UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended March 31, 2017
Or
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period From to
Commission File Number 0-7406
PrimeEnergy Corporation
(Exact name of registrant as specified in its charter)
| Delaware | 84-0637348 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. employer Identification No.) |
9821 Katy Freeway, Houston, Texas 77024
(Address of principal executive offices)
(713) 735-0000
(Registrant’s telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer | ☐ | Accelerated Filer | ☐ | |||
| Non-Accelerated Filer | ☐ | Smaller Reporting Company | ☒ | |||
| Emerging growth company | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The number of shares outstanding of each class of the Registrant’s Common Stock as of May 11, 2017 was: Common Stock, $0.10 par value 2,280,138 shares.
Index to Form 10-Q
March 31, 2017
2
CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited
(Thousands of dollars, except per share amounts)
| March 31, 2017 |
December 31, 2016 |
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| ASSETS |
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| Current Assets |
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| Cash and cash equivalents |
$ | 12,010 | $ | 6,568 | ||||
| Restricted cash and cash equivalents |
3,543 | 3,543 | ||||||
| Accounts receivable, net |
8,560 | 7,400 | ||||||
| Other current assets |
724 | 572 | ||||||
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| Total Current Assets |
24,837 | 18,083 | ||||||
| Property and Equipment, at cost |
||||||||
| Oil and gas properties (successful efforts method), net |
194,302 | 187,490 | ||||||
| Field and office equipment, net |
8,300 | 8,878 | ||||||
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| Total Property and Equipment, Net |
202,602 | 196,368 | ||||||
| Other Assets |
337 | 203 | ||||||
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| Total Assets |
$ | 227,776 | $ | 214,654 | ||||
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| LIABILITIES AND EQUITY |
||||||||
| Current Liabilities |
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| Accounts payable |
$ | 11,094 | $ | 11,965 | ||||
| Accrued liabilities |
30,575 | 8,184 | ||||||
| Current portion of long-term debt |
3,206 | 2,949 | ||||||
| Current portion of asset retirements |
1,563 | 1,563 | ||||||
| Derivative Liability Short-term |
946 | 2,547 | ||||||
| Due to related parties |
386 | — | ||||||
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| Total Current Liabilities |
47,770 | 27,208 | ||||||
| Long-Term Bank Debt |
27,386 | 66,316 | ||||||
| Asset Retirement Obligations |
16,065 | 15,943 | ||||||
| Derivative Liability Long-Term |
44 | 1,092 | ||||||
| Deferred Income Taxes |
41,990 | 37,500 | ||||||
| Other Long-Term Obligations |
718 | 715 | ||||||
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| Total Liabilities |
133,973 | 148,744 | ||||||
| Commitments and Contingencies |
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| Equity |
||||||||
| Common stock, $.10 par value; Authorized: 4,000,000 shares, issued: 3,836,397 shares |
383 | 383 | ||||||
| Paid-in capital |
8,439 | 8,313 | ||||||
| Retained earnings |
118,619 | 96,322 | ||||||
| Treasury stock, at cost; 1,553,386 shares and 1,552,894 shares |
(46,498 | ) | (46,473 | ) | ||||
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| Total Stockholders’ Equity – PrimeEnergy |
80,943 | 58,545 | ||||||
| Non-controlling interest |
12,860 | 7,335 | ||||||
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| Total Equity |
93,803 | 65,880 | ||||||
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| Total Liabilities and Equity |
$ | 227,776 | $ | 214,654 | ||||
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The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements
3
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited
Three Months Ended March 31, 2017 and 2016
(Thousands of dollars, except per share amounts)
| 2017 | 2016 | |||||||
| Revenues |
||||||||
| Oil and gas sales |
$ | 12,438 | $ | 7,130 | ||||
| Realized (loss) on derivative instruments, net |
(227 | ) | — | |||||
| Field service income |
3,761 | 4,224 | ||||||
| Administrative overhead fees |
1,581 | 1,757 | ||||||
| Unrealized gain on derivative instruments, net |
2,804 | — | ||||||
| Other income |
118 | 51 | ||||||
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| Total Revenues |
20,475 | 13,162 | ||||||
| Costs and Expenses |
||||||||
| Lease operating expense |
7,140 | 8,012 | ||||||
| Field service expense |
2,982 | 3,560 | ||||||
| Depreciation, depletion, amortization and accretion on discounted liabilities |
