitalized | (795 | ) | (2,765 | ) | 1,970 | |||||||
Income tax refunds | — | 35 | (35 | ) | ||||||||
Strategic, financial and bankruptcy-related advisory fees and costs paid | (901 | ) | (18,067 | ) | 17,166 | |||||||
Restructuring and exit costs paid | — | (1,773 | ) | 1,773 | ||||||||
Net cash provided by operating activities | 36,017 | 45,773 | (9,756 | ) | ||||||||
Cash flows from investing activities | ||||||||||||
Capital expenditures | (43,583 | ) | (14,575 | ) | (29,008 | ) | ||||||
Proceeds from sales of assets, net | — | 126 | (126 | ) | ||||||||
Other, net | — | 1,186 | (1,186 | ) | ||||||||
Net cash used in investing activities | (43,583 | ) | (13,263 | ) | (30,320 | ) | ||||||
Cash flows from financing activities | ||||||||||||
Proceeds (repayments) from credit facility borrowings, net | 12,000 | (5,468 | ) | 17,468 | ||||||||
Debt issuance costs paid | (1,090 | ) | — | (1,090 | ) | |||||||
Proceeds received from rights offering, net | 55 | — | 55 | |||||||||
Other, net | (55 | ) | — | (55 | ) | |||||||
Net cash provided by (used in) financing activities | 10,910 | (5,468 | ) | 16,378 | ||||||||
Net increase in cash and cash equivalents | $ | 3,344 | $ | 27,042 | $ | (23,698 | ) |
Successor | Predecessor | |||||||
Six Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2017 | 2016 | |||||||
Drilling and completion | $ | 43,455 | $ | 3,784 | ||||
Lease acquisitions and other land-related costs | 1,402 | 54 | ||||||
Pipeline, gathering facilities and other equipment | (443 | ) | 363 | |||||
Geological, geophysical (seismic) and delay rental costs | 382 | (17 | ) | |||||
$ | 44,796 | $ | 4,184 |
Successor | Predecessor | |||||||
Six Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2017 | 2016 | |||||||
Total capital expenditures program costs (from above) | $ | 44,796 | $ | 4,184 | ||||
(Increase) decrease in accrued capitalized costs | (2,322 | ) | 10,555 | |||||
Less: | ||||||||
Exploration costs charged to operations 1: | ||||||||
Geological, geophysical (seismic) and delay rental costs | — | 17 | ||||||
Transfers from tubular inventory and well materials | (1,142 | ) | (528 | ) | ||||
Add: | ||||||||
Tubular inventory and well materials purchased in advance of drilling | 1,100 | 164 | ||||||
Capitalized internal labor 1 | 1,070 | — | ||||||
Capitalized interest | 81 | 183 | ||||||
Total cash paid for capital expenditures | $ | 43,583 | $ | 14,575 |
1 | Exploration costs and certain internal labor costs were charged to operations while we applied the successful efforts method in the 2016 Predecessor period and capitalized under the full cost method in the 2017 Successor period. |
June 30, | December 31, | |||||||
2017 | 2016 | |||||||
Credit Facility borrowings | $ | 37,000 | $ | 25,000 | ||||
Shareholders’ equity | 236,696 | 185,548 | ||||||
$ | 273,696 | $ | 210,548 | |||||
Debt as a % of total capitalization | 14 | % | 12 | % |
Total Production | Average Daily Production | ||||||||||||||||||
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||
Three Months | Three Months | 2017 vs. | Three Months | Three Months | 2017 vs. | ||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||
(Total volume) | (Volume per day) | ||||||||||||||||||
Crude oil (MBbl & BOPD) | 685 | 791 | (106 | ) | 7,524 | 8,692 | (1,168 | ) | |||||||||||
NGLs (MBbl and BOPD) | 131 | 187 | (56 | ) | 1,440 | 2,053 | (613 | ) | |||||||||||
Natural gas (MMcf and MMcfpd) | 653 | 1,070 | (417 | ) | 7 | 12 | (5 | ) | |||||||||||
Total (MBOE and BOEPD) | 925 | 1,156 | (232 | ) | 10,159 | 12,706 | (2,546 | ) | |||||||||||
Three Months | Three Months | 2017 vs. | Three Months | Three Months | 2017 vs. | ||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||
(MBOE) | (BOE per day) | ||||||||||||||||||
South Texas | 864 | 1,055 | (191 | ) | 9,498 | 11,595 | (2,098 | ) | |||||||||||
Mid-Continent and other 1 | 60 | 101 | (41 | ) | 662 | 1,110 | (448 | ) | |||||||||||
925 | 1,156 | (232 | ) | 10,159 | 12,706 | (2,546 | ) | ||||||||||||
Six Months | Six Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||
(Total volume) | (Volume per day) | ||||||||||||||||||
Crude oil (MBbl & BOPD) | 1,293 | 1,764 | (471 | ) | 7,142 | 9,692 | (2,550 | ) | |||||||||||
NGLs (MBbl and BOPD) | 250 | 400 | (150 | ) | 1,382 | 2,200 | (819 | ) | |||||||||||
Natural gas (MMcf and MMcfpd) | 1,418 | 2,318 | (900 | ) | 8 | 13 | (5 | ) | |||||||||||
Total (MBOE and BOEPD) | 1,779 | 2,551 | (772 | ) | 9,829 | 14,014 | (4,185 | ) | |||||||||||
Six Months | Six Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||
(MBOE) | (BOE per day) | ||||||||||||||||||
South Texas | 1,635 | 2,346 | (712 | ) | 9,032 | 12,892 | (3,860 | ) | |||||||||||
Mid-Continent and other 1 | 144 | 204 | (60 | ) | 797 | 1,122 | (325 | ) | |||||||||||
1,779 | 2,551 | (772 | ) | 9,829 | 14,014 | (4,185 | ) |
1 | Includes total production and average daily production of approximately 4 MBOE (50 BOEPD) and 9 MBOE (51 MBOE) attributable to our currently inactive Marcellus Shale wells for the three and six months ended June 30, 2016. |
Total Product Revenues | Product Revenues per Unit of Volume | ||||||||||||||||||||||||
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Three Months | Three Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
($ per unit of volume) | |||||||||||||||||||||||||
Crude oil | $ | 32,351 | $ | 32,019 | $ | 332 | $ | 47.25 | $ | 40.48 | $ | 6.77 | |||||||||||||
NGLs | 2,043 | 2,431 | (388 | ) | $ | 15.59 | $ | 13.01 | $ | 2.58 | |||||||||||||||
Natural gas | 1,880 | 1,917 | (37 | ) | $ | 2.88 | $ | 1.79 | $ | 1.09 | |||||||||||||||
Total | $ | 36,274 | $ | 36,367 | $ | (93 | ) | $ | 39.24 | $ | 31.45 | $ | 7.79 | ||||||||||||
Three Months | Three Months | 2017 vs. | Three Months | Three Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
($ per BOE) | |||||||||||||||||||||||||
South Texas | $ | 34,916 | $ | 34,646 | $ | 270 | $ | 40.40 | $ | 32.83 | $ | 7.57 | |||||||||||||
Mid-Continent and other 1 | 1,358 | 1,721 | (363 | ) | $ | 22.55 | $ | 17.04 | $ | 5.51 | |||||||||||||||
$ | 36,274 | $ | 36,367 | $ | (93 | ) | $ | 39.24 | $ | 31.45 | $ | 7.79 | |||||||||||||
Six Months | Six Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
($ per unit of volume) | |||||||||||||||||||||||||
Crude oil | $ | 62,424 | $ | 57,985 | $ | 4,439 | $ | 48.29 | $ | 32.87 | $ | 15.42 | |||||||||||||
NGLs | 4,345 | 4,384 | (39 | ) | $ | 17.38 | $ | 10.95 | $ | 6.43 | |||||||||||||||
Natural gas | 4,223 | 4,319 | (96 | ) | $ | 2.98 | $ | 1.86 | $ | 1.12 | |||||||||||||||
Total | $ | 70,992 | $ | 66,688 | $ | 4,304 | $ | 39.90 | $ | 26.15 | $ | 13.75 | |||||||||||||
Six Months | Six Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
($ per BOE) | |||||||||||||||||||||||||
South Texas | $ | 67,603 | $ | 63,401 | $ | 4,202 | $ | 41.35 | $ | 27.02 | $ | 14.33 | |||||||||||||
Mid-Continent and other 1 | 3,389 | 3,287 | 102 | $ | 23.49 | $ | 16.09 | $ | 7.40 | ||||||||||||||||
$ | 70,992 | $ | 66,688 | $ | 4,304 | $ | 39.90 | $ | 26.15 | $ | 13.75 |
1 | Includes revenues of less than $0.1 million and $0.1 million attributable to our currently inactive Marcellus Shale wells for the three and six months ended March 31, 2016. |
Three Months Ended June 30, 2017 vs. 2016 | Six Months Ended June 30, 2017 vs. 2016 | ||||||||||||||||||||||||
Revenue Variance Due to | Revenue Variance Due to | ||||||||||||||||||||||||
Volume | Price | Total | Volume | Price | Total | ||||||||||||||||||||
Crude oil | $ | (4,303 | ) | $ | 4,635 | 332 | $ | (15,495 | ) | $ | 19,934 | 4,439 | |||||||||||||
NGLs | (726 | ) | 338 | (388 | ) | (1,646 | ) | 1,607 | (39 | ) | |||||||||||||||
Natural gas | (748 | ) | 711 | (37 | ) | (1,676 | ) | 1,580 | (96 | ) | |||||||||||||||
$ | (5,777 | ) | $ | 5,684 | $ | (93 | ) | $ | (18,817 | ) | $ | 23,121 | $ | 4,304 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Crude oil revenues, as reported | $ | 32,351 | $ | 32,019 | $ | 332 | $ | 62,424 | $ | 57,985 | $ | 4,439 | |||||||||||||
Derivative settlements, net | (466 | ) | 16,393 | (16,859 | ) | (2,458 | ) | 46,952 | (49,410 | ) | |||||||||||||||
$ | 31,885 | $ | 48,412 | $ | (16,527 | ) | $ | 59,966 | $ | 104,937 | $ | (44,971 | ) | ||||||||||||
Crude oil prices per Bbl | $ | 47.25 | $ | 40.48 | $ | 6.77 | $ | 48.29 | $ | 32.87 | $ | 15.42 | |||||||||||||
Derivative settlements per Bbl | (0.68 | ) | 20.72 | (21.40 | ) | (1.90 | ) | 26.62 | (28.52 | ) | |||||||||||||||
$ | 46.57 | $ | 61.20 | $ | (14.63 | ) | $ | 46.39 | $ | 59.49 | $ | (13.10 | ) |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
(Loss) gain on sales of assets, net | $ | (134 | ) | $ | 910 | $ | (1,044 | ) | $ | (69 | ) | $ | 757 | $ | (826 | ) |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Other revenues, net | $ | 142 | $ | (125 | ) | $ | 267 | $ | 345 | $ | 204 | $ | 141 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Lease operating | $ | 5,370 | $ | 5,225 | $ | (145 | ) | $ | 10,286 | $ | 11,417 | $ | 1,131 | ||||||||||||
