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 | ý | |
Non-accelerated filer | o | (Do not check if a smaller reporting company) | Smaller reporting company | o |
Emerging growth company | o |
Part I - Financial Information | ||
Item | Page | |
1. | Financial Statements (unaudited). | |
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. Acquisitions and Divestitures | ||
4. Bankruptcy Proceedings and Emergence | ||
5. Accounts Receivable and Revenues from Contracts with Customers | ||
6. Derivative Instruments | ||
7. Property and Equipment | ||
8. Long-Term Debt | ||
9. Income Taxes | ||
10. Executive Retirement | ||
11. Additional Balance Sheet Detail | ||
12. Fair Value Measurements | ||
13. Commitments and Contingencies | ||
14. Shareholders’ Equity | ||
15. Share-Based Compensation and Other Benefit Plans | ||
16. Interest Expense | ||
17. Earnings 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. |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Revenues | |||||||
Crude oil | $ | 71,258 | $ | 30,073 | |||
Natural gas liquids | 2,946 | 2,302 | |||||
Natural gas | 2,790 | 2,343 | |||||
Gain on sales of assets, net | 75 | 65 | |||||
Other, net | 142 | 203 | |||||
Total revenues | 77,211 | 34,986 | |||||
Operating expenses | |||||||
Lease operating | 7,296 | 4,916 | |||||
Gathering, processing and transportation | 3,359 | 2,551 | |||||
Production and ad valorem taxes | 4,092 | 1,979 | |||||
General and administrative | 6,471 | 4,107 | |||||
Depreciation, depletion and amortization | 22,081 | 9,810 | |||||
Total operating expenses | 43,299 | 23,363 | |||||
Operating income | 33,912 | 11,623 | |||||
Other income (expense) | |||||||
Interest expense | (4,601 | ) | (538 | ) | |||
Derivatives | (18,795 | ) | 17,016 | ||||
Other, net | (58 | ) | (20 | ) | |||
Income before income taxes | 10,458 | 28,081 | |||||
Income tax expense | (163 | ) | — | ||||
Net income | $ | 10,295 | $ | 28,081 | |||
Net income per share: | |||||||
Basic | $ | 0.68 | $ | 1.87 | |||
Diluted | $ | 0.68 | $ | 1.86 | |||
Weighted average shares outstanding – basic | 15,042 | 14,992 | |||||
Weighted average shares outstanding – diluted | 15,081 | 15,126 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Net income | $ | 10,295 | $ | 28,081 | |||
Other comprehensive income: | |||||||
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2018 and 2017, respectively | — | — | |||||
— | — | ||||||
Comprehensive income | $ | 10,295 | $ | 28,081 |
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
Assets | |||||||
Current assets | |||||||
Cash and cash equivalents | $ | 7,319 | $ | 11,017 | |||
Accounts receivable, net of allowance for doubtful accounts | 55,957 | 69,821 | |||||
Other current assets | 6,756 | 6,250 | |||||
Total current assets | 70,032 | 87,088 | |||||
Property and equipment, net (full cost method) | 691,283 | 529,059 | |||||
Derivative assets | 32 | — | |||||
Deferred income taxes | 4,780 | 4,943 | |||||
Other assets | 3,273 | 8,507 | |||||
Total assets | $ | 769,400 | $ | 629,597 | |||
Liabilities and Shareholders’ Equity | |||||||
Current liabilities | |||||||
Accounts payable and accrued liabilities | $ | 97,134 | $ | 96,181 | |||
Derivative liabilities | 36,820 | 27,777 | |||||
Total current liabilities | 133,954 | 123,958 | |||||
Other liabilities | 5,308 | 4,833 | |||||
Derivative liabilities | 16,108 | 13,900 | |||||
Long-term debt, net | 383,766 | 265,267 | |||||
Commitments and contingencies (Note 13) | |||||||
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; 15,058,210 and 15,018,870 shares issued as of March 31, 2018 and December 31, 2017, respectively | 151 | 150 | |||||
Paid-in capital | 195,111 | 194,123 | |||||
Retained earnings | 35,002 | 27,366 | |||||
Accumulated other comprehensive income | — | — | |||||
Total shareholders’ equity | 230,264 | 221,639 | |||||
Total liabilities and shareholders’ equity | $ | 769,400 | $ | 629,597 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Cash flows from operating activities | |||||||
Net income | $ | 10,295 | $ | 28,081 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 22,081 | 9,810 | |||||
Derivative contracts: | |||||||
Net (gains) losses | 18,795 | (17,016 | ) | ||||
Cash settlements, net | (7,576 | ) | (1,992 | ) | |||
Deferred income tax expense | 163 | — | |||||
Gain on sales of assets, net | (75 | ) | (65 | ) | |||
Non-cash interest expense | 796 | 188 | |||||
Share-based compensation (equity-classified) | 1,576 | 846 | |||||
Other, net | 13 | 18 | |||||
Changes in operating assets and liabilities, net | (7,386 | ) | (10,728 | ) | |||
Net cash provided by operating activities | 38,682 | 9,142 | |||||
Cash flows from investing activities | |||||||
Acquisitions, net | (83,338 | ) | — | ||||
Capital expenditures | (77,839 | ) | (17,741 | ) | |||
Proceeds from sales of assets, net | 1,551 | — | |||||
Net cash used in investing activities | (159,626 | ) | (17,741 | ) | |||
Cash flows from financing activities | |||||||
Proceeds from credit facility borrowings | 118,000 | 7,000 | |||||
Repayment of credit facility borrowings | — | (2,000 | ) | ||||
Debt issuance costs paid | (754 | ) | — | ||||
Other, net | — | (30 | ) | ||||
Net cash provided by financing activities | 117,246 | 4,970 | |||||
Net decrease in cash and cash equivalents | (3,698 | ) | (3,629 | ) | |||
Cash and cash equivalents – beginning of period | 11,017 | 6,761 | |||||
Cash and cash equivalents – end of period | $ | 7,319 | $ | 3,132 | |||
Supplemental disclosures: | |||||||
Cash paid for: | |||||||
Interest, net of amounts capitalized | $ | 3,662 | $ | 348 | |||
Reorganization items, net | $ | 161 | $ | 634 | |||
Non-cash investing and financing activities: | |||||||
Changes in accounts receivable related to acquisitions | $ | (26,627 | ) | $ | — | ||
Changes in other assets related to acquisitions | $ | (2,469 | ) | $ | — | ||
Changes in accrued liabilities related to acquisitions | $ | (15,320 | ) | $ | — | ||
Changes in accrued liabilities related to capital expenditures | $ | 9,616 | $ | 2,262 |
1. | Nature of Operations |
2. | Basis of Presentation |
3. | Acquisitions and Divestitures |
Assets | ||||
Oil and gas properties - proved | $ | 82,198 | ||
Oil and gas properties - unproved | 16,339 | |||
Liabilities | ||||
Asset retirement obligations (“AROs”) | 356 | |||
Net assets acquired | $ | 98,181 | ||
Cash consideration paid to Hunt | $ | 84,403 | ||
Accumulated costs, net of suspended revenues, for wells in which Hunt had rights to participate | 13,778 | |||
Total acquisition costs incurred | $ | 98,181 |
Assets | ||||
Oil and gas properties - proved | $ | 42,866 | ||
Oil and gas properties - unproved | 146,686 | |||
Other property and equipment | 8,642 | |||
Liabilities | ||||
Revenue suspense | 355 | |||
Asset retirement obligations | 494 | |||
Net assets acquired | $ | 197,345 | ||
Cash consideration paid to Devon and tag-along parties, net | $ | 190,277 | ||
Amount transferred to Devon from the Escrow Account | 9,519 | |||
Application of working capital adjustments, net | (2,451 | ) | ||
Total consideration transferred | $ | 197,345 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Total revenues | $ | 82,456 | $ | 47,721 | |||
Net income | $ | 13,390 | $ | 28,189 | |||
Net income (loss) per share - basic | $ | 0.89 | $ | 1.88 | |||
Net income (loss) per share - diluted | $ | 0.89 | $ | 1.86 |
4. | Bankruptcy Proceedings and Emergence |
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
Customers | $ | 43,764 | $ | 39,106 | |||
Joint interest partners | 13,808 | 32,493 | |||||
Other | 747 | 584 | |||||
58,319 | 72,183 | ||||||
Less: Allowance for doubtful accounts | (2,362 | ) | (2,362 | ) | |||
$ | 55,957 | $ | 69,821 |
As Determined | As Reported Under | Increase | |||||||||
Under Prior GAAP | ASC Topic 606 | (Decrease) | |||||||||
Revenues | |||||||||||
Crude oil | $ | 71,258 | $ | 71,258 | $ | — | |||||
Natural gas liquids | $ | 3,392 | $ | 2,946 | $ | (446 | ) | ||||
Natural gas | $ | 2,790 | $ | 2,790 | $ | — | |||||
Marketing services (included in Other, net revenues) | $ | 92 | $ | 92 | $ | — | |||||
Operating expenses | |||||||||||
Gathering, processing and transportation | $ | 3,805 | $ | 3,359 | $ | (446 | ) | ||||
Net income | $ | 10,295 | $ | 10,295 | $ | — |
6. | Derivative Instruments |
Average | Weighted | |||||||||||||||
Volume Per | Average | Fair Value | ||||||||||||||
Instrument | Day | Price | Asset | Liability | ||||||||||||
Crude Oil: | (barrels) | ($/barrel) | ||||||||||||||
Second quarter 2018 | Swaps-WTI | 6,484 | $ | 51.09 | $ | — | $ | 7,888 | ||||||||
Second quarter 2018 | Swaps-LLS | 2,500 | $ | 55.18 | — | 2,735 | ||||||||||
Third quarter 2018 | Swaps-WTI | 6,455 | $ | 51.10 | — | 6,998 | ||||||||||
Third quarter 2018 | Swaps-LLS | 2,500 | $ | 55.18 | — | 2,404 | ||||||||||
Fourth quarter 2018 | Swaps-WTI | 6,455 | $ | 51.10 | — | 5,960 | ||||||||||
Fourth quarter 2018 | Swaps-LLS | 2,500 | $ | 55.18 | — | 2,003 | ||||||||||
First quarter 2019 | Swaps-WTI | 4,946 | $ | 52.03 | — | 3,372 | ||||||||||
First quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 2,422 | ||||||||||
Second quarter 2019 | Swaps-WTI | 4,921 | $ | 52.04 | — | 2,861 | ||||||||||
Second quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 2,144 | ||||||||||
Third quarter 2019 | Swaps-WTI | 4,897 | $ | 52.05 | — | 2,404 | ||||||||||
Third quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 1,897 | ||||||||||
Fourth quarter 2019 | Swaps-WTI | 4,898 | $ | 52.05 | — | 2,011 | ||||||||||
Fourth quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 1,660 | ||||||||||
First quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 1,123 | ||||||||||
Second quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 866 | ||||||||||
Third quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 650 | ||||||||||
Fourth quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 461 | ||||||||||
Settlements to be paid in subsequent period | 3,037 |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Derivative gains (losses) | $ | (18,795 | ) | $ | 17,016 |
March 31, 2018 | December 31, 2017 | ||||||||||||||||
Derivative | Derivative | Derivative | Derivative | ||||||||||||||
Type | Balance Sheet Location | Assets | Liabilities | Assets | Liabilities | ||||||||||||
Commodity contracts | Derivative assets/liabilities – current | $ | — | $ | 36,820 | $ | — | $ | 27,777 | ||||||||
Commodity contracts | Derivative assets/liabilities – noncurrent | 32 | 16,108 | — | 13,900 | ||||||||||||
$ | 32 | $ | 52,928 | $ | — | $ | 41,677 |
7. | Property and Equipment |
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
Oil and gas properties: | |||||||
Proved | $ | 624,747 | $ | 460,029 | |||
Unproved | 137,722 | 117,634 | |||||
Total oil and gas properties | 762,469 | 577,663 | |||||
Other property and equipment | 13,702 | 12,712 | |||||
Total properties and equipment | 776,171 | 590,375 | |||||
Accumulated depreciation, depletion and amortization | (84,888 | ) | (61,316 | ) | |||
$ | 691,283 | $ | 529,059 |
8. | Long-Term Debt |
March 31, 2018 | December 31, 2017 | ||||||||||||||
Principal | Unamortized Discount and Deferred Issuance Costs 1 | Principal | Unamortized Discount and Deferred Issuance Costs 1 | ||||||||||||
Credit facility 2 | $ | 195,000 | $ | 77,000 | |||||||||||
Second lien term loans | 200,000 | $ | 11,234 | 200,000 | $ | 11,733 | |||||||||