7,938 | 5,275 | ||||||
| General and administrative expense |
1,736 | 2,431 | ||||||
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| Total Costs and Expenses |
19,796 | 19,278 | ||||||
| Gain on Sale and Exchange of Assets |
41,602 | 4,916 | ||||||
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| Income (Loss) Income from Operations |
42,281 | (1,200 | ) | |||||
| Interest Expense |
605 | 868 | ||||||
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| Income (Loss) Before Provision for Income Taxes |
41,676 | (2,068 | ) | |||||
| Provision (Benefit) for Income Taxes |
13,667 | (890 | ) | |||||
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| Net Income (Loss) |
28,009 | (1,178 | ) | |||||
| Less: Net Income Attributable to Non-Controlling Interests |
5,712 | 682 | ||||||
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| Net Income (Loss) Income Attributable to PrimeEnergy |
$ | 22,297 | $ | (1,860 | ) | |||
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| Basic Income (Loss) Income Per Common Share |
$ | 9.77 | $ | (0.81 | ) | |||
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| Diluted Income (Loss) Income Per Common Share |
$ | 7.35 | $ | (0.81 | ) | |||
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The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements
4
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – Unaudited
Three Months Ended March 31, 2017 and 2016
(Thousands of dollars)
| 2017 | 2016 | |||||||
| Net Income (Loss) |
$ | 28,009 | $ | (1,178 | ) | |||
| Other Comprehensive Income, net of taxes: |
||||||||
| Changes in fair value of hedge positions, net of taxes of $0 and $(2), respectively |
— | 5 | ||||||
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| Total other comprehensive loss |
— | 5 | ||||||
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| Comprehensive Income (Loss) |
28,009 | (1,173 | ) | |||||
| Less: Comprehensive Income Attributable to Non-Controlling Interest |
5,712 | 682 | ||||||
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| Comprehensive Income (Loss) Attributable to PrimeEnergy |
$ | 22,297 | $ | (1,855 | ) | |||
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The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements
5
CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited
Three Months Ended March 31, 2017
(Thousands of dollars)
| Common Stock | Additional Paid in |
Retained | Treasury | Total Stockholders’ Equity – |
Non-Controlling | Total | ||||||||||||||||||||||||||
| Shares | Amount | Capital | Earnings | Stock | PrimeEnergy | Interest | Equity | |||||||||||||||||||||||||
| Balance at December 31, 2016 |
3,836,397 | $ | 383 | $ | 8,313 | $ | 96,322 | $ | (46,473 | ) | $ | 58,545 | $ | 7,335 | $ | 65,880 | ||||||||||||||||
| Repurchase 492 shares of common stock |
— | — | — | — | (25 | ) | (25 | ) | — | (25 | ) | |||||||||||||||||||||
| Net income |
— | — | — | 22,297 | — | 22,297 | 5,712 | 28,009 | ||||||||||||||||||||||||
| Repurchase of non-controlling interests |
— | — | 126 | — | — | 126 | (187 | ) | (61 | ) | ||||||||||||||||||||||
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| Balance at March 31, 2017 |
3,836,397 | $ | 383 | $ | 8,439 | $ | 118,619 | $ | (46,498 | ) | $ | 80,943 | $ | 12,860 | $ | 93,803 | ||||||||||||||||
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The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements
6
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited
Three Months Ended March 31, 2017 and 2016
(Thousands of dollars)
| 2017 | 2016 | |||||||
| Cash Flows from Operating Activities: |
||||||||
| Net Income (loss) |
$ | 28,009 | $ | (1,178 | ) | |||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
||||||||
| Depreciation, depletion, amortization and accretion on discounted liabilities |
7,938 | 5,275 | ||||||
| Gain on sale of properties |
(41,602 | ) | (4,916 | ) | ||||
| Unrealized gain on derivative instruments, net |
(2,804 | ) | — | |||||
| Provision (benefit) for deferred income taxes |
4,492 | (290 | ) | |||||
| Changes in assets and liabilities: |
||||||||
| Increase in accounts receivable |
(1,160 | ) | (67 | ) | ||||
| Decrease in due from related parties |
— | 171 | ||||||
| Increase in due to related parties |
386 | — | ||||||
| Decrease in other assets |
(152 | ) | 712 | |||||
| (Decrease) in accounts payable |
(871 | ) | (2,814 | ) | ||||
| Increase in accrued liabilities |
22,391 | 4,268 | ||||||
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| Net Cash Provided by Operating Activities |
16,627 | 1,161 | ||||||
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| Cash Flows from Investing Activities: |