Per unit of production ($/BOE) | $ | 5.81 | $ | 4.52 | $ | (1.29 | ) | $ | 5.78 | $ | 4.48 | $ | (1.30 | ) | |||||||||||
% Change per unit of production | (29 | )% | (29 | )% |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Gathering, processing and transportation | $ | 2,555 | $ | 4,650 | $ | 2,095 | $ | 5,106 | $ | 8,468 | $ | 3,362 | |||||||||||||
Per unit of production ($/BOE) | $ | 2.77 | $ | 4.02 | $ | 1.25 | $ | 2.87 | $ | 3.32 | $ | 0.45 | |||||||||||||
% Change per unit of production | 31 | % | 14 | % |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Production and ad valorem taxes | |||||||||||||||||||||||||
Production/severance taxes | $ | 1,698 | $ | 1,184 | $ | (514 | ) | $ | 3,353 | $ | 1,380 | $ | (1,973 | ) | |||||||||||
Ad valorem taxes | 421 | 979 | 558 | 745 | 1,536 | 791 | |||||||||||||||||||
$ | 2,119 | $ | 2,163 | $ | 44 | $ | 4,098 | $ | 2,916 | $ | (1,182 | ) | |||||||||||||
Per unit production ($/BOE) | $ | 2.29 | $ | 1.87 | $ | (0.42 | ) | $ | 2.30 | $ | 1.14 | $ | (1.16 | ) | |||||||||||
Production/severance tax rate as a percent of product revenue | 4.7 | % | 3.3 | % | 4.7 | % | 2.1 | % |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Primary G&A | $ | 2,873 | $ | 5,671 | $ | 2,798 | $ | 6,174 | $ | 11,570 | $ | 5,396 | |||||||||||||
Share-based compensation | |||||||||||||||||||||||||
Liability-classified | — | (12 | ) | (12 | ) | — | (19 | ) | (19 | ) | |||||||||||||||
Equity-classified 1 | 848 | 1,965 | 1,117 | 1,694 | 1,364 | (330 | ) | ||||||||||||||||||
Significant special charges: | |||||||||||||||||||||||||
Strategic and financial advisory costs | — | 6,973 | 6,973 | — | 18,036 | 18,036 | |||||||||||||||||||
Restructuring expenses | — | 351 | 351 | (20 | ) | 1,099 | 1,119 | ||||||||||||||||||
Total G&A | $ | 3,721 | $ | 14,948 | $ | 11,227 | $ | 7,848 | $ | 32,050 | $ | 24,202 | |||||||||||||
Per unit of production ($/BOE) | $ | 4.03 | $ | 12.92 | $ | 8.89 | $ | 4.41 | $ | 12.56 | $ | 8.15 | |||||||||||||
Per unit of production excluding all share-based compensation and other significant special charges identified above ($/BOE) | $ | 3.11 | $ | 4.90 | $ | 1.79 | $ | 3.47 | $ | 4.54 | $ | 1.07 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Unproved leasehold amortization | $ | — | $ | 857 | $ | 857 | $ | — | $ | 1,713 | $ | 1,713 | |||||||||||||
Drilling rig termination charges | — | 936 | 936 | — | 1,426 | 1,426 | |||||||||||||||||||
Drilling carry commitment | — | 1,964 | 1,964 | — | 1,964 | 1,964 | |||||||||||||||||||
Geological and geophysical costs | — | — | — | — | 33 | 33 | |||||||||||||||||||
Other, primarily delay rentals | — | 563 | 563 | — | 511 | 511 | |||||||||||||||||||
$ | — | $ | 4,320 | $ | 4,320 | $ | — | $ | 5,647 | $ | 5,647 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
DD&A expense | $ | 11,076 | $ | 11,746 | $ | 670 | $ | 20,886 | $ | 25,558 | $ | 4,672 | |||||||||||||
DD&A Rate ($/BOE) | $ | 11.99 | $ | 10.15 | $ | (1.84 | ) | $ | 11.74 | $ | 10.02 | $ | (1.72 | ) |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Interest on borrowings and related fees | $ | 515 | $ | 11,344 | $ | 10,829 | $ | 905 | $ | 34,649 | $ | 33,744 | |||||||||||||
Amortization of debt issuance costs | 800 | 20,920 | 20,120 | 988 | 22,189 | 21,201 | |||||||||||||||||||
Capitalized interest | (41 | ) | (43 | ) | (2 | ) | (81 | ) | (183 | ) | (102 | ) | |||||||||||||
$ | 1,274 | $ | 32,221 | $ | 30,947 | $ | 1,812 | $ | 56,655 | $ | 54,843 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Crude oil derivative gains (losses) | $ | 11,061 | $ | (21,759 | ) | $ | 32,820 | $ | 28,077 | $ | (17,267 | ) | $ | 45,344 | |||||||||||
Natural gas derivative gains (losses) | — | — | — | — | — | — | |||||||||||||||||||
$ | 11,061 | $ | (21,759 | ) | $ | 32,820 | $ | 28,077 | $ | (17,267 | ) | $ | 45,344 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Other, net | $ | 101 | $ | (6 | ) | $ | 107 | $ | 101 | $ | (1,030 | ) | $ | 1,131 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Legal and professional fees and expenses | $ | — | $ | 7,237 | $ | 7,237 | $ | — | $ | 7,237 | $ | 7,237 | |||||||||||||
Debtor-in-Possession credit facility costs and commitment fees | — | 143 | 143 | — | 143 | 143 | |||||||||||||||||||
$ | — | $ | 7,380 | $ | 7,380 | $ | — | $ | 7,380 | $ | 7,380 |
Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||
Three Months | Three Months | 2017 vs. | Six Months | Six Months | 2017 vs. | ||||||||||||||||||||
Ended | Ended | 2016 | Ended | Ended | 2016 | ||||||||||||||||||||
June 30, | June 30, | Favorable | June 30, | June 30, | Favorable | ||||||||||||||||||||
2017 | 2016 | (Unfavorable) | 2017 | 2016 | (Unfavorable) | ||||||||||||||||||||
Income tax benefit (expense) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
Effective tax rate | — | % | — | % | — | % | — | % |
Item 3. | Quantitative and Qualitative Disclosures About Market Risk |
Item 4. | Controls and Procedures |
Item 1. | Legal Proceedings |
Item 1A. | Risk Factors |
Item 6. | Exhibits |
(10.1) | Master Assignment, Agreement and Amendment No. 2 to Credit Agreement dated as of June 27, 2017 among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the subsidiaries of the borrower party thereto, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on June 30, 2017). |
(31.1) * | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
(31.2) * | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
(32.1) † | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
(32.2) † | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
(101.INS) * | XBRL Instance Document |
(101.SCH) * | XBRL Taxonomy Extension Schema Document |
(101.CAL) * | XBRL Taxonomy Extension Calculation Linkbase Document |
(101.DEF) * | XBRL Taxonomy Extension Definition Linkbase Document |
(101.LAB) * | XBRL Taxonomy Extension Label Linkbase Document |
(101.PRE) * | XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith. |
† | Furnished herewith. |
PENN VIRGINIA CORPORATION | |||
(Registrant) | |||
By: | /s/ STEVEN A. HARTMAN | August 9, 2017 | |
Steven A. Hartman | |||
Senior Vice President, Chief Financial Officer and Treasurer | |||
By: | /s/ TAMMY L. HINKLE | August 9, 2017 | |
Tammy L. Hinkle | |||
Vice President and Controller | |||
(Principal Accounting Officer) |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and |
(d) | Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. |
/s/ JOHN A. BROOKS | |
John A. Brooks | |
Interim Principal Executive Officer |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and |
(d) | Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting. |
/s/ STEVEN A. HARTMAN | |
Steven A. Hartman | |
Senior Vice President, Chief Financial Officer and Treasurer |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ JOHN A. BROOKS | |
John A. Brooks | |
Interim Principal Executive Officer |
1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ STEVEN A. HARTMAN | |
Steven A. Hartman | |
Senior Vice President, Chief Financial Officer and Treasurer |
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Document and Entity Information - shares |
6 Months Ended | |
---|---|---|
Jun. 30, 2017 |
Aug. 04, 2017 |
|
Document Documentand Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2017 | |
Document Fiscal Year Focus | 2017 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | PVAC | |
Entity Registrant Name | PENN VIRGINIA CORP | |
Entity Central Index Key | 0000077159 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Smaller Reporting Company | |
Entity Common Stock, Shares Outstanding | 14,992,018 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Net income (loss) | $ 49,410 | |||
Successor [Member] | ||||
Net income (loss) | $ 21,329 | 49,410 | ||
Other comprehensive loss: | ||||
Change in pension and postretirement obligations, net of tax $0 and $0 in 2016 | 0 | 0 | ||
Total Other Comprehensive Income (Loss), Net of Tax | 0 | 0 | ||
Comprehensive income (loss) | $ 21,329 | $ 49,410 | ||
Predecessor [Member] | ||||
Net income (loss) | $ (67,266) | $ (100,739) | ||
Other comprehensive loss: | ||||
Change in pension and postretirement obligations, net of tax $0 and $0 in 2016 | (11) | (38) | ||
Total Other Comprehensive Income (Loss), Net of Tax | (11) | (38) | ||
Comprehensive income (loss) | $ (67,277) | $ (100,777) |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Successor [Member] | ||||
Change in pension and postretirement obligations, net of tax | $ 0 | $ 0 | ||
Predecessor [Member] | ||||
Change in pension and postretirement obligations, net of tax | $ (11) | $ (38) |
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Statement of Financial Position [Abstract] | ||
Preferred stock, par value | $ 0.01 | $ 100 |