Totals | 395,000 | $ | 11,234 | 277,000 | $ | 11,733 | |||||||||
Less: Unamortized discount | (3,674 | ) | (3,839 | ) | |||||||||||
Less: Unamortized deferred issuance costs | (7,560 | ) | (7,894 | ) | |||||||||||
Long-term debt, net | $ | 383,766 | $ | 265,267 |
2 | Issuance costs of the Credit Facility, which represent costs attributable to the access to credit over its contractual term, have been presented as a component of Other assets (see Note 11) and are being amortized over the term of the Credit Facility using the straight-line method. |
9. | Income Taxes |
11. | Additional Balance Sheet Detail |
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
Other current assets: | |||||||
Tubular inventory and well materials | $ | 5,391 | $ | 5,146 | |||
Prepaid expenses | 1,365 | 1,104 | |||||
$ | 6,756 | $ | 6,250 | ||||
Other assets: | |||||||
Deferred issuance costs of the Credit Facility | $ | 3,268 | $ | 2,857 | |||
Deposit in escrow 1 | — | 3,210 | |||||
Other | 5 | 2,440 | |||||
$ | 3,273 | $ | 8,507 | ||||
Accounts payable and accrued liabilities: | |||||||
Trade accounts payable | $ | 17,223 | $ | 22,579 | |||
Drilling costs | 32,005 | 22,389 | |||||
Royalties and revenue – related | 34,995 | 39,287 | |||||
Compensation – related | 1,791 | 2,975 | |||||
Interest | 366 | 223 | |||||
Reserve for bankruptcy claims | 3,933 | 3,933 | |||||
Other | 6,821 | 4,795 | |||||
$ | 97,134 | $ | 96,181 | ||||
Other liabilities: | |||||||
Asset retirement obligations | $ | 3,777 | $ | 3,286 | |||
Defined benefit pension obligations | 940 | 971 | |||||
Postretirement health care benefit obligations | 491 | 476 | |||||
Other | 100 | 100 | |||||
$ | 5,308 | $ | 4,833 |
12. | Fair Value Measurements |
March 31, 2018 | ||||||||||||||||
Fair Value | Fair Value Measurement Classification | |||||||||||||||
Description | Measurement | Level 1 | Level 2 | Level 3 | ||||||||||||
Assets: | ||||||||||||||||
Commodity derivative assets – noncurrent | $ | 32 | $ | — | $ | 32 | $ | — | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivative liabilities – current | $ | (36,820 | ) | $ | — | $ | (36,820 | ) | $ | — | ||||||
Commodity derivative liabilities – noncurrent | (16,108 | ) | — | (16,108 | ) | — |
December 31, 2017 | ||||||||||||||||
Fair Value | Fair Value Measurement Classification | |||||||||||||||
Description | Measurement | Level 1 | Level 2 | Level 3 | ||||||||||||
Liabilities: | ||||||||||||||||
Commodity derivative liabilities – current | $ | (27,777 | ) | $ | — | $ | (27,777 | ) | $ | — | ||||||
Commodity derivative liabilities – noncurrent | (13,900 | ) | — | (13,900 | ) | — |
• | 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 WTI and LLS crude oil 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. |
13. | Commitments and Contingencies |
December 31, | All Other | March 31, | |||||||||||||
2017 | Net Income | Changes 1 | 2018 | ||||||||||||
Common stock | $ | 150 | $ | — | $ | 1 | $ | 151 | |||||||
Paid-in capital | 194,123 | — | 988 | 195,111 | |||||||||||
Retained earnings | 27,366 | 10,295 | (2,659 | ) | 35,002 | ||||||||||
Accumulated other comprehensive income | — | — | — | — | |||||||||||
$ | 221,639 | $ | 10,295 | $ | (1,670 | ) | $ | 230,264 |
15. | Share-Based Compensation and Other Benefit Plans |
16. | Interest Expense |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Interest on borrowings and related fees | $ | 6,048 | $ | 390 | |||
Accretion of original issue discount 1 | 165 | — | |||||
Amortization of debt issuance costs | 631 | 188 | |||||
Capitalized interest | (2,243 | ) | (40 | ) | |||
$ | 4,601 | $ | 538 |
1 | Includes accretion of original issue discount attributable to the Second Lien Facility (see Note 8). |
17. | Earnings per Share |
Three Months Ended March 31, | |||||||
2018 | 2017 | ||||||
Net income - basic and diluted | $ | 10,295 | $ | 28,081 | |||
Weighted-average shares – basic | 15,042 | 14,992 | |||||
Effect of dilutive securities 1 | 39 | 134 | |||||
Weighted-average shares – diluted | 15,081 | 15,126 |
1 | The number of dilutive securities for the three months ended March 31, 2018 and 2017, which is attributable to RSUs and PRSUs, was determined under the “treasury stock” method. |
• | risks related to recently completed acquisitions, including our ability to realize their expected benefits; |
• | our ability to satisfy our short-term and long-term liquidity needs, including our inability to generate sufficient cash |
• | negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service |
• | 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, NGLs, and natural gas; |
• | our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; |
• | our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well |
• | any impairments, write-downs or write-offs of our reserves or assets; |
• | the projected demand for and supply of oil, natural gas liquids, or 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 |
• | the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual |
• | 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 with other parties and counterparty risk related to the ability of these parties to meet their future obligations; |
• | the occurrence of unusual weather or operating conditions, including force majeure events; |
• | our ability to retain or attract senior management and key employees; |
• | compliance with and changes in governmental regulations or enforcement practices, especially with respect to |
• | 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, 2017. |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
• | Production increased approximately 28 percent to 1,453 thousand barrels of oil equivalent, or MBOE, from 1,135 MBOE due primarily to more productive and a greater number of wells turned to sales as well as the effect of one month of production from increased working interests in wells associated with the acquisition of certain oil and gas assets from Hunt Oil Company, or Hunt, in March 2018, or the Hunt Acquisition. |
• | Product revenues increased approximately 42 percent to $77.0 million from $54.1 million due primarily to higher crude oil volume and 10 percent higher crude oil prices. Higher natural gas revenues from higher volume and six percent higher pricing were substantially offset by lower NGL revenues due primarily to the $0.4 million effect of the adoption of ASC Topic 606 as referenced above. Excluding the effect of ASC Topic 606, NGL revenues increased approximately two percent while NGL pricing declined by approximately eight percent on a basis comparable to the 2017 period. |
• | Production and lifting costs (consisting of Lease operating expenses, or LOE, and GPT) increased on an absolute basis to $10.7 million from $9.5 million, but declined on a per unit basis to $7.33 per barrel of oil equivalent, or BOE, from $8.34 per BOE due primarily to the increase in production volume and lower down-hole maintenance costs in the first quarter of 2018 as well as the effect of the adoption of ASC Topic 606 ($0.4 million or $0.31 per BOE). |
• | Production and ad valorem taxes increased on an absolute and per unit basis to $4.1 million and $2.82 per BOE from $3.0 million and $2.68 per BOE, respectively, due to higher production volume and higher crude oil and natural gas pricing. |
• | G&A expenses increased on an absolute and per unit basis to $6.5 million and $4.45 per BOE from $3.5 million and $3.05 per BOE, respectively, due primarily to transaction costs associated with the Hunt Acquisition, costs associated with the retirement of our Executive Chairman in February 2018 and higher employee-related support costs as we have expanded our employee base commensurate with our current growth plans, partially offset by the effect of higher production volume. |
• | Depreciation, depletion and amortization, or DD&A, increased on an absolute and per unit basis to $22.1 million and $15.20 per BOE from $17.1 million and $15.07 per BOE, respectively due primarily to the higher production volume. |
• | Our operating income increased to $33.9 million for the three months ended March 31, 2018 compared to $21.2 million for the three months ended December 31, 2017 due the combined impact of the matters noted above. |
Three Months Ended | |||||||||||
March 31, | December 31, | March 31, | |||||||||
2018 | 2017 | 2017 | |||||||||
Total production (MBOE) | 1,453 | 1,135 | 855 | ||||||||
Average daily production (BOEPD) | 16,145 | 12,340 | 9,495 | ||||||||
Crude oil production (MBbl) | 1,127 | 845 | 608 | ||||||||
Crude oil production as a percent of total | 78 | % | 74 | % | 71 | % | |||||
Product revenues | $ | 76,994 | $ | 54,144 | $ | 34,718 | |||||
Crude oil revenues | $ | 71,258 | $ | 48,499 | $ | 30,073 | |||||
Crude oil revenues as a percent of total | 93 | % | 90 | % | 87 | % | |||||
Realized prices: | |||||||||||
Crude oil ($ per Bbl) | $ | 63.23 | $ | 57.42 | $ | 49.47 | |||||
NGLs ($ per Bbl) 1 | $ | 17.94 | $ | 22.47 | $ | 19.34 | |||||
Natural gas ($ per Mcf) | $ | 2.87 | $ | 2.71 | $ | 3.06 | |||||
Aggregate ($ per BOE) | $ | 52.99 | $ | 47.69 | $ | 40.63 | |||||
Prices adjusted for derivatives: | |||||||||||
Crude oil ($ per Bbl) | $ | 56.51 | $ | 55.24 | $ | 46.19 | |||||
Aggregate ($ per BOE) | $ | 47.77 | $ | 46.07 | $ | 38.30 | |||||
Production and lifting costs: | |||||||||||
Lease operating ($ per BOE) | $ | 5.02 | $ | 5.50 | $ | 5.75 | |||||
Gathering, processing and transportation ($ per BOE) 1 | $ | 2.31 | $ | 2.84 | $ | 2.98 | |||||
Production and ad valorem taxes ($ per BOE) | $ | 2.82 | $ | 2.68 | $ | 2.31 | |||||
General and administrative ($ per BOE) 2 | $ | 4.45 | $ | 3.05 | $ | 4.80 | |||||
Depreciation, depletion and amortization ($ per BOE) | $ | 15.20 | $ | 15.07 | $ | 11.47 | |||||
Cash provided by operating activities 3 | $ | 38,682 | $ | 31,416 | $ | 9,142 | |||||
Cash paid for capital expenditures | $ | 77,839 | $ | 47,843 | $ | 17,741 | |||||
Cash and cash equivalents at end of period | $ | 7,319 | $ | 11,017 | $ | 3,132 | |||||
Debt outstanding at end of period, net | $ | 383,766 | $ | 265,267 | $ | 30,000 | |||||
Credit available under credit facility at end of period | $ | 144,245 | $ | 159,745 | $ | 97,233 | |||||
Net development wells drilled and completed | 10.0 | 5.3 | 2.4 |
1 | The effects of the adoption of ASC Topic 606, if applied to the periods ended in 2017, would have resulted in realized prices for NGLs of $19.27 and $16.45 per BOE and GPT of $2.43 and $2.58 per BOE for the three months ended December 31, 2017 and March 31, 2017, respectively. |
2 | Includes combined amounts of $1.55, $0.83 and $0.96 per BOE for the three months ended March 31, 2018, December 31, 2017 and March 31, 2017, respectively, attributable to equity-classified share-based compensation and significant special charges, including acquisition transaction and other costs, as described in the discussion of “Results of Operations - General and Administrative” that follows. |
3 | Includes cash paid for derivative settlements of $7.6 million, $1.8 million and $2.0 million for the three months ended March 31, 2018, December 31, 2017 and March 31, 2017, respectively. |
WTI Volumes | WTI Average Swap Price | LLS Volumes | LLS Average Swap Price | ||||||||||
(Barrels per day) | ($ per barrel) | (Barrels per day) | ($ per barrel) | ||||||||||
Remainder of 2018 | 7,803 | $ | 53.33 | 2,500 | $ | 55.18 | |||||||