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| Capital expenditures, including exploration expense |
(18,866 | ) | (7,920 | ) | ||||
| Proceeds from sale of properties and equipment |
46,438 | 4,916 | ||||||
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| Net Cash Provided by (Used in) Investing Activities |
27,572 | (3,004 | ) | |||||
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| Cash Flows from Financing Activities: |
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| Purchase of stock for treasury |
(25 | ) | (485 | ) | ||||
| Purchase of non-controlling interests |
(60 | ) | (179 | ) | ||||
| Proceeds from long-term bank debt and other long-term obligations |
— | 9,000 | ||||||
| Repayment of long-term bank debt and other long-term obligations |
(38,672 | ) | (2,754 | ) | ||||
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| Net Cash (Used in) Provided by Financing Activities |
(38,757 | ) | 5,582 | |||||
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| Net Increase in Cash and Cash Equivalents |
5,442 | 3,739 | ||||||
| Cash and Cash Equivalents at the Beginning of the Period |
6,568 | 9,750 | ||||||
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| Cash and Cash Equivalents at the End of the Period |
$ | 12,010 | $ | 13,489 | ||||
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| Supplemental Disclosures: |
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| Income taxes paid |
$ | 200 | $ | 91 | ||||
| Interest paid |
$ | 451 | $ | 806 | ||||
The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements
7
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2017
(Unaudited)
(1) Basis of Presentation:
The accompanying condensed consolidated financial statements of PrimeEnergy Corporation (“PEC” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form 10-K for the year ended December 31, 2016. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s condensed consolidated balance sheets as of March 31, 2017 and December 31, 2016, the condensed consolidated results of operations, cash flows and equity for the three months ended March 31, 2017 and 2016. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued.
Recently Issued Accounting Pronouncements
In August 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of ASU 2016-15 and assessing the impact, if any, it may have on its statement of consolidated cash flows.
The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the Revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605. Extractives – Oil and Gas Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. The Company is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.
The FASB issued ASU 2016-02, Leases (Topic 842). This ASU requires lessee recognition on the balance sheet of a right-of-use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statement of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. This ASU will not have a material impact on the Company’s financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-03, Accounting Changes and Error Corrections (Topic 250) and Investments - Equity Method and Joint Venture (Topic 323), which states that registrants should consider additional qualitative disclosures if the impact of an issued but not yet adopted ASU is unknown or cannot be reasonably estimated and to include a description of the effect of the accounting policies that the registrant expects to apply, if determined. Transition guidance in certain issued but not yet adopted ASUs, including Leases and Revenue Recognition, was also updated to reflect this amendment. This guidance is effective immediately.
(2) Acquisitions and Dispositions:
Historically the Company has repurchased the interests of the partners and trust unit holders in the oil and gas limited partnerships (the “Partnerships”) and the asset and business income trusts (the “Trusts”) managed by the Company as general partner and as managing trustee, respectively. The Company purchased such interests in amounts totaling $60,000 and $1,000 for the three months ended March 31, 2017 and 2016, respectively.
During the first quarter of 2017, the Company sold or farmed out interests in certain non-core undeveloped oil and natural gas properties through a number of separate, individually negotiated transactions in exchange for cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds under these agreements were $46.4 million.
8
(3) Restricted Cash and Cash Equivalents:
Restricted cash and cash equivalents include $3.54 million at March 31, 2017 and December 31, 2016 of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at March 31, 2017 and December 31, 2016 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying condensed consolidated balance sheets.