Preferred stock, shares authorized | 5,000,000 | 5,000,000 |
Schedule of Stockholders' Equity [Line Items] | ||
Preferred stock, redemption value per share (in dollars per share) | $ 0 | $ 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 45,000,000 | 45,000,000 |
Common stock, shares issued | 14,992,018 | 14,992,018 |
Series A Preferred Stock | ||
Schedule of Stockholders' Equity [Line Items] | ||
Preferred stock, issued | 0 | 0 |
Series B Preferred Stock | ||
Schedule of Stockholders' Equity [Line Items] | ||
Preferred stock, issued | 0 | 0 |
Nature of Operations |
6 Months Ended |
---|---|
Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Nature of Operations | Nature of Operations Penn Virginia Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. Our operations are substantially concentrated with over 90 percent of our production, revenues and capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash. In August 2016, we terminated our remaining operations in the Marcellus Shale in Pennsylvania and recently completed remediation activities at the sites of our former wells in that region. We are currently awaiting releases from state environmental authorities to finalize our exit activities. |
Basis of Presentation |
6 Months Ended |
---|---|
Jun. 30, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2016. Operating results for the six months ended June 30, 2017, are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. Comparability of Financial Statements to Prior Periods We adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes through that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. In connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s creditors. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. In addition, we adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations, financial position and cash flows for the Successor periods will be substantially different from our historic trends. We have recasted amounts for equity-classified share-based compensation recognized as a component of “General and administrative” expenses from the amounts originally reported for the three and six months ended June 30, 2016 to correct for an immaterial error identified by management and disclosed in our Quarterly Report on Form 10-Q for the period ended September 30, 2016. Previously reported expenses associated with this matter, as well as our operating losses and net losses, were increased by $5.3 million for each of the three and six-month periods ended June 30, 2016. Our net loss per basic and diluted share increased by $0.06 for each of the three and six-month periods ended June 30, 2016. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. Subsequent Events In July 2017, we entered into a definitive agreement to acquire Eagle Ford properties located primarily in Lavaca County, Texas for $205 million in cash, subject to customary purchase price adjustments, from Devon Energy Corporation. The acquisition has an effective date of March 1, 2017 and is expected to close in September 2017, subject to customary closing conditions. With the exception of the pending acquisition, management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto. Recently Issued Accounting Pronouncements In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather “interest and other costs” associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of “General and administrative” expenses. The total cost associated with these plans is generally less than $0.1 million on an annual basis and is therefore not material. We will adopt ASU 2017–07 in January 2018. In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are currently in the early stages of evaluating the requirements and the period for which we will adopt the standard. In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 12, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water disposal revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources, which we do not believe are significant. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in January 2018 using the cumulative effect transition method. |
Bankruptcy Proceeding Bankruptcy Proceedings |
6 Months Ended |
---|---|
Jun. 30, 2017 | |
Reorganizations [Abstract] | |
Reorganization under Chapter 11 of US Bankruptcy Code Disclosure [Text Block] | Bankruptcy Proceedings and Emergence On May 12, 2016 (the “Petition Date”), we and eight of our subsidiaries filed voluntary petitions (In re Penn Virginia Corporation, et al., Case No. 16-32395) seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (the “Bankruptcy Court”). On August 11, 2016 (the “Confirmation Date”), the Bankruptcy Court confirmed our Second Amended Joint Chapter 11 Plan of Reorganization of Penn Virginia Corporation and its Debtor Affiliates (the “Plan”), and we subsequently emerged from bankruptcy on September 12, 2016 (the “Effective Date”). While our emergence from bankruptcy is effectively complete, certain administrative and claims resolution activities will continue under the authority of the Bankruptcy Court until complete. As of August 4, 2017, certain claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of Successor common stock have been allocated, certain of these matters must be settled with cash payments. As of June 30, 2017, we had $3.9 million reserved for outstanding claims to be potentially settled in cash. This reserve is included as a component of “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. |
Accounts Receivable and Major Customers |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Receivables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Receivable and Major Customers | Accounts Receivable and Major Customers The following table summarizes our accounts receivable by type as of the dates presented:
_______________________ 1 Includes amounts owed to us from joint venture partners for acquisitions in prior periods, severance tax refunds approved by state taxing authorities to be returned to us and other miscellaneous non-operating items. For the six months ended June 30, 2017, one customer accounted for $64.6 million, or approximately 91%, of our consolidated product revenues. As of June 30, 2017, $19.2 million, or approximately 84%, of our consolidated accounts receivable from customers was related to this customer. For the six months ended June 30, 2016, three customers accounted for $62.2 million, or approximately 93%, of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2016 were $32.1 million, $16.2 million and $13.9 million, or approximately 48%, 24% and 21% of the consolidated total, respectively. As of December 31, 2016, $16.7 million, or approximately 81%, of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers. |
Derivative Instruments |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Instruments | Derivative Instruments We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility. Our derivative instruments are not formally designated as hedges in the context of GAAP. We typically utilize collars and swaps, which are placed with financial institutions that we believe are acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements. The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas and closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position. We terminated all of our pre-petition derivative contracts from March 2016 through May 2016 for $63.0 million and reduced amounts outstanding under the pre-petition credit agreement (the “RBL”) by $52.0 million. In connection with these transactions, the counterparties to the derivative contracts, which were also affiliates of lenders under the RBL, transferred the cash proceeds that were used for RBL repayments directly to the administrative agent under the RBL. Accordingly, all of these RBL repayments have been presented as non-cash financing activities on our Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2016. In May 2016, we entered into a series of new commodity derivative contracts. Accordingly, we hedged a substantial portion of our future crude oil production through the end of 2019 at a weighted-average price of approximately $49.07 per barrel. We are currently unhedged with respect to NGL and natural gas production. The following table sets forth our commodity derivative positions as of June 30, 2017:
Financial Statement Impact of Derivatives The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:
The effects of derivative gains and (losses) and cash settlements (except for those cash settlements attributable to the aforementioned termination transactions) are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded in the “Derivative contracts” section of our Condensed Consolidated Statements of Cash Flows under “Net (gains) losses” and “Cash settlements, net.” The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:
As of June 30, 2017, we reported commodity derivative asset of $3.2 million. The contracts associated with this position are with two counterparties, both of which are investment grade financial institutions. This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties. |
Property and Equipment |
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Jun. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property and Equipment | Property and Equipment The following table summarizes our property and equipment as of the dates presented:
Unproved property costs of $4.1 million and $4.7 million have been excluded from amortization as of June 30, 2017 and December 31, 2016, respectively. We transferred $2.0 million of undeveloped leasehold costs associated with acreage unlikely to be drilled or associated with proved undeveloped reserves, including capitalized interest, from unproved properties to the full cost pool during the six months ended June 30, 2017. We capitalized internal costs of $1.1 million and interest of $0.1 million during the six months ended June 30, 2017 in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $11.74 and $10.02 for the six months ended June 30, 2017 and 2016, respectively. |
Long-Term Debt |
6 Months Ended |
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Jun. 30, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt Credit Facility On the Effective Date upon our emergence from bankruptcy, we entered into our credit agreement (the “Credit Facility”). The Credit Facility currently provides for a $200 million revolving commitment and borrowing base and a $5 million sublimit for the issuance of letters of credit. In June 2017, the borrowing base was redetermined from $128 million to $200 million pursuant to an amendment to the Credit Facility (the “Amendment”). In connection with the Amendment, we paid and capitalized issue costs of $1.1 million and wrote-off $0.6 million of previously capitalized issue costs due to a change in the composition of financial institutions comprising the Credit Facility bank group. The availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base. The borrowing base under the Credit Facility is generally redetermined semi-annually in April and October of each year. Additionally, the Credit Facility lenders may, at their discretion, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us to pay expenses associated with our bankruptcy proceedings and for general corporate purposes including working capital. The Credit Facility matures in September 2020. We had outstanding borrowings of $37 million and $25 million under the Credit Facility as of June 30, 2017 and December 31, 2016, respectively. We also had $0.8 million in letters of credit outstanding as of June 30, 2017 and December 31, 2016. The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 2.00% to 3.00%, determined based on the average availability under the Credit Facility or (b) a customary London interbank offered rate (“LIBOR”) plus an applicable margin ranging from 3.00% to 4.00%, determined based on the average availability under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on LIBOR borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. As of June 30, 2017, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 4.3289%. Unused commitment fees are charged at a rate of 0.50%. The Credit Facility is guaranteed by us and all of our subsidiaries (the “Guarantor Subsidiaries”). The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company has no material independent assets or operations. There are no significant restrictions on the ability of the parent company or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our assets. The Credit Facility requires us to maintain (1) a minimum interest coverage ratio (adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses as defined in the Credit Facility (“EBITDAX”) to adjusted interest expense), measured as of the last day of each fiscal quarter, of 3.00 to 1.00, (2) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00, and (3) a maximum leverage ratio (consolidated indebtedness to EBITDAX), measured as of the last day of each fiscal quarter, initially of 4.00 to 1.00, decreasing on December 31, 2017 to 3.75 to 1.00 and on March 31, 2018 and thereafter to 3.50 to 1.00. The Credit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. The Credit Facility contains customary events of default and remedies for credit facilities of this nature. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility. As of June 30, 2017, we were in compliance with all of these covenants. |
Income Taxes |
6 Months Ended |
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Jun. 30, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes We recognized a federal and state income tax expense for the six months ended June 30, 2017 at the blended rate of 35.52%; however, the federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets. We recognized a federal income tax benefit for the six months ended June 30, 2016 at the statutory rate of 35% which was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of cumulative losses. We received a state income tax refund of less than $0.1 million during the six months ended June 30, 2016. We have evaluated the impact of the reorganization, including the change in control, resulting from our emergence from bankruptcy. From an income tax perspective, the most significant impact is attributable to our carryover tax attributes associated with our net operating losses (“NOLs”). We believe that the Successor will be able to fully absorb the cancellation of debt income realized by the Predecessor in connection with the reorganization with its adjusted NOL carryovers. The amount of the remaining NOL carryovers and the tax basis of our properties will be limited under Section 382 of the Internal Revenue Code due to the change in control that occurred upon our emergence from bankruptcy on the Effective Date. As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in the Fresh Start Accounting process, the Successor is in a net deferred tax asset position. We have determined that it is more likely than not that we will not realize future income tax benefits from the additional tax basis and our remaining NOL carryovers. Accordingly, we have provided for a full valuation allowance of the underlying deferred tax assets. |
Exit Activities |
6 Months Ended |
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Jun. 30, 2017 | |
Restructuring and Related Activities [Abstract] | |
Exit Activities | Exit Activities Prior to the Effective Date, the Predecessor committed to a number of actions, or exit activities, the most significant of which are described below. Reductions in Force In connection with efforts to reduce our administrative costs, we took certain actions to reduce our total employee headcount. In 2016, we reduced our total employee headcount by 53 employees including 28 of whom were terminated in the six months ended June 30, 2016. We incurred charges of $1.1 million in connection with this action and paid a total of $0.7 million in severance and termination benefits during the six months ended June 30, 2016. We recognized an immaterial credit adjustment to the remaining obligation of less than $0.1 million during the period ended June 30, 2017. There were no payments under these obligations during the six months ended June 30, 2017. The costs associated with these reduction-in-force actions are included as a component of our “General and administrative” expenses in our Condensed Consolidated Statements of Operations. The related obligation is included in “Accounts payable and accrued liabilities” on our Condensed Consolidated Balance Sheet. Drilling Rig Termination In connection with the suspension of our 2016 drilling program in the Eagle Ford, we terminated a drilling rig contract and incurred $1.3 million in early termination charges during the six months ended June 30, 2016. As this obligation represented a pre-petition liability of the Predecessor, it was discharged in connection with our emergence from bankruptcy. The vendor recovered a portion of the amount in the form of Successor common stock. Firm Transportation Obligation We had a contractual obligation for certain firm transportation capacity in the Appalachian region that was scheduled to expire in 2022 and, as a result of the sale of our natural gas assets in this region in 2012, we no longer had production available to satisfy this commitment. We originally recognized a liability in 2012 representing this obligation for the estimated discounted future net cash outflows over the remaining term of the contract. The accretion of the obligation through the Petition Date, net of any recoveries from periodic sales of our contractual capacity, was charged as an offset to Other revenue. During the six months ended June 30, 2016, we paid a total of $1.1 million and recognized accretion expense of $0.3 million attributable to the underlying obligation. In connection with our emergence from bankruptcy, we rejected the underlying contract. |