2019 | 5,415 | $ | 52.75 | 2,500 | $ | 51.30 | |||||||
2020 | 5,000 | $ | 53.21 | — | — |
Borrowings Outstanding | ||||||||||
Weighted- Average | Maximum | Weighted- Average Rate | ||||||||
Three months ended March 31, 2018 | $ | 124,756 | $ | 195,000 | 5.01 | % |
Three Months Ended | |||||||
March 31, | March 31, | ||||||
2018 | 2017 | ||||||
Cash flows from operating activities | |||||||
Operating cash flows, net of working capital changes | $ | 50,762 | $ | 12,116 | |||
Crude oil derivative settlements paid, net | (7,576 | ) | (1,992 | ) | |||
Interest payments, net of amounts capitalized | (3,662 | ) | (348 | ) | |||
Acquisition transaction costs paid | (431 | ) | — | ||||
Bankruptcy-related administration fees and costs paid | (161 | ) | (634 | ) | |||
Consulting costs paid to former Executive Chairman | (250 | ) | — | ||||
Net cash provided by operating activities | 38,682 | 9,142 | |||||
Cash flows from investing activities | |||||||
Acquisitions, net | (83,338 | ) | — | ||||
Capital expenditures | (77,839 | ) | (17,741 | ) | |||
Proceeds from sales of assets, net | 1,551 | — | |||||
Net cash used in investing activities | (159,626 | ) | (17,741 | ) | |||
Cash flows from financing activities | |||||||
Proceeds from credit facility borrowings, net | 118,000 | 5,000 | |||||
Debt issuance costs paid | (754 | ) | — | ||||
Other, net | — | (30 | ) | ||||
Net cash provided by financing activities | 117,246 | 4,970 | |||||
Net decrease in cash and cash equivalents | $ | (3,698 | ) | $ | (3,629 | ) |
Three Months Ended | |||||||
March 31, | March 31, | ||||||
2018 | 2017 | ||||||
Drilling and completion | $ | 81,044 | $ | 19,640 | |||
Lease acquisitions and other land-related costs | 2,061 | 714 | |||||
Pipeline, gathering facilities and other equipment, net | 973 | (781 | ) | ||||
Geological, geophysical (seismic) costs | 150 | 186 | |||||
$ | 84,228 | $ | 19,759 |
Three Months Ended | |||||||
March 31, | March 31, | ||||||
2018 | 2017 | ||||||
Total capital expenditures program costs (from above) | $ | 84,228 | $ | 19,759 | |||
(Increase) decrease in accrued capitalized costs | (9,616 | ) | (2,262 | ) | |||
Less: | |||||||
Transfers from tubular inventory and well materials | (1,335 | ) | (331 | ) | |||
Add: | |||||||
Tubular inventory and well materials purchased in advance of drilling | 1,580 | 72 | |||||
Capitalized internal labor | 739 | 463 | |||||
Capitalized interest | 2,243 | 40 | |||||
Total cash paid for capital expenditures | $ | 77,839 | $ | 17,741 |
March 31, | December 31, | ||||||
2018 | 2017 | ||||||
Credit Facility borrowings | $ | 195,000 | $ | 77,000 | |||
Second Lien Facility term loans, net | 188,766 | 188,267 | |||||
Total debt, net | 383,766 | 265,267 | |||||
Shareholders’ equity | 230,264 | 221,639 | |||||
$ | 614,030 | $ | 486,906 | ||||
Debt as a % of total capitalization | 62 | % | 54 | % |
Total Production | Average Daily Production | ||||||||||||||||
2018 vs. | 2018 vs. | ||||||||||||||||
Three Months Ended | 2017 | Three Months Ended | 2017 | ||||||||||||||
March 31, | March 31, | Favorable | March 31, | March 31, | Favorable | ||||||||||||
2018 | 2017 | (Unfavorable) | 2018 | 2017 | (Unfavorable) | ||||||||||||
Crude oil (MBbl & BOPD) | 1,127 | 608 | 519 | 12,522 | 6,755 | 5,767 | |||||||||||
NGLs (MBbl and BOPD) | 164 | 119 | 45 | 1,825 | 1,322 | 503 | |||||||||||
Natural gas (MMcf and MMcfpd) | 971 | 765 | 206 | 11 | 9 | 2 | |||||||||||
Total (MBOE and BOEPD) | 1,453 | 855 | 598 | 16,145 | 9,495 | 6,650 | |||||||||||
2018 vs. | 2018 vs. | ||||||||||||||||
Three Months Ended | 2017 | Three Months Ended | 2017 | ||||||||||||||
March 31, | March 31, | Favorable | March 31, | March 31, | Favorable | ||||||||||||
2018 | 2017 | (Unfavorable) | 2018 | 2017 | (Unfavorable) | ||||||||||||
(MBOE) | (BOEPD) | ||||||||||||||||
South Texas | 1,383 | 770 | 613 | 15,370 | 8,561 | 6,809 | |||||||||||
Mid-Continent | 70 | 84 | (14 | ) | 775 | 934 | (159 | ) | |||||||||
1,453 | 855 | 598 | 16,145 | 9,495 | 6,650 |
Total Product Revenues | Product Revenues per Unit of Volume | ||||||||||||||||||||||
2018 vs. | 2018 vs. | ||||||||||||||||||||||
Three Months Ended | 2017 | Three Months Ended | 2017 | ||||||||||||||||||||
March 31, | March 31, | Favorable | March 31, | March 31, | Favorable | ||||||||||||||||||
2018 | 2017 | (Unfavorable) | 2018 | 2017 | (Unfavorable) | ||||||||||||||||||
($ per unit of volume) | |||||||||||||||||||||||
Crude oil | $ | 71,258 | $ | 30,073 | $ | 41,185 | $ | 63.23 | $ | 49.47 | $ | 13.76 | |||||||||||
NGLs | 2,946 | 2,302 | 644 | $ | 17.94 | $ | 19.34 | $ | (1.40 | ) | |||||||||||||
Natural gas | 2,790 | 2,343 | 447 | $ | 2.87 | $ | 3.06 | $ | (0.19 | ) | |||||||||||||
Total | $ | 76,994 | $ | 34,718 | $ | 42,276 | $ | 52.99 | $ | 40.63 | $ | 12.36 | |||||||||||
2018 vs. | 2018 vs. | ||||||||||||||||||||||
Three Months Ended | 2017 | Three Months Ended | 2017 | ||||||||||||||||||||
March 31, | March 31, | Favorable | March 31, | March 31, | Favorable | ||||||||||||||||||
2018 | 2017 | (Unfavorable) | 2018 | 2017 | (Unfavorable) | ||||||||||||||||||
($ per BOE) | |||||||||||||||||||||||
South Texas | $ | 75,316 | $ | 32,687 | $ | 42,629 | $ | 54.45 | $ | 42.42 | $ | 12.03 | |||||||||||
Mid-Continent | 1,678 | 2,031 | (353 | ) | $ | 24.05 | $ | 24.16 | $ | (0.11 | ) | ||||||||||||
$ | 76,994 | $ | 34,718 | $ | 42,276 | $ | 52.99 | $ | 40.63 | $ | 12.36 |
Three Months Ended March 31, 2018 vs. 2017 | |||||||||||
Revenue Variance Due to | |||||||||||
Volume | Price | Total | |||||||||
Crude oil | $ | 25,674 | $ | 15,511 | $ | 41,185 | |||||
NGLs | 875 | (231 | ) | 644 | |||||||
Natural gas | 630 | (183 | ) | 447 | |||||||
$ | 27,179 | $ | 15,097 | $ | 42,276 |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Crude oil revenues, as reported | $ | 71,258 | $ | 30,073 | $ | 41,185 | |||||
Derivative settlements, net | (7,576 | ) | (1,992 | ) | (5,584 | ) | |||||
$ | 63,682 | $ | 28,081 | $ | 35,601 | ||||||
Crude oil prices per Bbl | $ | 63.23 | $ | 49.47 | $ | 13.76 | |||||
Derivative settlements per Bbl | (6.72 | ) | (3.28 | ) | (3.44 | ) | |||||
$ | 56.51 | $ | 46.19 | $ | 10.32 |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Gain on sales of assets, net | $ | 75 | $ | 65 | $ | 10 |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Other revenues, net | $ | 142 | $ | 203 | $ | (61 | ) |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Lease operating | $ | 7,296 | $ | 4,916 | $ | (2,380 | ) | ||||
Per unit of production ($/BOE) | $ | 5.02 | $ | 5.75 | $ | 0.73 | |||||
% Change per unit of production | 12.7 | % |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Gathering, processing and transportation | $ | 3,359 | $ | 2,551 | $ | (808 | ) | ||||
Per unit of production ($/BOE) | $ | 2.31 | $ | 2.98 | $ | 0.67 | |||||
% Change per unit of production | 22.5 | % |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Production and ad valorem taxes | |||||||||||
Production/severance taxes | $ | 3,609 | $ | 1,655 | $ | (1,954 | ) | ||||
Ad valorem taxes | 483 | 324 | (159 | ) | |||||||
$ | 4,092 | $ | 1,979 | $ | (2,113 | ) | |||||
Per unit production ($/BOE) | $ | 2.82 | $ | 2.31 | $ | (0.51 | ) | ||||
Production/severance tax rate as a percent of product revenue | 4.7 | % | 4.8 | % |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Primary G&A | $ | 4,214 | $ | 3,281 | $ | (933 | ) | ||||
Share-based compensation (equity-classified) | 1,576 | 846 | (730 | ) | |||||||
Significant special charges: | |||||||||||
Acquisition transaction costs | 431 | — | (431 | ) | |||||||
Executive retirement costs | 250 | — | (250 | ) | |||||||
Restructuring expenses | — | (20 | ) | (20 | ) | ||||||
Total G&A | $ | 6,471 | $ | 4,107 | $ | (2,364 | ) | ||||
Per unit of production ($/BOE) | $ | 4.45 | $ | 4.80 | $ | 0.35 | |||||
Per unit of production excluding share-based compensation and other significant special charges identified above ($/BOE) | $ | 2.90 | $ | 3.84 | $ | 0.94 |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
DD&A expense | $ | 22,081 | $ | 9,810 | $ | (12,271 | ) | ||||
DD&A Rate ($/BOE) | $ | 15.20 | $ | 11.47 | $ | (3.73 | ) |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Interest on borrowings and related fees | $ | 6,048 | $ | 390 | $ | (5,658 | ) | ||||
Accretion of original discount | 165 | — | (165 | ) | |||||||
Amortization of debt issuance costs | 631 | 188 | (443 | ) | |||||||
Capitalized interest | (2,243 | ) | (40 | ) | 2,203 | ||||||
$ | 4,601 | $ | 538 | $ | (4,063 | ) |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Crude oil derivative gains (losses) | $ | (18,795 | ) | $ | 17,016 | $ | (35,811 | ) |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Other, net | $ | (58 | ) | $ | (20 | ) | $ | (38 | ) |
2018 vs. | |||||||||||
Three Months Ended | 2017 | ||||||||||
March 31, | March 31, | Favorable | |||||||||
2018 | 2017 | (Unfavorable) | |||||||||
Income tax benefit (expense) | $ | (163 | ) | $ | — | $ | (163 | ) | |||
Effective tax rate | 1.6 | % | — | % |
Item 3. | Quantitative and Qualitative Disclosures About Market Risk. |
Average | Weighted | |||||||||||||||
Volume Per | Average | Fair Value | ||||||||||||||
Instrument | Day | Price | Asset | Liability | ||||||||||||
Crude Oil: | (barrels) | ($/barrel) | ||||||||||||||
Second quarter 2018 | Swaps-WTI | 6,484 | $ | 51.09 | $ | — | $ | 7,888 | ||||||||
Second quarter 2018 | Swaps-LLS | 2,500 | $ | 55.18 | — | 2,735 | ||||||||||
Third quarter 2018 | Swaps-WTI | 6,455 | $ | 51.10 | — | 6,998 | ||||||||||
Third quarter 2018 | Swaps-LLS | 2,500 | $ | 55.18 | — | 2,404 | ||||||||||
Fourth quarter 2018 | Swaps-WTI | 6,455 | $ | 51.10 | — | 5,960 | ||||||||||
Fourth quarter 2018 | Swaps-LLS | 2,500 | $ | 55.18 | — | 2,003 | ||||||||||
First quarter 2019 | Swaps-WTI | 4,946 | $ | 52.03 | — | 3,372 | ||||||||||
First quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 2,422 | ||||||||||
Second quarter 2019 | Swaps-WTI | 4,921 | $ | 52.04 | — | 2,861 | ||||||||||
Second quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 2,144 | ||||||||||
Third quarter 2019 | Swaps-WTI | 4,897 | $ | 52.05 | — | 2,404 | ||||||||||
Third quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 1,897 | ||||||||||
Fourth quarter 2019 | Swaps-WTI | 4,898 | $ | 52.05 | — | 2,011 | ||||||||||
Fourth quarter 2019 | Swaps-LLS | 2,500 | $ | 51.30 | — | 1,660 | ||||||||||
First quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 1,123 | ||||||||||
Second quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 866 | ||||||||||
Third quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 650 | ||||||||||
Fourth quarter 2020 | Swaps-WTI | 4,000 | $ | 52.67 | — | 461 | ||||||||||
Settlements to be paid in subsequent period | 3,037 |
Change of $10.00 per Bbl of Crude Oil or $1.00 per MMBtu of Natural Gas ($ in millions) | |||||||
Increase | Decrease | ||||||
Effect on the fair value of crude oil derivatives 1 | $ | (67.6 | ) | $ | 61.4 | ||
Effect of crude oil price changes for the remainder of 2018 on operating income, excluding derivatives 2 | $ | 97.6 | $ | (97.6 | ) | ||
Effect of natural gas price changes for the remainder of 2018 on operating income 2 | $ | 48.1 | $ | (48.1 | ) |
1 | Based on derivatives outstanding as of March 31, 2018. |
2 | These sensitivities are subject to significant change. |
Item 4. | Controls and Procedures. |