(4) Additional Balance Sheet Information:
Certain balance sheet amounts are comprised of the following:
| (Thousands of dollars) | March 31, 2017 |
December 31, 2016 |
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| Accounts Receivable: |
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| Joint interest billing |
$ | 3,288 | $ | 2,345 | ||||
| Trade receivables |
1,209 | 1,070 | ||||||
| Oil and gas sales |
4,232 | 4,078 | ||||||
| Other |
128 | 204 | ||||||
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| 8,857 | 7,697 | |||||||
| Less: Allowance for doubtful accounts |
(297 | ) | (297 | ) | ||||
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| Total |
$ | 8,560 | $ | 7,400 | ||||
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| Accounts Payable: |
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| Trade |
$ | 3,037 | $ | 3,967 | ||||
| Royalty and other owners |
6,655 | 5,909 | ||||||
| Partner advances |
592 | 592 | ||||||
| Prepaid drilling deposits |
48 | 83 | ||||||
| Other |
762 | 1,414 | ||||||
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| Total |
$ | 11,094 | $ | 11,965 | ||||
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| Accrued Liabilities: |
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| Compensation and related expenses |
$ | 6,435 | $ | 2,295 | ||||
| Property costs |
10,707 | 3,317 | ||||||
| Income Tax |
10,962 | 1,988 | ||||||
| Other |
2,471 | 584 | ||||||
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| Total |
$ | 30,575 | $ | 8,184 | ||||
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9
(5) Property and Equipment:
Property and equipment at March 31, 2017 and December 31, 2016 consisted of the following:
| (Thousands of dollars) | March 31, 2017 |
December 31, 2016 |
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| Proved oil and gas properties, at cost |
$ | 431,827 | $ | 417,821 | ||||
| Less: Accumulated depletion and depreciation |
(237,525 | ) | (230,331 | ) | ||||
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| Oil and Gas Properties, Net |
$ | 194,302 | $ | 187,490 | ||||
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| Field and office equipment |
$ | 26,562 | $ | 26,902 | ||||
| Less: Accumulated depreciation |
(18,262 | ) | (18,024 | ) | ||||
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| Field and Office Equipment, Net |
$ | 8,300 | $ | 8,878 | ||||
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| Total Property and Equipment, Net |
$ | 202,602 | $ | 196,368 | ||||
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(6) Long-Term Debt:
Bank Debt:
Effective July 30, 2010 the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement had a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility was secured by substantially all of the Company’s oil and gas properties. The credit facility was subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans.
On February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the “ 2017 Credit Agreement”) with a maturity date of February 15, 2021. The Second Amended and Restated Credit Agreement and subsequent amendments were incorporated into the 2017 Credit Agreement. Pursuant to the terms and conditions of the 2017 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The credit facility is secured y substantially all of the Company’s oil and gas properties. Currently, the Company’s borrowing base is $75 million. The 2017 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.
At March 31, 2017, the Company had a total of $24.8 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.68% and $50.2 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.32% for the three months ended March 31, 2017 as compared to 3.61% for the three months ended March 31, 2016. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.
The Company entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years, which commenced in January 2014, related to $75 million of the Company’s bank debt resulting in a LIBO fixed rate of 0.563% and terminated in January 2016. The Company recorded interest expense and paid $7,070 related to the settlement of interest rate swaps for the three months ended March 31, 2016.
Equipment Loans:
On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by a portion of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of March 31, 2017, the Company had a total of $3.03 million outstanding on this Equipment Loan.
10
On July 29, 2014, the Company entered into additional equipment financing facilities (“Additional Equipment Loans”) totaling $6.0 million with JP Morgan Chase Bank. In August 2014, the Company drew down $4.8 million of this facility that is secured by field service equipment, carries an interest rate of 3.40% per annum, requires monthly payments (principal and interest) of $87,800, and has a final maturity date of July 31, 2019. The remaining $1.2 million under the Additional Equipment Loans was available for interim draws to finance the acquisition of any future field service equipment. In December 2014, the Company made an interim draw of an additional $0.5 million on this facility that is secured by recently purchased field service equipment. Interim draws on this facility carried a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan, with a rate of 3.50% and requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of March 31, 2017, the Company had a total of $2.76 million outstanding on the Additional Equipment Loans.
The Company determined these loans are Level 3 liabilities in the fair-value hierarchy and estimated their fair value as $5.5 million and $8.6 million at March 31, 2017 and 2016, respectively, using a discounted cash flow model.
(7) Other Long-Term Obligations and Commitments:
Operating Leases:
The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the rest of fiscal 2017 and thereafter for the operating leases are as follows:
| (Thousands of dollars) | Operating Leases |
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| 2017 |
$ | 597 | ||
| 2018 |
59 | |||
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| Total minimum payments |
$ | 656 | ||
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Rent expense for office space for the three months ended March 31, 2017 and 2016 was $181,000 and $207,000, respectively.
Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the three months ended March 31, 2017 is as follows:
| (Thousands of dollars) | ||||
| Asset retirement obligation – December 31, 2016 |
$ | 17,505 | ||
| Liabilities incurred |
30 | |||
| Liabilities settled |
(99 | ) | ||
| Accretion expense |
192 | |||
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| Asset retirement obligation – March 31, 2017 |
$ | 17,628 | ||
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|
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The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.
(8) Contingent Liabilities:
The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations.
The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
11
From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
(9) Stock Options and Other Compensation:
In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At March 31, 2017 and 2016, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.
(10) Related Party Transactions:
The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in amounts totaling $60,000 and $1,000 for the three months ended March 31, 2017 and 2016, respectively.
Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.
Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.
(11) Financial Instruments
Fair Value Measurements:
Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at March 31, 2017 and December 31, 2016:
| March 31, 2017 |
Quoted Prices in Active Markets For Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Balance at March 31, 2017 |
||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| Assets |
||||||||||||||||
| Commodity derivative contracts |
$ | — | $ | — | $ | 213 | $ | 213 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total assets |
$ | — | $ | — | $ | 213 | $ | 213 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Liabilities |
||||||||||||||||
| Commodity derivative contracts |
$ | — | $ | — | $ | (990 | ) | $ | (990 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total liabilities |
$ | — | $ | — | $ | (990 | ) | $ | (990 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
| December 31, 2016 |
Quoted Prices in Active Markets For Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Balance at December 31, 2016 |
||||||||||||
| (Thousands of dollars) | ||||||||||||||||
| Assets |
||||||||||||||||
| Commodity derivative contracts |
$ | — | $ | — | $ | 57 | $ | 57 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total assets |
$ | — | $ | — | $ | 57 | $ | 57 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Liabilities |
||||||||||||||||
| Commodity derivative contract |
$ | — | $ | — | $ | (3,639 | ) | $ | (3,639 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total liabilities |
$ | — | $ | — | $ | (3,639 | ) | $ | (3,639 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
12
The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.
The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2017.
| (Thousands of dollars) | ||||
| Net Liabilities – December 31, 2016 |
$ | (3,582 | ) | |
| Total realized and unrealized (gains) losses: |
||||
| Included in earnings (a) |
2577 | |||
| Included in other comprehensive loss |
— | |||
| Purchases, sales, issuances and settlements |
228 | |||
|
|
|
|||
| Net assets (liabilities) – March 31, 2017 |
$ | (777 | ) | |
|
|
|
|||
| a) | Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments, and interest rate swap instruments are reported as an increase or reduction to interest expense. |
Derivative Instruments:
The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.
Interest rate swap derivatives are treated as cash-flow hedges and are used to fix our floating interest rates on existing debt. Settlements of the swaps, which began in January 2014 and concluded in January 2016, was recognized within interest expense. There were no remaining interest rate swaps for the periods ending March 31,2017 and December 31, 2016.The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax.
13
The following table sets forth the effect of derivative instruments on the consolidated balance sheets at March 31, 2017 and December 31, 2016:
| Fair Value | ||||||||||||
| (Thousands of dollars) | Balance Sheet Location | March 31, 2017 |
December 31, 2016 |
|||||||||
| Asset Derivatives: |
||||||||||||
| Derivatives not designated as cash-flow hedging instruments: |
||||||||||||
| Crude oil commodity contracts |
Other Assets | $ | 28 | $ | — | |||||||
| Natural gas commodity contracts |
Other Assets | $ | 185 | $ | 57 | |||||||
|
|
|
|
|
|||||||||
| Total |
$ | 213 | $ | 57 | ||||||||
|
|
|
|
|
|||||||||
| Liability Derivatives: |
||||||||||||
| Derivatives not designated as cash-flow hedging instruments: |
||||||||||||
| Crude oil commodity contracts |
Derivative liability short-term | (205 | ) | (1,065 | ) | |||||||
| Natural gas commodity contracts |
Derivative liability short-term | (741 | ) | (1,482 | ) | |||||||
| Natural gas commodity contracts |
Derivative liability long-term | (20 | ) | (463 | ) | |||||||
| Crude oil commodity contracts |
Derivative liability long-term | (24 | ) | (629 | ) | |||||||
|
|
|
|
|
|||||||||
| Total |
$ | (990 | ) | $ | (3,639 | ) | ||||||
|
|
|
|
|
|||||||||
| Total derivative instruments |
$ | (777 | ) | $ | (3,582 | ) | ||||||
|
|
|
|
|
|||||||||
14