Additional Balance Sheet Detail |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional Balance Sheet Detail | Additional Balance Sheet Detail The following table summarizes components of selected balance sheet accounts as of the dates presented:
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Fair Value Measurements |
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Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Fair Value Measurements We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and our Credit Facility borrowings. As of June 30, 2017, the carrying values of all of these financial instruments approximated fair value. Recurring Fair Value Measurements Certain financial assets and liabilities are measured at fair value on a recurring basis on our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented:
Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the six months ended June 30, 2017 and 2016. We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:
Non-Recurring Fair Value Measurements The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties. The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method, which we have applied since the Effective Date, we apply a ceiling test determination utilizing prescribed procedures. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements. |
Commitments and Contingencies |
6 Months Ended |
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Jun. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Gathering and Intermediate Transportation Commitments We have long-term agreements with Republic Midstream, LLC (“Republic Midstream”) and Republic Midstream Marketing, LLC (“Republic Marketing” and, together with Republic Midstream, collectively, “Republic”) to provide for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region as well as volume capacity support for certain downstream interstate pipeline transportation. Republic is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment of 8,000 gross barrels of oil per day to Republic through 2031 under the gathering agreement. Under the marketing agreement, we have a 10-year commitment to sell 8,000 barrels per day of crude oil to Republic, or any third party, utilizing Republic Marketing’s capacity on a certain downstream interstate pipeline. Excluding the potential impact of the effects of price escalation from commodity price changes, the minimum fee requirements under the Amended Agreements are as follows: $5.0 million for the remainder of 2017, $10.4 million for 2018, $11.7 million for 2019, $13.0 million for 2020 through 2025, $7.4 million for 2026, $3.8 million for 2027 through 2030 and $2.2 million for 2031. Drilling Commitments As of June 30, 2017, we had contractual commitments for two drilling rigs. The first rig is subject to a six-month commitment through September 2017. The second rig, which completed a seven-well commitment in July 2017, was extended for a six-month commitment that ends in January 2018. We have approximately $4.5 million of remaining obligations associated with these commitments. Legal and Regulatory We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of June 30, 2017, we continue to maintain a $0.1 million reserve for a litigation matter. As of June 30, 2017, we also had AROs of approximately $2.5 million attributable to the plugging of abandoned wells. |
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Shareholders' Equity | Shareholders’ Equity The following tables summarize the components of our shareholders’ equity and the changes therein as of and for six months ended June 30, 2017:
_______________________ 1 Includes equity-classified share-based compensation of $1.7 million and $0.1 million from the receipt in May 2017 of proceeds attributable to the rights offering in 2016 that had been held in escrow, net of costs to register our common stock. |
Share-Based Compensation and Other Benefit Plans |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share-Based Compensation and Other Benefit Plans | Share-Based Compensation and Other Benefit Plans Share-Based Compensation We recognize share-based compensation expense related to our share-based compensation plans as a component of “General and administrative” expense in our Condensed Consolidated Statements of Operations. In the Predecessor periods in 2016 we had outstanding equity-classified awards in the form of stock options, restricted stock units and deferred stock units. All outstanding equity-classified share-based compensation awards were canceled in connection with our emergence from bankruptcy. We reserved 749,600 shares of Successor common Stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 256,400 shares of time-vested restricted stock units (“RSUs”) and 62,675 performance restricted stock units (“PRSUs”) had been granted as of June 30, 2017. The following table summarizes our share-based compensation expense (benefit) recognized for the periods presented:
_______________________ 1 Amounts for the 2016 periods have been recasted (see Note 2). In the six months ended June 30, 2017, we granted 148,837 RSUs to certain employees with an average grant-date fair value of $51.50 per RSU. The RSUs are being charged to expense on a straight-line basis over five years. In January 2017, we also granted 62,675 PRSUs to members of our management. The PRSUs were issued collectively in three separate tranches with individual three-year performance periods beginning in January 2017, 2018 and 2019, respectively. Vesting of the PRSUs can range from zero to 200 percent of the original grant based on the performance of our common stock relative to an industry index. The grant date fair values of the individual tranches were $65.28 for the first performance period tranche and $61.74 for each of the second and third performance period tranches. Due to their market condition, the PRSUs are being charged to expense using graded vesting over five years. The fair value of each PRSU award was estimated on the January 26, 2017 date of grant using a Monte Carlo simulation. Expected volatilities were based on historical volatilities. A risk-free rate of interest of 1.49% was utilized which is equivalent to the yield, as of the measurement date, of the zero-coupon U.S. Treasury bill commensurate with the longest remaining performance measurement period for each tranche. We assumed no payment of dividends during the performance periods. Other Benefit Plans We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.1 million and $0.2 million of expense attributable to the 401(k) Plan for the three and six months ended June 30, 2017, respectively and $0.2 million and $0.3 million of expense attributable to the 401(k) Plan for the three and six months ended June 30, 2016, respectively. We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees, all of whom retired prior to 2000. The combined expense recognized with respect to these plans was less than $0.1 million for each of the three and six months ended June 30, 2017 and 2016. |
Interest Expense |
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Banking and Thrift [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Expense | The following table summarizes the components of interest expense for the periods presented:
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Earnings (Loss) per Share |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Earnings (Loss) per Share | Earnings (Loss) per Share The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented:
_______________________ 1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the three and six months ended June 30, 2016, as their assumed conversion would have been anti-dilutive. 2 The number of dilutive securities for the three and six months ended June 30, 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method. For the six months ended June 30, 2016, approximately 26.6 million of potentially dilutive securities, including the Series A and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted loss per common share. |
Basis of Presentation (Policies) |
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Schedule of Policies [Line Items] | |||||