Item 1. | Legal Proceedings. |
Item 1A. | Risk Factors. |
Item 6. | Exhibits. |
(3.1) | Third Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on January 19, 2018). |
(10.1) | Support Agreement, dated January 18, 2018 by and among Penn Virginia Corporation, Strategic Value Partners, LLC and certain funds and accounts managed by Strategic Value Partners, LLC (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on January 19, 2018). |
(10.2) | Separation and Consulting Agreement dated January 18, 2018 by and among Penn Virginia Corporation and Harry Quarls (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on January 19, 2018). |
(10.3) | Master Assignment, Agreement and Amendment No. 4 to Credit Agreement, dated as of March 1, 2018, 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 March 7, 2018). |
(31.1) * | Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
(31.2) * | Certification Pursuant to Rule 13a-14(a), 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 | |||
May 9, 2018 | By: | /s/ STEVEN A. HARTMAN | |
Steven A. Hartman | |||
Senior Vice President, Chief Financial Officer and Treasurer | |||
(Principal Financial Officer) | |||
May 9, 2018 | By: | /s/ TAMMY L. HINKLE | |
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 | |
President and Chief 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 | |
President and Chief 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 |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
May 04, 2018 |
|
Document Documentand Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2018 | |
Document Fiscal Period Focus | Q1 | |
Trading Symbol | PVAC | |
Entity Registrant Name | PENN VIRGINIA CORP | |
Entity Central Index Key | 0000077159 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Current Reporting Status | Yes | |
Entity Voluntary Filers | No | |
Entity Filer Category | Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 15,058,480 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Statement of Comprehensive Income [Abstract] | ||
Net income (loss) | $ 10,295 | $ 28,081 |
Other comprehensive loss: | ||
Change in pension and postretirement obligations, net of tax of $0 and $0 in 2016 | 0 | 0 |
Total Other Comprehensive Income (Loss), Net of Tax | 0 | 0 |
Comprehensive income (loss) | $ 10,295 | $ 28,081 |
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Statement of Comprehensive Income [Abstract] | ||
Change in pension and postretirement obligations, net of tax | $ 0 | $ 0 |
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
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 | 15,058,210 | 15,018,870 |
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 |
3 Months Ended |
---|---|
Mar. 31, 2018 | |
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 and revenues and all of our capital expenditures attributable to this region. We also have less significant operations in Oklahoma, primarily consisting of non-operated properties in the Granite Wash. |
Basis of Presentation |
3 Months Ended |
---|---|
Mar. 31, 2018 | |
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, 2017. Operating results for the three months ended March 31, 2018, are not necessarily indicative of the results that may be expected for the year ending December 31, 2018. Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2018, we adopted and began applying the relevant guidance provided in Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”). ASU 2017–07 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 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. As required, ASU 2017–07 has been applied retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, which was less than $0.1 million, has been included as a component of the “Other income (expense)” caption in our Consolidated Statement of Operations for the three months ended March 31, 2017. Prior to 2018, all costs associated with these plans were included in the “General and administrative” (“G&A”) expenses caption. Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and with related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification Topic 606 Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASCO Topic 606. Recently Issued Accounting Pronouncements Pending Adoption 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 which have a higher credit risk than those associated with our traditional customer receivables. 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 continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. 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 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way 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 on the effective date in 2019. We are also continuing to monitor developments regarding ASU 2016–02 that are unique to our industry. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements 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 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. |
Acquisitions and Divestitures (Notes) |
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Acquisitions And Dispositions Disclosure [Text Block] | Acquisitions and Divestitures Acquisitions Hunt Acquisition In December 2017, we entered into a purchase and sale agreement with Hunt Oil Company (“Hunt”) to acquire certain oil and gas assets in the Eagle Ford Shale, primarily in Gonzales and Lavaca Counties, Texas for $86.0 million in cash, subject to adjustments (the “Hunt Acquisition”). The Hunt Acquisition has an effective date of October 1, 2017 and closed on March 1, 2018, at which time we paid cash consideration of $84.4 million. In connection with the Hunt Acquisition, we also acquired working interests in certain wells that we previously drilled as operator in which Hunt had rights to participate prior to the transaction closing. Accumulated costs, net of suspended revenues for these wells was $13.8 million which we have reflected as a component of the total net assets acquired. We funded the Hunt Acquisition with borrowings under our credit agreement (the “Credit Facility”). The Hunt Acquisition expands our core net leasehold position by approximately 9,700 net acres, substantially all of which is held by production, in the northwestern portion of our Eagle Ford acreage. As a result of the Hunt Acquisition we are the operator of substantially all of our Eagle Ford acreage. We incurred a total of $0.5 million of transaction costs for legal, due diligence and other professional fees associated with the Hunt Acquisition, including $0.1 million in 2017 and $0.4 million in the first quarter of 2018. These costs have been recognized as a component of our G&A expenses. We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the preliminary fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to Hunt:
Devon Acquisition In July 2017, we entered into a purchase and sale agreement (the “Purchase Agreement”) with Devon Energy Corporation (“Devon”) to acquire all of Devon’s right, title and interest in and to certain oil and gas assets (the “Devon Properties”), including oil and gas leases covering approximately 19,600 net acres located primarily in Lavaca County, Texas for aggregate consideration of $205 million in cash (the “Devon Acquisition”). Upon execution of the Purchase Agreement, we deposited $10.3 million as earnest money into an escrow account (the “Escrow Account”). The Devon Acquisition has an effective date of March 1, 2017 and closed on September 29, 2017, at which time we paid cash consideration of $189.9 million and $7.1 million was released from the Escrow Account to Devon. In November 2017, we acquired additional working interests in the Devon Properties for $0.7 million from parties that had tag-along rights to sell their interests under the Purchase Agreement. As of December 31, 2017, $3.2 million remained in the Escrow Account, which was included as a component of noncurrent “Other assets” on our Condensed Consolidated Balance Sheet. The final settlements of the Devon Acquisition together with the tag-along rights acquisition, occurred in February 2018 at which time $2.5 million in cash was transferred from the Escrow Account to Devon and the remaining $0.7 million was distributed to us. In addition, Devon transferred $0.3 million to us for suspended revenues attributable to the acquired properties. The Devon Acquisition was financed with the net proceeds received from borrowings under the $200 million Second Lien Credit Agreement dated as of September 29, 2017 (the “Second Lien Facility”) (see Note 8 for terms of the Second Lien Facility) and incremental borrowings under the Credit Facility. The Devon Properties include increases in working interests of many properties for which we are the operator as well as other properties that are contiguous to our existing asset base in South Texas. We incurred a total of $1.0 million of transaction costs in 2017 associated with the Devon Acquisition, including advisory, legal, due diligence and other professional fees. These costs have been recognized as a component of our G&A expenses. We accounted for the Devon Acquisition by applying the acquisition method of accounting as of September 29, 2017. The following table represents the final fair values assigned to the net assets acquired and the total consideration transferred:
Valuation of Acquisitions The fair values of the oil and gas properties acquired in the Hunt and Devon Acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future cash flows (v) the timing of our development plans and (vi) a market-based weighted-average cost of capital. The fair value of the other property and equipment acquired was measured primarily with reference to replacement costs for similar assets adjusted for the age and normal use of the underlying assets. Because many of these inputs are not observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in GAAP. Impact of Acquisitions on Actual and Pro Forma Results of Operations The results of operations attributable to the Hunt Acquisition and Devon Acquisition have been included in our Consolidated Financial Statements for the periods after March 1, 2018 and after September 29, 2017, respectively. The Hunt Acquisition provided revenues and estimated earnings (including revenues less operating expenses and excluding allocations of interest expense and income taxes) of approximately $0.4 million and $0.2 million, respectively, for the period from March 1, 2018 through March 31, 2018. As the properties and working interests acquired in connection with the Hunt and Devon Acquisitions are included within our existing Eagle Ford acreage, it is not practical or meaningful to disclose revenues and earnings unique to those assets for periods beyond those during which they were acquired as they were fully integrated into our regional operations soon after their acquisition. The following table presents unaudited summary pro forma financial information for the three months ended March, 31, 2018 and 2017 assuming the Hunt and Devon Acquisitions and the related entry into the Second Lien Facility occurred as of January 1, 2017. The pro forma financial information does not purport to represent what our actual results of operations would have been if the Hunt and Devon Acquisitions and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods.