The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the three month period ended March 31, 2017 and 2016:
| Location of gain/loss recognized in income |
Amount of gain/loss recognized in income |
|||||||||
| (Thousands of dollars) |
2017 | 2016 | ||||||||
| Derivative designated as cash-flow hedge instruments: |
||||||||||
| Interest rate swap contracts |
Interest expense |
$ | — | $ | (7 | ) | ||||
| Derivatives not designated as cash-flow hedge instruments: |
||||||||||
| Natural gas commodity contracts |
Unrealized (loss) gain on derivative instruments, net |
1,313 | — | |||||||
| Crude oil commodity contracts |
Unrealized (loss) gain on derivative instruments, net |
1,491 | — | |||||||
| Natural gas commodity contracts |
Realized gain (loss) on derivative instruments, net |
(149 | ) | — | ||||||
| Crude oil commodity contracts |
Realized gain (loss) on derivative instruments, net |
(78 | ) | — | ||||||
|
|
|
|
|
|||||||
| $ | 2,577 | $ | (7 | ) | ||||||
|
|
|
|
|
|||||||
(12) Earnings Per Share:
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:
| Three Months Ended March 31, | ||||||||||||||||||||||||
| 2017 | 2016 | |||||||||||||||||||||||
| Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
Net Income (In 000’s) |
Weighted Average Number of Shares Outstanding |
Per Share Amount |
|||||||||||||||||||
| Basic |
$ | 22,297 | 2,283,011 | $ | 9.77 | $ | (1,860 | ) | 2,295,177 | $ | (0.81 | ) | ||||||||||||
| Effect of dilutive securities: |
||||||||||||||||||||||||
| Options |
— | 752,529 | — | 749,585 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Diluted (a) |
$ | 22,297 | 3,035,540 | $ | 7.35 | $ | (1,860 | ) | 3,044,762 | $ | (0.81 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| (a) | The effect of the 767,500 outstanding stock options is antidilutive for the three months ended March 31, 2016 due to a net loss reported for the period. |
15
This Report may contain statements relating to the future results of the Company that are considered “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 (the “PSLRA”). In addition, certain statements may be contained in the Company’s future filings with the SEC, in press releases, and in oral and written statements made by or with the approval of the Company that are not statements of historical fact and constitute forward-looking statements within the meaning of the PSLRA. Such forward-looking statements, in addition to historical information, which involve risk and uncertainties, are based on the beliefs, assumptions and expectations of management of the Company. Words such as “expects”, ‘believes”, “should”, “plans”, “anticipates”, “will”, “potential”, “could”, “intend”, “may”, “outlook”, “predict”, “project”, “would”, “estimates”, “assumes”, “likely” and variations of such similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve risks and uncertainties and are based on a number of assumptions that could ultimately prove inaccurate and, therefore, there can be no assurance that they will prove to be accurate. Actual results and outcomes may vary materially from what is expressed or forecast in such statements due to various risks and uncertainties. These risks and uncertainties include, among other things, the possibility of drilling cost overruns and technical difficulties, volatility of oil and gas prices, competition, risks inherent in the Company’s oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, and the Company’s ability to replace and expand oil and gas reserves. Accordingly, stockholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected. The forward-looking statements are made as of the date of this Report and other than as required by the federal securities laws, the Company assumes no obligation to update the forward-looking statements or to update the reasons why actual results could differ from those projected in the forward-looking statements.
| Item 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.
OVERVIEW
We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential.
We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of over 21,160 gross (13,020 net) acres, approximately 91% of which is in Reagan, Upton, Martin and Midland counties of Texas where our current horizontal drilling activity is focused. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells. In Oklahoma we maintain an acreage position of approximately 77,741 gross (14,512 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady and Garvin counties. We believe approximately 2300 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 78 new horizontal wells based on an estimate of only two wells per section, with our share of such prospective future development being about $42 million based on an average 10.5% ownership level.
Our balanced portfolio of assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash flows generated from operations, through our producing oil and gas properties, our field services business, and from sales of non-core acreage.
The Company will continue to pursue the acquisition of leasehold acreage and producing properties in areas where we currently operate and believe there is additional exploration and development potential and will attempt to assume the position of operator in all such acquisitions. In order to diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets so as to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.
Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We may use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.
RECENT ACTIVITIES
Our West Texas, horizontal drilling program, which began in 2015, includes eight wells drilled, completed and placed on production as of December 31, 2016. Drilling activity has continued in the first quarter of 2017 with the Company participating in an additional 19 horizontal wells, eight of which were placed on production by March 31, 2017, and eleven that are in various stages of being drilled, completed, or are waiting on hydraulic fracture stimulation. In addition, we anticipate the drilling of eight more horizontal wells in 2017. This additional activity brings the anticipated total to 27 horizontal wells that are expected to be drilled in 2017 in our West Texas horizontal drilling program. The Company is also participating for less than 1% interest in thirteen other horizontal wells.
In Upton County, Texas, we are developing a contiguous 3,900 acre block with our joint venture partner, Apache Corporation, where the Company holds approximately 48% interest in 2,606 gross acres. Through yearend 2016, six wells had been drilled and completed. In the first quarter of 2017, an additional eleven wells were spud and are in the process of being drilled or completed. Approximately $82 million will be invested in this group of wells, of which the Company’s share will be approximately $27.9 million. Apache drilling-plans indicate an additional six wells will be drilled later this year at a cost of $38.9 million, of which our share is approximately $12.4 million. Apache Corporation has indicated plans to Pad drill the acreage and projects future phases of development will result in approximately 60 horizontal wells being drilled at a cost of about $470 million. We own various interests ranging from 14% to 49% in the lands to be developed in this project and expect our share of these capital expenditures to be approximately $120 million. The total number of wells that will be drilled and the timing of the drilling may vary based on drilling
16
schedule and commodity prices. Also in Upton County, the Company is participating for 4% interest with Apache in the development of a 640 acre block where six wells that had been drilled in 2016, were placed on production in the first quarter of 2017. In 2016, we commenced our Martin County, Texas horizontal drilling program with the drilling of two wells that began production in July, 2016. These wells were drilled on a 960 acre block that the Company is developing with RSP Permian. An additional two wells, spud in 2016, were placed on production in the first quarter of 2017. The Company owns 35% interest in these two wells. RSP Permian drilling-plans indicate an additional two wells will be drilled in 2017, however, definitive plans have not yet been received.
The Company maintains an acreage position of approximately 21,160 gross (13,020 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Midland and Martin counties. We believe this acreage has significant resource potential in multiple Spraberry and Wolfcamp intervals that support the potential drilling of as many as 250 additional wells.
Our Oklahoma horizontal development program, which began in 2012, has, through the first quarter of 2017 participated in 24 horizontal wells for approximately $23 million. Over this same time period the Company chose to retain an overriding royalty interest in 21 other horizontal wells. In the first quarter of 2017, we participated in two horizontal wells, one vertical well and retained an over-riding royalty interest in one other horizontal well. The Company participated with 17.6% interest in the drilling of a horizontal well in Canadian County operated by Devon Energy that was spud in November of 2016 and has been completed and was placed on production in early April 2017. The Company is currently participating with 11.8% interest in a horizontal well being drilled by Marathon Oil Company in Kingfisher County. This well was spud in February and is anticipated be completed and on production in the second quarter of 2017. Our share of this well will be approximately $1 Million. In addition, the Company is participating for 50% interest in a vertical well in Garvin County that has been drilled and is in the process of being tested. Our share of the cost of this will is expected to be approximately $1.3 Million. One interval in this well is currently being tested and further completion work is anticipated for the second quarter of 2017. Also in the first quarter of 2017, the Company chose to retain an ORRI in a horizontal well drilled in Garfield County that has been drilled and placed on production, and also chose to sell certain leasehold rights and instead retain an ORRI in a particular acreage block in Canadian County where eight horizontal wells are likely to be drilled in the future.
The horizontal activity on Company acreage in Oklahoma is primarily focused in Canadian, Grady, Kingfisher and Garvin counties where we hold approximately 2300 net acres that are prospective for horizontal development. We believe our acreage has significant additional resource potential that could support the drilling of 78 new horizontal wells.
In the first quarter of 2017, the Company sold or farmed-out leasehold rights through four separate transactions, receiving gross proceeds of approximately $46.4 million. In West Texas we sold approximately 2,031 net mineral acres for $38 million, primarily located in Martin County, and in Oklahoma we farmed-out approximately 1,525 net mineral acres in Canadian County for $8.4 million and will retain an over-riding royalty interest and potential reversionary interests. These sales were of non-cash flowing mineral interests.