New Accounting Pronouncements | Recently Issued Accounting Pronouncements In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”) which provides guidance to improve the reporting of net benefit cost in financial statements. The guidance requires employers to disaggregate the service cost component from the other components of net benefit cost. The service cost component of net periodic benefit cost shall be reported in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period, except for amounts capitalized. All other components of net benefit cost shall be presented outside of a subtotal for income from operations. The line item used to present the components other than the service cost shall be disclosed if the other components are not presented in a separate line item or items. ASU 2017–07 is effective January 1, 2018 and is required to be applied retrospectively. ASU 2017–07 will be applicable to our legacy retiree benefit plans which cover a limited population of former employees. There is no service cost associated with these plans as they are not applicable to current employees, but rather “interest and other costs” associated with the legacy obligations. Upon the adoption of ASU 2017–07, the entirety of the expense associated with these plans will be presented as a component of the “Other income (expense)” caption in our Condensed Consolidated Statement of Operations. These costs are currently recognized as a component of “General and administrative” expenses. The total cost associated with these plans is generally less than $0.1 million on an annual basis and is therefore not material. We will adopt ASU 2017–07 in January 2018. In June 2016, the FASB issued ASU 2016–13, Measurement of Credit Losses on Financial Instruments (“ASU 2016–13”), which changes the recognition model for the impairment of financial instruments, including accounts receivable, loans and held-to-maturity debt securities, among others. ASU 2016–13 is required to be adopted using the modified retrospective method by January 1, 2020, with early adoption permitted for fiscal periods beginning after December 15, 2018. In contrast to current guidance, which considers current information and events and utilizes a probable threshold, (an “incurred loss” model), ASU 2016–13 mandates an “expected loss” model. The expected loss model: (i) estimates the risk of loss even when risk is remote, (ii) estimates losses over the contractual life, (iii) considers past events, current conditions and reasonable supported forecasts and (iv) has no recognition threshold. ASU 2016–13 will have applicability to our accounts receivable portfolio, particularly those receivables attributable to our joint interest partners. At this time, we do not anticipate that the adoption of ASU 2016–13 will have a significant impact on our Consolidated Financial Statements and related disclosures; however, we are currently in the early stages of evaluating the requirements and the period for which we will adopt the standard. In February 2016, the FASB issued ASU 2016–02, Leases (“ASU 2016–02”), which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases with terms of more than twelve months. Consistent with current GAAP, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance or operating lease. ASU 2016–02 also will require disclosures regarding the amount, timing, and uncertainty of cash flows arising from leases. The effective date of ASU 2016–02 is January 1, 2019, with early adoption permitted. We believe that ASU 2016–02 will likely be applicable to our oil and natural gas gathering commitment arrangements as described in Note 12, our existing leases for office facilities and certain office equipment and potentially to certain drilling rig and completion contracts with terms in excess of twelve months to the extent we may have such contracts in the future. Our oil and natural gas gathering arrangements are fairly complex and involve multiple elements that could be construed as leases. Accordingly, we are continuing to evaluate the effect that ASU 2016–02 will have on our Consolidated Financial Statements and related disclosures as well as the period for which we will adopt the standard, however, at this time, we believe that we will likely adopt ASU 2016–02 in 2019. In May 2014, the FASB issued ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014–09 will replace most existing revenue recognition guidance in GAAP when it becomes effective on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. While traditional commodity sales transactions, property conveyances and joint interest arrangements in the oil and gas industry are not expected to be significantly impacted by ASU 2014–09, natural gas imbalances and other non-product revenues, including our ancillary marketing, gathering and transportation and water disposal revenues could be affected. Accordingly, we are continuing to evaluate the effect that ASU 2014–09 will have on our Consolidated Financial Statements and related disclosures, with a more focused analysis on these other revenue sources, which we do not believe are significant. We are also continuing to monitor developments regarding ASU 2014–09 that are unique to our industry. We will adopt ASU 2014–09 in January 2018 using the cumulative effect transition method. |
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Basis of Presentation | Basis of Presentation Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2016. Operating results for the six months ended June 30, 2017, are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. Comparability of Financial Statements to Prior Periods We adopted and began applying the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”) on September 12, 2016. Accordingly, our Condensed Consolidated Financial Statements and Notes after September 12, 2016, are not comparable to the Condensed Consolidated Financial Statements and Notes through that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Condensed Consolidated Financial Statements and Notes as the “Successor,” which is effectively a new reporting entity for financial reporting purposes, for periods subsequent to September 12, 2016, and the “Predecessor” for periods prior to September 13, 2016. In connection with our reorganization, we experienced a change in control as the outstanding common and preferred shares of the Predecessor were canceled and substantially all of the Successor’s new common stock was issued to the Predecessor’s creditors. Furthermore, our Condensed Consolidated Financial Statements and Notes have been presented with a “black line” division to delineate, where applicable, the lack of comparability between the Predecessor and Successor. In addition, we adopted the full cost method of accounting for our oil and gas properties effective with our adoption of Fresh Start Accounting. Accordingly, our results of operations, financial position and cash flows for the Successor periods will be substantially different from our historic trends. We have recasted amounts for equity-classified share-based compensation recognized as a component of “General and administrative” expenses from the amounts originally reported for the three and six months ended June 30, 2016 to correct for an immaterial error identified by management and disclosed in our Quarterly Report on Form 10-Q for the period ended September 30, 2016. Previously reported expenses associated with this matter, as well as our operating losses and net losses, were increased by $5.3 million for each of the three and six-month periods ended June 30, 2016. Our net loss per basic and diluted share increased by $0.06 for each of the three and six-month periods ended June 30, 2016. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements for the Successor periods have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. |
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Fair Value Measurements | We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. |
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Fair Value, Measurements, Recurring | |||||
Schedule of Policies [Line Items] | |||||
Fair Value Measurements | We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:
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Fair Value, Measurements, Nonrecurring | |||||
Schedule of Policies [Line Items] | |||||
Fair Value Measurements | Non-Recurring Fair Value Measurements The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs. In addition, we utilize non-recurring fair value measurements with respect to the recognition and measurement of asset impairments, particularly during our Predecessor periods during which time we applied the successful efforts method to our oil and gas properties. The factors used to determine fair value for purposes of recognizing and measuring asset impairments while we applied the successful efforts method to our oil and gas properties during our Predecessor periods included, but were not limited to, estimates of proved and risk-adjusted probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs were typically not observable, we have categorized the amounts as level 3 inputs. Under the full cost method, which we have applied since the Effective Date, we apply a ceiling test determination utilizing prescribed procedures. The full cost method is substantially different from the successful efforts method which relies upon fair value measurements. |