Divestitures In February 2018, we sold our undeveloped acreage holdings in the Tuscaloosa Marine Shale in Louisiana that were scheduled to expire in 2019 and in March 2018 we sold certain undeveloped deep leasehold rights in Oklahoma. We received a combined total of $1.6 million for these leasehold assets which were applied as a reduction of our net oil and gas properties. |
Bankruptcy Proceeding Bankruptcy Proceedings |
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Mar. 31, 2018 | |
Reorganizations [Abstract] | |
Reorganization under Chapter 11 of US Bankruptcy Code Disclosure [Text Block] | Bankruptcy Proceedings and Emergence On May 12, 2016, 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 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 “Emergence Date”). Effective January 17, 2018, the Bankruptcy Court closed the eight cases attributable to our subsidiaries, leaving the aforementioned lead case open pending the entry of a final decree or order by the Bankruptcy Court. While our emergence from bankruptcy is effectively complete, certain administrative and claims resolution activities will continue under the authority of the Bankruptcy Court until they have been appropriately discharged. As of May 4, 2018, certain claims were still in the process of resolution. While most of these matters are unsecured claims for which shares of our common stock have been allocated, certain of these matters must be settled with cash payments. As of March 31, 2018, 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 |
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Accounts Receivable and Major Customers | Accounts Receivable and Revenues from Contracts with Customers Accounts Receivable and Major Customers The following table summarizes our accounts receivable by type as of the dates presented:
For the three months ended March 31, 2018, three customers accounted for $70.6 million, or approximately 91%, of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2018 were $31.0 million, $26.4 million and $13.2 million, or 40%, 34% and 17% of the consolidated total, respectively. As of March 31, 2018 and December 31, 2017, $38.8 million and $32.1 million, or approximately 89% and 82%, 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. For the three months ended March 31, 2017, one customer accounted for $31.2 million, or approximately 90%, of our consolidated product revenues. Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contacts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote-off $2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018 and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018:
Accounting Policies for Revenue Recognition and Associated Costs Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs. We have natural gas processing contracts in place with certain midstream processing vendors in our two primary operating regions. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018 and through March 31, 2018, we are the agent and our midstream processing vendors are our customers with respect to all of our NGL product sales. Natural gas. Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services. We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606 which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our joint venture partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. |
Derivative Instruments |
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Derivative Instruments | Derivative Instruments We utilize derivative instruments to mitigate our financial exposure to commodity 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 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 (“WTI”) crude oil and Louisiana Light Sweet (“LLS”) 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 are currently unhedged with respect to NGL and natural gas production. The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of March 31, 2018:
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 are reported as adjustments to reconcile net income 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 presented on a gross basis, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:
As of March 31, 2018, we reported total commodity derivative liabilities of $52.9 million. The contracts associated with this position are with five counterparties, all 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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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 $137.7 million and $117.6 million have been excluded from amortization as of March 31, 2018 and December 31, 2017, respectively. We transferred less than $0.1 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 three months ended March 31, 2018. We capitalized internal costs of $0.7 million and $0.6 million and interest of $2.2 million and less than $0.1 million during the three months ended March 31, 2018 and 2017, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization (“DD&A”) per barrel of oil equivalent of proved oil and gas properties was $15.20 and $11.47 for the three months ended March 31, 2018 and 2017, respectively. |
Long-Term Debt |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt | Long-Term Debt The following table summarizes our debt obligations as of the dates presented:
_______________________ 1 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method.
Credit Facility On the Emergence Date, we entered into the Credit Facility. The Credit Facility provides for a $340.0 million revolving commitment and borrowing base and a $5 million sublimit for the issuance of letters of credit. In March 2018, the borrowing base under the Credit Facility was redetermined from $237.5 million to $340.0 million pursuant to the Master Assignment, Agreement and Amendment No. 4 to the Credit Facility (the “Fourth Amendment”). In the three months ended March 31, 2018, we paid and capitalized issue costs of $0.7 million in connection with the Fourth Amendment. 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 April 2018 redetermination was accelerated to March in connection with the Hunt Acquisition. The Credit Facility is available to us for general corporate purposes including working capital. The Credit Facility matures in September 2020. We had $0.8 million in letters of credit outstanding as of March 31, 2018 and December 31, 2017. 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 March 31, 2018, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 5.34%. 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. There are no significant restrictions on our ability 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 of 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 March 31, 2018, and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with all of the covenants under the Credit Facility. Second Lien Facility On September 29, 2017, we entered into the $200 million Second Lien Facility. We received net proceeds of $187.8 million from the Second Lien Facility net of an original issue discount (“OID”) of $4.0 million and issue costs of $8.2 million. The proceeds from the Second Lien Facility were used to fund the Devon Acquisition and related fees and expenses. The maturity date under the Second Lien Facility is September 29, 2022. The outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 6.00% or (b) a customary LIBOR rate plus an applicable margin of 7.00%. As of March 31, 2018, the actual interest rate of outstanding borrowings under the Second Lien Facility was 8.88%. Amounts under the Second Lien Facility were borrowed at a price of 98% with an initial interest rate of 8.34% resulting in an effective interest rate of 9.89%. 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 eurocurrency borrowings is payable every one or three months (including in three month intervals if we select a six month interest period), at our election and is computed on the basis of a 360-day year. We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to eurocurrency loans): during year one, a customary “make-whole” premium; during year two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: during years one and two, 102% of the amount being prepaid; during year three, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility is collateralized by substantially all of the Company’s and its subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by us and the subsidiary guarantors. The Second Lien Facility has no financial covenants, but 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 and transactions with affiliates and other customary covenants. As illustrated in the table above, the OID and issue costs of the Second Lien Facility are presented as reductions to the outstanding term loans. These costs are subject to amortization using the interest method over the five-year term of the Second Lien Facility. As of March 31, 2018, and through the date upon which the Consolidated Financial Statements were issued, we were in compliance with all of the covenants under the Second Lien Facility. |
Income Taxes |
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Mar. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes On December 22, 2017, the U.S. Congress enacted comprehensive tax legislation as part of the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (the “TCJA”). The TCJA makes broad and complex changes to the U.S. tax code, including but not limited to, (i) the requirement to pay a one-time transition tax on all undistributed earnings of foreign subsidiaries; (ii) reducing the U.S. federal corporate income tax rate from 35% to 21%; (iii) generally eliminating U.S. federal income taxes on dividends from foreign subsidiaries; (iv) allowing the immediate deduction of certain new investments in lieu of depreciation expense over time; (v) creating a new limitation on deductible interest expense; (vi) changing rules related to use and limitations of net operating loss (“NOL”) carryforwards created in tax years beginning after December 31, 2017 and (vii) repeal of the corporate alternative minimum tax (“AMT”). In connection with our initial analysis of the impact of the TCJA, our Condensed Consolidated Balance Sheet as of December 31, 2017 included a deferred tax asset of $4.9 million attributable to our AMT credit carryforwards that were previously fully reserved, but became realizable in connection with the AMT provisions of the TCJA. We continue to analyze the impacts of the TCJA on the Company and refine our estimates during 2018. We recognized a federal and state income tax expense for the three months ended March 31, 2018 at the blended rate of 21.6%; however, the federal and state tax expense was offset by an adjustment to the valuation allowance against our net deferred tax assets along with an adjustment of $0.2 million to the deferred tax asset related to sequestration of a portion of the aforementioned AMT credit carryforward resulting in an effective tax rate of 1.6%. The effect of the adjustment was to reduce our deferred tax asset to $4.8 million as of March 31, 2018. We recognized a federal income tax benefit for the three months ended March 31, 2017 at the blended rate of 35.2% 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 had no liability for unrecognized tax benefits as of March 31, 2018. There were no interest and penalty charges recognized during the periods ended March 31, 2018 and 2017. Tax years from 2013 forward remain open for examination by the Internal Revenue Service and various state jurisdictions. |
Executive Retirement |
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Mar. 31, 2018 | |
Restructuring and Related Activities [Abstract] | |
Exit Activities | Executive Retirement Effective February 28, 2018, Mr. Harry Quarls retired from his position as a director and Executive Chairman of the Company. In connection with his retirement, we entered into a separation and consulting agreement (“Separation Agreement”) whereby Mr. Quarls will provide transition and support services to us through December 31, 2018. We paid Mr. Quarls $0.3 million for such services and a mutually agreed-upon amount for any services in excess of a minimum level established in the Separation Agreement. The Separation Agreement included a general release of claims, and provided for the accelerated vesting of certain share-based compensation awards for which we recognized expense of $0.6 million during the three months ended March 31, 2018 (see Note 15). The costs associated with the Separation Agreement, including the share-based compensation charges, are included as a component of G&A expenses in our Condensed Consolidated Statements of Operation. |
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:
_______________________ 1 Represents the amount remaining in the Escrow Account for the Devon Acquisition which was utilized to fund the remaining liabilities due to Devon for the final settlement in March 2018 (see Note 3). |
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 the 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 and Second Lien Facility borrowings. As of March 31, 2018, 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 three months ended March 31, 2018 and 2017. We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:
Non-Recurring Fair Value Measurements In addition to the fair value measurements applied with respect to the Hunt and Devon Acquisitions, as described in Note 3, 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. |
Commitments and Contingencies |
3 Months Ended |
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Mar. 31, 2018 | |
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 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 (“MVC”) 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 (gross) to Republic, or to 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 attributable to the MVC under the gathering and transportation agreement are as follows: $7.9 million for the remainder of 2018, $11.7 million for 2019, $13.0 million per year for 2020 through 2025, $7.4 million for 2026, $3.8 million per year for 2027 through 2030 and $2.2 million for 2031. Drilling and Completion Commitments We have contractual commitments for three drilling rigs as of March 31, 2018 with terms expiring in August 2018, September 2018 and November 2018, respectively. We also have one-year purchase commitments for the utilization of certain frac services and the purchase of certain proppant materials. Both the frac services and materials commitments were effective January 1, 2018. We have approximately $37.0 million of combined 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 March 31, 2018, we continue to maintain a $0.1 million reserve for a litigation matter. As of March 31, 2018, we also had AROs of approximately $3.8 million attributable to the plugging of abandoned wells. |