Accounts Receivable and Major Customers (Tables) |
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Receivables [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Accounts Receivable | The following table summarizes our accounts receivable by type as of the dates presented:
_______________________ 1 Includes amounts owed to us from joint venture partners for acquisitions in prior periods, severance tax refunds approved by state taxing authorities to be returned to us and other miscellaneous non-operating items. |
Derivative Instruments (Tables) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity Derivative Positions | The following table sets forth our commodity derivative positions as of June 30, 2017:
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Impact of Derivative Activities on Condensed Consolidated Statements of Income | The impact of our derivative activities on income is included in “Derivatives” in our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:
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Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets | The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:
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Property and Equipment (Tables) |
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Property, Plant and Equipment [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Property and Equipment | The following table summarizes our property and equipment as of the dates presented:
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Additional Balance Sheet Detail (Tables) |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components of Selected Balance Sheet Accounts | The following table summarizes components of selected balance sheet accounts as of the dates presented:
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Fair Value Measurements (Tables) |
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Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on Recurring Basis | The following tables summarize the valuation of those assets and liabilities as of the dates presented:
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Shareholders' Equity (Tables) |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Stockholders Equity | The following tables summarize the components of our shareholders’ equity and the changes therein as of and for six months ended June 30, 2017:
_______________________ 1 Includes equity-classified share-based compensation of $1.7 million and $0.1 million from the receipt in May 2017 of proceeds attributable to the rights offering in 2016 that had been held in escrow, net of costs to register our common stock. |
Share-Based Compensation (Tables) |
6 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Share-Based Compensation Expense | The following table summarizes our share-based compensation expense (benefit) recognized for the periods presented:
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Interest Expense (Tables) |
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Banking and Thrift [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Expense Net Disclosure | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Expense | The following table summarizes the components of interest expense for the periods presented:
___________________
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Earnings per Share (Tables) |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Components of Calculation of Basic and Diluted Earnings Per Share | _______________________ 1 Dividends attributable to our Series A 6% Convertible Perpetual Preferred Stock and Series B 6% Convertible Perpetual Preferred Stock (together, the “Series A and B Preferred Stock”) were excluded from the computation of diluted loss per share for the three and six months ended June 30, 2016, as their assumed conversion would have been anti-dilutive. 2 The number of dilutive securities for the three and six months ended June 30, 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method. For the six months ended June 30, 2016, approximately 26.6 million of potentially dilutive securities, including the Series A and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted loss per common share. The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented:
|
Nature of Operations Nature of Operations (Details) |
6 Months Ended |
---|---|
Jun. 30, 2017 | |
TEXAS | Eagle Ford Shale | |
Concentration Risk [Line Items] | |
Concentration risk, percentage (more than) | 90.00% |
Basis of Presentation (Details) - $ / shares |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Immaterial Error Correction | 5.3 | 5.3 | ||
Successor [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Basic (in dollars per share) | $ 1.42 | $ 3.30 | ||
Diluted (in dollars per share) | $ 1.42 | $ 3.27 | ||
Increase in Diluted and Basic Earnings Per Share [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Basic (in dollars per share) | $ 0.06 | $ 0.06 | ||
Diluted (in dollars per share) | $ 0.06 | $ 0.06 |
Basis of Presentation Subsequent Event (Details) $ in Millions |
Jul. 31, 2017
USD ($)
|
---|---|
Subsequent Event [Member] | |
Subsequent Event [Line Items] | |
Acquisition Costs, Period Cost | $ 205 |
Bankruptcy Proceeding Bankruptcy Proceeding (Details) $ in Thousands |
May 12, 2016
subsidiary
|
Jun. 30, 2017
USD ($)
|
Dec. 31, 2016
USD ($)
|
---|---|---|---|
Reorganizations [Abstract] | |||
Number of Subsidiaries Filing Chapter 11 Bankruptcy | subsidiary | 8 | ||
Bankruptcy Claims, amount reserved for outstanding claims | $ | $ 3,922 | $ 3,922 |
Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Receivables [Abstract] | ||
Customers | $ 22,920 | $ 20,489 |
Joint interest partners | 21,598 | 7,238 |
Other | 670 | 3,789 |
Accounts Receivable, Gross, Current, Total | 45,188 | 31,516 |
Less: Allowance for doubtful accounts | (2,381) | (2,421) |
Accounts receivable, net of allowance for doubtful accounts | $ 42,807 | $ 29,095 |
Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Successor [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivatives | $ 11,061 | $ 28,077 | ||
Predecessor [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivatives | $ (21,759) | $ (17,267) |
Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivatives, Fair Value [Line Items] | ||
Derivative assets, current | $ 2,672 | $ 0 |
Derivative Asset, Noncurrent | 584 | 0 |
Derivative assets | 3,256 | 0 |
Commodity derivative liabilities – current | 0 | 12,932 |
Derivative Liability, Noncurrent | 90 | 14,437 |
Derivative Liability | 90 | 27,369 |
Commodity contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability | 3,200 | |
Commodity contracts | Derivative assets/liabilities - current | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, current | 2,672 | 0 |
Commodity derivative liabilities – current | 0 | 12,932 |
Commodity contracts | Noncurrent Derivative Contract [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Noncurrent | 584 | 0 |
Derivative Liability, Noncurrent | $ 90 | $ 14,437 |
Summary of Long-Term Debt (Detail) - USD ($) |
Jun. 30, 2017 |
Mar. 31, 2017 |
Dec. 31, 2016 |
---|---|---|---|
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 128,000,000 | ||
Revolving credit facility | $ 37,000,000 | $ 25,000,000 | |
Revolving Credit Facility | |||
Debt Instrument [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 200,000,000 |
Income Taxes (Details) - USD ($) $ in Millions |
6 Months Ended | |
---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Income Tax Disclosure [Abstract] | ||
Blended tax rate (as a percent) | 35.52% | |
Federal statutory income tax rate (as a percent) | 35.00% | |
Income taxes refund received (less than) | $ 0.1 |
Exit Activities (Detail) $ in Thousands |
6 Months Ended | 12 Months Ended | |
---|---|---|---|
Jun. 30, 2017
USD ($)
|
Jun. 30, 2016
USD ($)
|
Dec. 31, 2016 |
|
Predecessor [Member] | |||
Restructuring Cost and Reserve [Line Items] | |||
Restructuring and Related Cost, Number of Positions Eliminated | 28 | 53 | |
Severance and Termination Benefits | $ 700 | $ 1,100 | |
Liabilities Subject to Compromise, Early Contract Termination Fees | 1,300 | ||
Payments for Restructuring | 1,100 | ||
Restructuring Reserve, Accretion of Obligation | $ 317 | ||
Successor [Member] | |||
Restructuring Cost and Reserve [Line Items] | |||
Severance and Termination Adjustment | 100 | ||
Restructuring Reserve, Accretion of Obligation | $ 0 |
Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands |
Jun. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Other current assets: | ||
Tubular inventory and well materials | $ 2,100 | $ 2,125 |
Prepaid expenses | 1,000 | 903 |
Other Assets, Current | 3,100 | 3,028 |
Other assets: | ||
Deferred issuance costs of the Revolver | 2,887 | 2,785 |
Other | 2,536 | 2,544 |
Other assets | 5,423 | 5,329 |
Accounts payable and accrued liabilities: | ||
Trade accounts payable | 10,166 | 9,825 |
Drilling costs | 4,802 | 2,479 |
Royalties and revenue – related | 33,231 | 26,116 |
Compensation – related | 1,739 | 2,557 |
Interest | 84 | 55 |
Reserve for bankruptcy claims | 3,922 | 3,922 |
Other | 5,319 | 4,743 |
Accounts payable and accrued liabilities | 59,263 | 49,697 |
Other liabilities: | ||
Asset retirement obligations (“AROs”) | 2,506 | 2,459 |
Defined benefit pension obligations | 972 | 1,025 |
Postretirement health care benefit obligations | 525 | 488 |
Other | 100 | 100 |
Other liabilities | $ 4,103 | $ 4,072 |
Commitments and Contingencies - Additional Information (Detail) $ in Millions |
6 Months Ended |
---|---|
Jun. 30, 2017
USD ($)
bbl
| |
Commitments and Contingencies Disclosure [Line Items] | |
Long-term Purchase Commitment, Minimum Volume Required | bbl | 8,000 |
Marketing Agreement | 10 |
Asset Retirement Obligation | $ 2.5 |
Legal Reserve | |
Commitments and Contingencies Disclosure [Line Items] | |
Reserve established for contingency matters | 0.1 |
Crude Oil Gathering And Transportation Services | |
Commitments and Contingencies Disclosure [Line Items] | |
Contractual obligation, balance of 2017 | 5.0 |
Contractual Obligation, Due in 2018 | 10.4 |
Contractual Obligation, Due in 2019 | 11.7 |
Contractual Obligation, Due 2020 through 2025 | 13.0 |
Contractual Obligation, Due 2026 | 7.4 |
Contractual Obligation, Due 2027 through 2030 | 3.8 |
Contractual Obligation, Due 2031 | 2.2 |
Contract Drilling [Member] | |
Commitments and Contingencies Disclosure [Line Items] | |
Contractual Obligation | $ 4.5 |
Summary of Share-Based Compensation Expense (Detail) $ / shares in Units, $ in Thousands |
1 Months Ended | 3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|---|
Jan. 31, 2017
tranche
$ / shares
shares
|
Jun. 30, 2017
USD ($)
shares
|
Jun. 30, 2016
USD ($)
|
Jun. 30, 2017
USD ($)
$ / shares
shares
|
Jun. 30, 2016
USD ($)
|
|
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based compensation (equity-classified) | $ (1,700) | ||||
Time Vested Restricted Stock Units [Domain] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares | 256,400 | 256,400 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | $ 51.50 | ||||
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period | 5 years | ||||
Performance Restricted Stock Units [Domain] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares | 62,675 | 62,675 | 62,675 | ||
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period | 5 years | ||||
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche | 3 | ||||
Share-based Compensation Arrangements By Share-based Payment Award, Performance Period | 3 years | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Minimum | 1.49% | ||||
Performance Restricted Stock Units [Domain] | Minimum [Member] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage | 0.00% | ||||
Performance Restricted Stock Units [Domain] | Maximum [Member] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage | 200.00% | ||||
Performance Restricted Stock Units [Domain] | Year 1 [Domain] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | $ 65.28 | ||||
Performance Restricted Stock Units [Domain] | Year 2 | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | 61.74 | ||||
Performance Restricted Stock Units [Domain] | Year 3 | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | $ 61.74 | ||||
Time Vested Restricted Stock Units - Employees [Domain] [Domain] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares | 148,837 | 148,837 | |||
Employees and Directors [Member] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares | 749,600 | 749,600 | |||
Predecessor [Member] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Other Stock Based Compensation Expense | $ 1,965 | $ 1,364 | |||
Share-based compensation (equity-classified) | (1,364) | ||||
Allocated Share-based Compensation Expense | 1,953 | 1,345 | |||
Defined Contribution Plan, Cost | 200 | 300 | |||
Predecessor [Member] | Other Pension, Postretirement and Supplemental Plans [Member] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Pension and Other Postretirement Benefits Cost (Reversal of Cost) | 100 | 100 | |||
Predecessor [Member] | Liability-classified awards | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based compensation (equity-classified) | $ (12) | $ (19) | |||
Successor [Member] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Other Stock Based Compensation Expense | $ 848 | $ 1,694 | |||
Share-based compensation (equity-classified) | (1,694) | ||||
Allocated Share-based Compensation Expense | 848 | 1,694 | |||
Defined Contribution Plan, Cost | 100 | 200 | |||
Successor [Member] | Other Pension, Postretirement and Supplemental Plans [Member] | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Pension and Other Postretirement Benefits Cost (Reversal of Cost) | 100 | 100 | |||
Successor [Member] | Liability-classified awards | |||||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||||
Share-based compensation (equity-classified) | $ 0 | $ 0 |
Interest Expense Components of Interest Expense (Details) - USD ($) $ in Thousands |
3 Months Ended | 6 Months Ended | |||||||
---|---|---|---|---|---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
||||||
Components of Interest Expense [Line Items] | |||||||||
Write off of Deferred Debt Issuance Cost | $ 600 | ||||||||
Successor [Member] | |||||||||
Components of Interest Expense [Line Items] | |||||||||
Interest Expense, Borrowings | $ 515 | 905 | |||||||
Amortization of Debt Issuance Costs | [1] | 800 | 988 | ||||||
Interest Paid, Capitalized | (41) | (81) | |||||||
Interest Expense | $ 1,274 | 1,812 | |||||||
Write off of Deferred Debt Issuance Cost | $ 600 | ||||||||
Predecessor [Member] | |||||||||
Components of Interest Expense [Line Items] | |||||||||
Interest Expense, Borrowings | [2] | $ 11,344 | $ 34,649 | ||||||
Amortization of Debt Issuance Costs | [1] | 20,920 | 22,189 | ||||||
Interest Paid, Capitalized | (43) | (183) | |||||||
Interest Expense | 32,221 | 56,655 | |||||||
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations | 23,500 | 46,900 | |||||||
Debtor Reorganization Items, Write-off of Debt Issuance Costs and Debt Discounts | 20,500 | ||||||||
Senior Notes Due 2019 [Domain] | Predecessor [Member] | |||||||||
Components of Interest Expense [Line Items] | |||||||||
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations | 5,400 | 10,900 | |||||||
Senior Notes Due 2020 [Domain] | Predecessor [Member] | |||||||||
Components of Interest Expense [Line Items] | |||||||||
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations | $ 16,500 | $ 32,900 | |||||||
|
Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended | 6 Months Ended | ||
---|---|---|---|---|
Jun. 30, 2017 |
Jun. 30, 2016 |
Jun. 30, 2017 |
Jun. 30, 2016 |
|
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Net income (loss) | $ 49,410 | |||
Successor [Member] | ||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Net income (loss) | $ 21,329 | 49,410 | ||
Less: Preferred stock dividends | 0 | 0 | ||
Net loss attributable to common shareholders, Diluted | $ 21,329 | $ 49,410 | ||
Weighted-average shares – basic | 14,992 | 14,992 | ||
Effect of dilutive securities | 58 | 105 | ||
Weighted-average shares – diluted | 15,050 | 15,097 | ||
Predecessor [Member] | ||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Net income (loss) | $ (67,266) | $ (100,739) | ||
Less: Preferred stock dividends | (2,820) | (5,972) | ||
Net loss attributable to common shareholders, Diluted | $ (70,086) | $ (106,711) | ||
Weighted-average shares – basic | 89,051 | 87,496 | ||
Effect of dilutive securities | 0 | 0 | ||
Weighted-average shares – diluted | 89,051 | 87,496 | ||
Potentially dilutive securities with the effect of being anti-dilutive excluded from the calculation of diluted earnings per common share | 26,600 | |||
Predecessor [Member] | Series A Preferred Stock | ||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Perpetual Preferred Stock, dividend rate (as a percent) | 6.00% | |||
Predecessor [Member] | Series B Preferred Stock | ||||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Perpetual Preferred Stock, dividend rate (as a percent) | 6.00% |
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