Shareholders' Equity |
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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 the three months ended March 31, 2018:
_______________________ 1 Includes equity-classified share-based compensation of $1.6 million during the three months ended March 31, 2018. During the three months ended March 31, 2018, 37,845 and 1,495 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes, respectively. Also includes a write-off of $2.7 million for certain accounts receivable attributable to natural gas imbalances accounted for under the entitlements method prior to January 1, 2018 in accordance with the adoption of ASC Topic 606 (see Note 5). |
Share-Based Compensation and Other Benefit Plans |
3 Months Ended |
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Mar. 31, 2018 | |
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 G&A expenses in our Condensed Consolidated Statements of Operations. We reserved 749,600 shares of common stock for issuance under the Penn Virginia Corporation Management Incentive Plan for future share-based compensation awards. A total of 310,700 RSUs and 98,526 PRSUs have been granted as of March 31, 2018. We recognized $1.6 million and $0.8 million of expense attributable to the RSUs and PRSUs for the three months ended March 31, 2018 and 2017, respectively. Approximately $0.6 million of the expense for the 2018 period was attributable to the accelerated vesting of certain awards of our former Executive Chairman. In the three months ended March 31, 2018 and 2017, we granted 5,719 and 146,834 RSUs to certain employees with an average grant-date fair value of $36.52 and $51.71 per RSU, respectively. The RSUs are being charged to expense on a straight-line basis over a range of four to five years. In the three months ended March 31, 2018, 37,845 shares vested, net of shares withheld for income taxes. In the three months ended March 31, 2017, we granted 62,675 PRSUs to members of our management. No PRSUs were granted during the three months ended March 31, 2018. In the three months ended March 31, 2018, 1,495 shares vested, net of shares withheld for income taxes. Previously issued PRSUs were issued collectively in two to 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. Due to their market condition, the PRSUs are being charged to expense using graded vesting over a maximum of five years. The fair value of each PRSU award was estimated on their grant dates using a Monte Carlo simulation with a range of $47.70 to $65.28 per PRSU. Expected volatilities were based on historical volatilities and range from 59.63% to 62.18%. A risk-free rate of interest with a range of 1.44% to 1.51% 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 of expense attributable to the 401(k) Plan for each of the three months ended March 31, 2018 and 2017. The charges for the 401(k) Plan are recorded as a component of G&A expenses. 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 months ended March 31, 2018 and 2017. The charges for these plans are recorded as a component of “Other income (expense)” in our Condensed Consolidated Statements of Operation. |
Interest Expense |
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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 (Loss) per Share | Earnings per Share The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:
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Basis of Presentation (Policies) |
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Schedule of Policies [Line Items] | |||||
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, 2017. Operating results for the three months ended March 31, 2018, are not necessarily indicative of the results that may be expected for the year ending December 31, 2018. Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2018, we adopted and began applying the relevant guidance provided in Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”). ASU 2017–07 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 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. As required, ASU 2017–07 has been applied retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, which was less than $0.1 million, has been included as a component of the “Other income (expense)” caption in our Consolidated Statement of Operations for the three months ended March 31, 2017. Prior to 2018, all costs associated with these plans were included in the “General and administrative” (“G&A”) expenses caption. Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and with related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification Topic 606 Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASCO Topic 606. Recently Issued Accounting Pronouncements Pending Adoption 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 which have a higher credit risk than those associated with our traditional customer receivables. 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 continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. 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 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way 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 on the effective date in 2019. We are also continuing to monitor developments regarding ASU 2016–02 that are unique to our industry. Going Concern Presumption Our unaudited Condensed Consolidated Financial Statements 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 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. |
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Fair Value Measurements | We apply the authoritative accounting provisions for measuring the 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 and Second Lien Facility borrowings. As of March 31, 2018, the carrying values of all of these financial instruments approximated fair value. |
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New Accounting Pronouncements, Policy [Policy Text Block] | Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2018, we adopted and began applying the relevant guidance provided in Accounting Standards Update (“ASU”) 2017–07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (“ASU 2017–07”). ASU 2017–07 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 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. As required, ASU 2017–07 has been applied retrospectively to periods prior to 2018. Accordingly, the entirety of the expense associated with these plans, which was less than $0.1 million, has been included as a component of the “Other income (expense)” caption in our Consolidated Statement of Operations for the three months ended March 31, 2017. Prior to 2018, all costs associated with these plans were included in the “General and administrative” (“G&A”) expenses caption. Effective January 1, 2018, we adopted and began applying the relevant guidance provided in ASU 2014–09, Revenues from Contracts with Customers (“ASU 2014–09”) and with related amendments to GAAP which, together with ASU 2014–09, represent Accounting Standards Codification Topic 606 Revenues from Contracts with Customers (“ASC Topic 606”). We adopted ASC Topic 606 using the cumulative effect transition method (see Note 5 for the impact and disclosures associated with the adoption of ASCO Topic 606. Recently Issued Accounting Pronouncements Pending Adoption 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 which have a higher credit risk than those associated with our traditional customer receivables. 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 continuing to evaluate the requirements and the period for which we will adopt the standard as well as monitoring developments regarding ASU 2016–13 that are unique to our industry. 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 13, our existing leases for office facilities and certain office equipment, land easements and similar arrangements for rights-of-way 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 on the effective date in 2019. We are also continuing to monitor developments regarding ASU 2016–02 that are unique to our industry. |
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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 In addition to the fair value measurements applied with respect to the Hunt and Devon Acquisitions, as described in Note 3, 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. |
New Accounting Pronouncement (Policies) |
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Revenue from Contract with Customer [Text Block] | Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contacts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote-off $2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018 and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018:
Accounting Policies for Revenue Recognition and Associated Costs Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs. We have natural gas processing contracts in place with certain midstream processing vendors in our two primary operating regions. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018 and through March 31, 2018, we are the agent and our midstream processing vendors are our customers with respect to all of our NGL product sales. Natural gas. Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services. We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606 which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our joint venture partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018:
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Acquisitions and Divestitures (Tables) |
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Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | We accounted for the Devon Acquisition by applying the acquisition method of accounting as of September 29, 2017. The following table represents the final fair values assigned to the net assets acquired and the total consideration transferred:
We accounted for the Hunt Acquisition by applying the acquisition method of accounting as of March 1, 2018. The following table represents the preliminary fair values assigned to the net assets acquired and the total acquisition cost incurred, including consideration transferred to Hunt:
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Business Acquisition, Pro Forma Information [Table Text Block] | The pro forma financial information does not purport to represent what our actual results of operations would have been if the Hunt and Devon Acquisitions and the entry into the Second Lien Facility had occurred as of this date, or the results of operations for any future periods.
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Accounts Receivable and Major Customers (Tables) |
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Revenue from Contract with Customer [Text Block] | Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contacts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote-off $2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018 and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018:
Accounting Policies for Revenue Recognition and Associated Costs Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs. We have natural gas processing contracts in place with certain midstream processing vendors in our two primary operating regions. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018 and through March 31, 2018, we are the agent and our midstream processing vendors are our customers with respect to all of our NGL product sales. Natural gas. Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services. We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606 which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our joint venture partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018:
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Summary of Accounts Receivable | The following table summarizes our accounts receivable by type as of the dates presented:
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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, presented on a net basis by period of maturity, as of March 31, 2018:
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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 presented on a gross basis, 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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Mar. 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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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Long-Term Debt Long-Term Debt (Tables) |
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Debt Instrument [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Long-term Debt Instruments [Table Text Block] | The following table summarizes our debt obligations 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:
_______________________ 1 Represents the amount remaining in the Escrow Account for the Devon Acquisition which was utilized to fund the remaining liabilities due to Devon for the final settlement in March 2018 (see Note 3). |
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 the three months ended March 31, 2018:
_______________________ 1 Includes equity-classified share-based compensation of $1.6 million during the three months ended March 31, 2018. During the three months ended March 31, 2018, 37,845 and 1,495 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes, respectively. Also includes a write-off of $2.7 million for certain accounts receivable attributable to natural gas imbalances accounted for under the entitlements method prior to January 1, 2018 in accordance with the adoption of ASC Topic 606 (see Note 5). |
Interest Expense (Tables) |
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Interest Expense Net Disclosure | The following table summarizes the components of interest expense for the periods presented:
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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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Components of Calculation of Basic and Diluted Earnings Per Share | The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:
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Revenue with Customers (Tables) |
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Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue from Contract with Customer [Text Block] | Revenue from Contracts with Customers Adoption of ASC Topic 606 Effective January 1, 2018, we adopted ASC Topic 606 and have applied the guidance therein to our contacts with customers for the sale of commodity products (crude oil, NGLs and natural gas) as well as marketing services that we provide to our joint venture partners and other third parties. ASC Topic 606 provides for a five-step revenue recognition process model to determine the transfer of goods or services to consumers in an amount that reflects the consideration to which we expect to be entitled in exchange for such goods and services. Upon the adoption of ASC Topic 606, we: (i) changed the presentation of our NGL product revenues from a gross basis to a net basis and changed the classification of certain natural gas processing costs associated with NGLs from a component of “Gathering, processing and transportation” (“GPT”) expense to a reduction of NGL product revenues as described in further detail below, (ii) wrote-off $2.7 million of accounts receivable arising from natural gas imbalances accounted for under the entitlements method as a direct reduction to our beginning balance of retained earnings as of January 1, 2018 and (iii) adopted the sales method with respect to production imbalance transactions beginning after December 31, 2017. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018:
Accounting Policies for Revenue Recognition and Associated Costs Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of GPT expense. NGLs. We have natural gas processing contracts in place with certain midstream processing vendors in our two primary operating regions. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors, particularly those attributable to the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues based on a net basis with processing costs presented as a reduction of revenue. Based on an analysis of all of our existing natural gas processing contracts, we have determined that, as of January 1, 2018 and through March 31, 2018, we are the agent and our midstream processing vendors are our customers with respect to all of our NGL product sales. Natural gas. Subsequent to the aforementioned processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing services. We provide marketing services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a negotiated fixed rate fee based on the sales price of the underlying oil and gas products. Production attributable to joint venture partners from wells that we operate that are not subject to marketing agreements are delivered in kind. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers. Direct costs associated with our marketing efforts are included in G&A expenses. Transaction Prices, Contract Balances and Performance Obligations Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. Accordingly, we have applied the practical expedient included in ASC Topic 606 which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied as described above. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities as those terms are defined in ASC Topic 606. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production, particularly from properties that are operated by our joint venture partners. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. The following table illustrates the impact of the the adoption of ASC Topic 606 on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2018:
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Nature of Operations Nature of Operations (Details) |
3 Months Ended |
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Mar. 31, 2018 | |
TEXAS | Eagle Ford Shale | |
Concentration Risk [Line Items] | |
Concentration risk, percentage (more than) | 90.00% |
Basis of Presentation (Details) - USD ($) $ / shares in Units, $ in Thousands |
3 Months Ended | |
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Mar. 31, 2018 |
Mar. 31, 2017 |
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Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Oil and Condensate Revenue | $ 2,946 | $ 2,302 |
Basic (in dollars per share) | $ 0.68 | $ 1.87 |
Diluted (in dollars per share) | $ 0.68 | $ 1.86 |
Gas Gathering, Transportation, Marketing and Processing Costs | $ 3,359 | $ 2,551 |
Other Pension, Postretirement and Supplemental Plans [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Pension and Other Postretirement Benefits Cost (Reversal of Cost) | $ 100 | $ 100 |
Bankruptcy Proceeding Bankruptcy Proceeding (Details) $ in Thousands |
May 12, 2016
subsidiary
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Mar. 31, 2018
USD ($)
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Dec. 31, 2017
USD ($)
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Reorganizations [Abstract] | |||
Number of Subsidiaries Filing Chapter 11 Bankruptcy | subsidiary | 8 | ||
Bankruptcy Claims, amount reserved for outstanding claims | $ | $ 3,933 | $ 3,933 |
Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
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Receivables [Abstract] | ||
Customers | $ 43,764 | $ 39,106 |
Joint interest partners | 13,808 | 32,493 |
Other | 747 | 584 |
Accounts Receivable, Gross, Current, Total | 58,319 | 72,183 |
Less: Allowance for doubtful accounts | (2,362) | (2,362) |
Accounts receivable, net of allowance for doubtful accounts | $ 55,957 | $ 69,821 |
Accounts Receivable and Major Customers - Additional Information (Detail) $ in Millions |
3 Months Ended | 12 Months Ended | |
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Mar. 31, 2018
USD ($)
Customer
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Mar. 31, 2017
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Customer
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Dec. 31, 2017
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Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Document Period End Date | Mar. 31, 2018 | ||
Sales Revenue | Customer Concentration Risk [Member] | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Number of major customers | Customer | 3 | 1 | |
Revenues, major customers | $ 70.6 | $ 31.2 | |
Concentration risk, percentage | 91.00% | 90.00% | |
Sales Revenue | Customer Concentration Risk [Member] | Major Customer 1 | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Revenues, major customers | $ 31.0 | ||
Concentration risk, percentage | 40.00% | ||
Sales Revenue | Customer Concentration Risk [Member] | Major Customer 2 | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Revenues, major customers | $ 26.4 | ||
Concentration risk, percentage | 34.00% | ||
Sales Revenue | Customer Concentration Risk [Member] | Major Customer Three [Member] | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Revenues, major customers | $ 13.2 | ||
Concentration risk, percentage | 17.00% | ||
Accounts Receivable | Credit Concentration Risk | |||
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Concentration risk, percentage | 89.00% | 82.00% | |
Accounts receivable, major customers | $ 38.8 | $ 32.1 |
Accounts Receivable and Major Customers Revenue from Contracts with Customers (Details) - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Exploration and Production Revenue | $ 71,258 | $ 30,073 |
Oil and Condensate Revenue | 2,946 | 2,302 |
Natural Gas Production Revenue | 2,790 | 2,343 |
Refining and Marketing Revenue | 92 | |
Gas Gathering, Transportation, Marketing and Processing Costs | 3,359 | 2,551 |
Net Income (Loss) Available to Common Stockholders, Basic | 10,295 | $ 28,081 |
Calculated under Revenue Guidance in Effect before Topic 606 [Member] | ||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Exploration and Production Revenue | 71,258 | |
Oil and Condensate Revenue | 3,392 | |
Natural Gas Production Revenue | 2,790 | |
Refining and Marketing Revenue | 92 | |
Gas Gathering, Transportation, Marketing and Processing Costs | 3,805 | |
Net Income (Loss) Available to Common Stockholders, Basic | 10,295 | |
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | ||
Revenue, Initial Application Period Cumulative Effect Transition [Line Items] | ||
Exploration and Production Revenue | 0 | |
Oil and Condensate Revenue | 446 | |
Natural Gas Production Revenue | 0 | |
Refining and Marketing Revenue | 0 | |
Gas Gathering, Transportation, Marketing and Processing Costs | 446 | |
Net Income (Loss) Available to Common Stockholders, Basic | $ 0 |
Derivative Instruments - Additional Information (Detail) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018
USD ($)
Entity
|
Dec. 31, 2017
USD ($)
|
|
Derivative Instruments and Hedging Activities Disclosure [Line Items] | ||
Derivative assets | $ 52,928 | $ 41,677 |
Commodity contracts | ||
Derivative Instruments and Hedging Activities Disclosure [Line Items] | ||
Derivative assets | $ 52,900 | |
Number of derivative counterparties | Entity | 5 | |
Commodity contracts | Crude Oil | ||
Derivative Instruments and Hedging Activities Disclosure [Line Items] | ||
Third-party quoted forward prices | West Texas Intermediate (“WTI”) crude oil |
Commodity Derivative Positions (Detail) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018
USD ($)
bbl
$ / bbl
|
Dec. 31, 2017
USD ($)
|
|
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Derivative Liability | $ 52,928 | $ 41,677 |
Settlement Agreement [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Fair Value Asset | ||
Fair Value Liability | $ 3,037 | |
Crude Oil | Second Quarter 2018 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 6,484 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.09 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 7,888 | |
Crude Oil | Third Quarter 2018 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 6,455 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.10 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 6,998 | |
Crude Oil | Fourth Quarter 2018 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 6,455 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.10 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 5,960 | |
Crude Oil | First Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,946 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.03 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 3,372 | |
Crude Oil | Second Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,921 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.04 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,861 | |
Crude Oil | Third Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,897 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.05 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,404 | |
Crude Oil | Fourth Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,898 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.05 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,011 | |
Crude Oil | First Quarter 2020 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,000 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.67 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 1,123 | |
Crude Oil | Second Quarter 2020 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,000 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.67 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 866 | |
Crude Oil | Third Quarter 2020 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,000 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.67 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 650 | |
Crude Oil | Fourth Quarter 2020 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Notional Volume, per day | bbl | 4,000 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 52.67 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 461 | |
Louisiana Light Sweet [Member] | Second Quarter 2018 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Instrument | Swaps-LLS | |
Notional Volume, per day | bbl | 2,500 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 55.18 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,735 | |
Louisiana Light Sweet [Member] | Third Quarter 2018 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Instrument | Swaps-LLS | |
Notional Volume, per day | bbl | 2,500 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 55.18 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,404 | |
Louisiana Light Sweet [Member] | Fourth Quarter 2018 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Instrument | Swaps-LLS | |
Notional Volume, per day | bbl | 2,500 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 55.18 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,003 | |
Louisiana Light Sweet [Member] | First Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Instrument | Swaps-LLS | |
Notional Volume, per day | bbl | 2,500 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.30 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,422 | |
Louisiana Light Sweet [Member] | Second Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Instrument | Swaps-LLS | |
Notional Volume, per day | bbl | 2,500 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.30 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 2,144 | |
Louisiana Light Sweet [Member] | Third Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Instrument | Swaps-LLS | |
Notional Volume, per day | bbl | 2,500 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.30 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 1,897 | |
Louisiana Light Sweet [Member] | Fourth Quarter 2019 [Member] | ||
Derivative Instruments Related to Oil and Gas Production [Line Items] | ||
Instrument | Swaps-LLS | |
Notional Volume, per day | bbl | 2,500 | |
Derivative, Swap Type, Average Fixed Price | $ / bbl | 51.30 | |
Fair Value Asset | $ 0 | |
Fair Value Liability | $ 1,660 |
Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands |
3 Months Ended | |
---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivatives | $ (18,795) | $ 17,016 |
Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 36,820 | $ 27,777 |
Derivative Asset, Noncurrent | 32 | 0 |
Derivative assets | 32 | 0 |
Derivative Liability, Noncurrent | 16,108 | 13,900 |
Derivative Liability | 52,928 | 41,677 |
Commodity contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability | 52,900 | |
Commodity contracts | Current Derivative Contract [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Current | 0 | 0 |
Derivative liabilities | 36,820 | 27,777 |
Commodity contracts | Noncurrent Derivative Contract [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Noncurrent | 32 | 0 |
Derivative Liability, Noncurrent | $ 16,108 | $ 13,900 |
Summary of Property and Equipment (Detail) $ in Thousands |
3 Months Ended | ||
---|---|---|---|
Mar. 31, 2018
USD ($)
$ / bbl
|
Mar. 31, 2017
USD ($)
$ / bbl
|
Dec. 31, 2017
USD ($)
|
|
Property, Plant and Equipment [Abstract] | |||
Proved Oil and Gas Property, Full Cost Method | $ 624,747 | $ 460,029 | |
Unproved Oil and Gas Property, Full Cost Method | 137,722 | 117,634 | |
Oil and Gas Property, Full Cost Method, Gross | 762,469 | 577,663 | |
Other property and equipment | 13,702 | 12,712 | |
Total properties and equipment | 776,171 | 590,375 | |
Accumulated depreciation, depletion and amortization | (84,888) | (61,316) | |
Property and equipment, net (successful efforts method) | 691,283 | 529,059 | |
Unproved Oil and Gas Property excluded | 137,700 | $ 117,600 | |
Undeveloped Leasehold Costs Transferred | 100 | ||
Capitalized Costs, Proved Properties | 700 | $ 600 | |
Interest Costs Capitalized | $ 2,200 | $ 100 | |
Amortization Expense Per Physical Unit of Production | $ / bbl | 15.2 | 11.47 |
Summary of Long-Term Debt (Detail) - USD ($) |
Mar. 31, 2018 |
Dec. 31, 2017 |
Sep. 29, 2017 |
||
---|---|---|---|---|---|
Debt Instrument [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 237,500,000 | ||||
Revolving credit facility | [1] | 195,000,000 | $ 77,000,000 | ||
Second Lien Facility | 200,000,000 | 200,000,000 | $ 200,000,000 | ||
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums | 11,234,000 | 11,733,000 | |||
Debt Instrument, Unamortized Discount | (3,674,000) | (3,839,000) | (4,000,000) | ||
Unamortized Debt Issuance Expense | (7,560,000) | (7,894,000) | $ (8,200,000) | ||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | 383,766,000 | 265,267,000 | |||
Long-term Debt | 395,000,000 | $ 277,000,000 | |||
Revolving Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 340,000,000 | ||||
|
Long-Term Debt - Additional Information (Detail) - USD ($) |
3 Months Ended | 9 Months Ended | ||||
---|---|---|---|---|---|---|
Mar. 31, 2018 |
Sep. 30, 2017 |
Dec. 31, 2017 |
Sep. 29, 2017 |
|||
Debt Disclosure [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 237,500,000 | |||||
Debt Issuance Costs, Line of Credit Arrangements, Gross | 700,000 | |||||
Long-term Line of Credit | [1] | $ 195,000,000 | $ 77,000,000 | |||
Debt Instrument, Discounted Percentage | 98.00% | |||||
Interest Coverage Ratio, Maximum | 3.00 | |||||
Current Ratio | 1.00 | |||||
Second Lien Facility | $ 200,000,000 | 200,000,000 | $ 200,000,000 | |||
Proceeds from Debt, Net of Issuance Costs | $ 187,800,000 | |||||
Debt Instrument, Unamortized Discount | 3,674,000 | 3,839,000 | 4,000,000 | |||
Unamortized Debt Issuance Expense | $ 7,560,000 | 7,894,000 | $ 8,200,000 | |||
Year 2 [Member] | ||||||
Debt Disclosure [Line Items] | ||||||
Prepayment Premium | 102.00% | |||||
Prepayment Premium, Change in Control | 102.00% | |||||
Year 3 [Member] | ||||||
Debt Disclosure [Line Items] | ||||||
Prepayment Premium | 101.00% | |||||
Prepayment Premium, Change in Control | 101.00% | |||||
Revolving Credit Facility | ||||||
Debt Disclosure [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 340,000,000 | |||||
Interest Rate at Period End | 5.3407% | |||||
Revolving Credit Facility | Future Period Three [Member] | ||||||
Debt Disclosure [Line Items] | ||||||
Debt To E B I T D Ratio Maximum | 3.50 | |||||
Letter of Credit | ||||||
Debt Disclosure [Line Items] | ||||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | |||||
Line of Credit [Member] | ||||||
Debt Disclosure [Line Items] | ||||||
Letters of Credit Outstanding, Amount | $ 800,000 | $ 800,000 | ||||
Line of Credit [Member] | Letter of Credit | ||||||
Debt Disclosure [Line Items] | ||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 5,000,000.0 | |||||
Second Lien Facility [Member] | ||||||
Debt Disclosure [Line Items] | ||||||
Interest rate option one, applicable margin rate over Adjusted LIBOR | 7.00% | |||||
Interest rate option two, applicable margin rate | 6.00% | |||||
Second Lien Facility, Initial Interest Rate | 8.88% | 8.34% | ||||
Second Lien Facility, Effective Interest Rate | 9.89% | |||||
Minimum [Member] | Revolving Credit Facility | ||||||
Debt Disclosure [Line Items] | ||||||
Interest rate option one, applicable margin rate over Adjusted LIBOR | 2.00% | |||||
Interest rate option two, applicable margin rate | 3.00% | |||||
Maximum [Member] | Revolving Credit Facility | ||||||
Debt Disclosure [Line Items] | ||||||
Interest rate option one, applicable margin rate over Adjusted LIBOR | 3.00% | |||||
Interest rate option two, applicable margin rate | 4.00% | |||||
Interest Payable One [Member] | Revolving Credit Facility | ||||||
Debt Disclosure [Line Items] | ||||||
Debt Instrument, Interest Payable Period | 1 month | |||||
Interest Payable Two [Member] | Revolving Credit Facility | ||||||
Debt Disclosure [Line Items] | ||||||
Debt Instrument, Interest Payable Period | 3 months | |||||
Interest Payable Three [Member] | Revolving Credit Facility | ||||||
Debt Disclosure [Line Items] | ||||||
Debt Instrument, Interest Payable Period | 6 months | |||||
|
Income Taxes (Details) - USD ($) |
3 Months Ended | 12 Months Ended | |
---|---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
Dec. 31, 2017 |
|
Income Tax Disclosure [Abstract] | |||
Separation Agreement, Consulting Fees | $ 300,000 | ||
Blended tax rate (as a percent) | 21.60% | ||
Income Tax Expense (Benefit), Continuing Operations, Adjustment of Deferred Tax (Asset) Liability | $ 200,000 | ||
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent | 1.60% | ||
Federal statutory income tax rate (as a percent) | 2100.00% | 35.20% | 3500.00% |
Deferred Tax Assets, Net, Noncurrent | $ 4,780,000 | $ 4,943,000 | |
Income Tax Examination, Penalties and Interest Expense | 0 | $ 0 | |
Unrecognized Tax Benefits | $ 0 |
Executive Retirement (Detail) $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2018
USD ($)
| |
Restructuring and Related Activities [Abstract] | |
Separation Agreement, Consulting Fees | $ 0.3 |
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $ 0.6 |
Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
|||
---|---|---|---|---|---|
Other current assets: | |||||
Tubular inventory and well materials | $ 5,391 | $ 5,146 | |||
Prepaid expenses | 1,365 | 1,104 | |||
Other Assets, Current | 6,756 | 6,250 | |||
Other assets: | |||||
Deferred issuance costs of the Revolver | 3,268 | 2,857 | |||
Earnest Money Deposits | 0 | [1] | 3,210 | ||
Other | 5 | 2,440 | |||
Other assets | 3,273 | 8,507 | |||
Accounts payable and accrued liabilities: | |||||
Trade accounts payable | 17,223 | 22,579 | |||
Drilling costs | 32,005 | 22,389 | |||
Royalties and revenue – related | 34,995 | 39,287 | |||
Compensation – related | 1,791 | 2,975 | |||
Interest | 366 | 223 | |||
Reserve for bankruptcy claims | 3,933 | 3,933 | |||
Other | 6,821 | 4,795 | |||
Accounts payable and accrued liabilities | 97,134 | 96,181 | |||
Other liabilities: | |||||
Asset retirement obligations | 3,777 | 3,286 | |||
Defined benefit pension obligations | 940 | 971 | |||
Postretirement health care benefit obligations | 491 | 476 | |||
Other | 100 | 100 | |||
Other liabilities | $ 5,308 | $ 4,833 | |||
|
Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands |
Mar. 31, 2018 |
Dec. 31, 2017 |
---|---|---|
Assets: | ||
Derivative Asset, Noncurrent | $ 32 | $ 0 |
Liabilities: | ||
Commodity derivative liabilities – current | 36,820 | 27,777 |
Derivative Liability, Noncurrent | 16,108 | 13,900 |
Fair Value, Measurements, Recurring | Commodity contracts | ||
Assets: | ||
Derivative Asset, Noncurrent | 32 | |
Liabilities: | ||
Commodity derivative liabilities – current | 36,820 | 27,777 |
Derivative Liability, Noncurrent | 16,108 | 13,900 |
Fair Value, Measurements, Recurring | Commodity contracts | Level 1 | ||
Assets: | ||
Derivative Asset, Noncurrent | 0 | |
Liabilities: | ||
Commodity derivative liabilities – current | 0 | 0 |
Derivative Liability, Noncurrent | 0 | 0 |
Fair Value, Measurements, Recurring | Commodity contracts | Level 2 | ||
Assets: | ||
Derivative Asset, Noncurrent | 32 | |
Liabilities: | ||
Commodity derivative liabilities – current | 36,820 | 27,777 |
Derivative Liability, Noncurrent | 16,108 | 13,900 |
Fair Value, Measurements, Recurring | Commodity contracts | Level 3 | ||
Assets: | ||
Derivative Asset, Noncurrent | 0 | |
Liabilities: | ||
Commodity derivative liabilities – current | 0 | 0 |
Derivative Liability, Noncurrent | $ 0 | $ 0 |
Commitments and Contingencies - Additional Information (Detail) $ in Millions |
3 Months Ended |
---|---|
Mar. 31, 2018
USD ($)
bbl
| |
Commitments and Contingencies Disclosure [Line Items] | |
Long-term Purchase Commitment, Minimum Volume Required | bbl | 8,000 |
Marketing Agreement | 10 |
Asset Retirement Obligation | $ 3.8 |
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, Due in 2018 | 7.9 |
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 | $ 37.0 |
Shareholders' Equity Rollforward (Details) - USD ($) $ in Thousands |
3 Months Ended | ||||
---|---|---|---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
As of beginning balance | $ 221,639 | ||||
Net income (loss) | 10,295 | $ 28,081 | |||
All Other Changes | (1,670) | ||||
As of ending balance | 230,264 | ||||
Share-based compensation | 1,576 | $ 846 | |||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 2,700 | ||||
Common stock | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
As of beginning balance | 150 | ||||
All Other Changes | [1] | 1 | |||
As of ending balance | 151 | ||||
Paid-in capital | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
As of beginning balance | 194,123 | ||||
All Other Changes | [1] | 988 | |||
As of ending balance | 195,111 | ||||
Retained earnings | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
As of beginning balance | 27,366 | ||||
Net income (loss) | 10,295 | ||||
All Other Changes | [1] | (2,659) | |||
As of ending balance | 35,002 | ||||
Accumulated other comprehensive income | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
As of beginning balance | 0 | ||||
As of ending balance | $ 0 | ||||
Time Vested Restricted Stock Units [Domain] | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Shares, Issued | 37,845 | ||||
Performance Restricted Stock Units [Domain] | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Shares, Issued | 1,495 | ||||
|
Summary of Share-Based Compensation Expense (Detail) $ / shares in Units, $ in Thousands |
1 Months Ended | 3 Months Ended | |
---|---|---|---|
Jan. 31, 2017
tranche
|
Mar. 31, 2018
USD ($)
$ / shares
shares
|
Mar. 31, 2017
USD ($)
$ / shares
shares
|
|
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Share-based compensation (equity-classified) | $ | $ 1,576 | $ 846 | |
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $ | 600 | ||
Defined Contribution Plan, Cost | $ | 100 | 100 | |
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 | |
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 | 310,700 | ||
Shares, Issued | 37,845 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares | $ 36.52 | $ 51.71 | |
Time Vested Restricted Stock Units [Domain] | Minimum [Member] | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period | 4 years | ||
Time Vested Restricted Stock Units [Domain] | Maximum [Member] | |||
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items] | |||
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period | 5 years | ||
Performance restricted-Employees [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 | 98,526 | ||
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 | 0 | 62,675 | |
Shares, Issued | 1,495 | ||
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period | 5 years | ||
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 | 1.44% | ||
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate, Maximum | 1.51% | ||
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, Terms of Award | 0.5963 | ||
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche | 2 | ||
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, Terms of Award | 0.6218 | ||
Share-based Compensation Arrangements By Share-based Payment Award, Number Of Award Tranches | tranche | 3 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage | 200.00% | ||
Performance Restricted Stock Units [Domain] | Year 1 [Domain] | Minimum [Member] | |||
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 | $ 47.70 | ||
Performance Restricted Stock Units [Domain] | Share-based Compensation Award, Tranche Two [Member] | Maximum [Member] | |||
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 | ||
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 | 5,719 | 146,834 | |
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 | 749,600 |
Interest Expense Components of Interest Expense (Details) - USD ($) $ in Thousands |
3 Months Ended | ||||
---|---|---|---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
||||
Banking and Thrift [Abstract] | |||||
Interest Expense, Borrowings | $ 6,048 | $ 390 | |||
Amortization of Debt Discount (Premium) | 165 | [1] | 0 | ||
Amortization of Debt Issuance Costs | 631 | 188 | |||
Interest Paid, Capitalized | (2,243) | (40) | |||
Interest Expense | $ 4,601 | $ 538 | |||
|
Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Thousands, $ in Thousands |
3 Months Ended | |||
---|---|---|---|---|
Mar. 31, 2018 |
Mar. 31, 2017 |
|||
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items] | ||||
Net income (loss) | $ 10,295 | $ 28,081 | ||
Weighted-average shares – basic | 15,042 | 14,992 | ||
Effect of dilutive securities | [1] | 39 | 134 | |
Weighted-average shares – diluted | 15,081 | 15,126 | ||
Net Income (Loss) Available to Common Stockholders, Basic | $ 10,295 | $ 28,081 | ||
|