RESULTS OF OPERATIONS
2017 and 2016 Compared
We report net income of $22.3 million, $9.77 per share for the three months ended March 2017 compared with a net loss of $1.86 million or $(0.81) per share for the same period of 2016. Current year net income reflects an increase in oil and gas production combined with increased commodity prices over the three months ended March 31, 2016 combined with gains related to the sale of acreage during the three months ended March 2017. The significant components of income and expense are discussed below.
Oil and gas sales increased $5.3 million, or 74% from $7.1 million for the three months ended March 31, 2016 to $12.4 million for the three months ended March 31, 2017. Crude oil and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head increased an average of $20.61 per barrel, or 71% on crude oil during the three months ended March 31, 2017 from the same period in 2016 and our average well head price for natural gas increased $1.18 per mcf, or 53% during the three months ended March 31, 2017 from the same period in 2016.
Our crude oil production increased by 13,000 barrels, or 8% from 162,000 barrels for the first quarter 2016 to 175,000 barrels for the first quarter 2017. Our natural gas production increased by 7,000 mcf, or 0.6% from 1,105,000 mcf for the first quarter 2016 to 1,112,000 mcf for the first quarter 2017. The net increase in crude oil and natural gas production volumes reflect the natural decline of properties drilled in early 2016 combined with the natural decline of the previously existing properties, offset by production from new wells added in late 2016 and early 2017.
17
The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended March 31, 2017 and 2016 (excluding realized gains and losses from derivatives).
| Three Months Ended March 31, | ||||||||||||
| 2017 | 2016 | Increase / (Decrease) |
||||||||||
| Barrels of Oil Produced |
175,000 | 162,000 | 13,000 | |||||||||
| Average Price Received |
$ | 49.52 | $ | 28.91 | $ | 20.61 | ||||||
|
|
|
|
|
|||||||||
| Oil Revenue (In 000’s) |
$ | 8,674 | $ | 4,684 | $ | 3,990 | ||||||
| Mcf of Gas Produced |
1,112,000 | 1,105,000 | 7,000 | |||||||||
| Average Price Received |
$ | 3.39 | $ | 2.21 | $ | 1.18 | ||||||
|
|
|
|
|
|||||||||
| Gas Revenue (In 000’s) |
$ | 3,764 | $ | 2,446 | $ | 1,318 | ||||||
|
|
|
|
|
|
|
|||||||
| Total Oil & Gas Revenue (In 000’s) |
$ | 12,438 | $ | 7,130 | $ | 5,308 | ||||||
|
|
|
|
|
|
|
|||||||
Realized net losses on derivative instruments include net losses of $0.15 million and $0.077 million on the settlements of natural gas and crude oil derivatives, respectively for the first quarter 2017. No such gains were recognized in 2016.
We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During the three months ended March 31, 2017, we recognized net unrealized gains of $1.31 million associated with natural gas fixed swap contracts and $1.49 million in net unrealized gains associated with crude oil fixed swaps due to an increase in natural gas and crude oil futures market prices between December 31, 2016 and March 31, 2017. No such gains were recognized in 2016.
There were no swaps in place related to the three months ended March 31, 2016. Oil and gas prices received for the three months ended March 31, 2017 including the impact of derivatives were:
| Oil Price |
$ | 49.12 | ||
| Gas Price |
$ | 3.25 | ||
Field service income decreased $0.46 million, or 11% from $4.22 million for the first quarter 2016 to $3.76 million for the first quarter 2017. This decrease is a combined result of reduced utilization and the market requiring us to charge lower rates to customers during the 2017 period. Workover rig services represent the bulk of our field service operations, and while we were able to keep our rigs utilized during 2017, working rates have all decreased between the periods in our most active districts.
Lease operating expense decreased $0.72 million, or 11% from $8.01 million for the first quarter 2016 to $7.14 million for the first quarter 2017. This decrease is primarily due to general rate reductions on vendor services off-set by increased production taxes related to increased oil and natural gas prices during the first three months of 2017 as compared to the same period of 2016.
Field service expense decreased $0.58 million, or 16% from $3.56 million for the first quarter 2016 to $2.98 million for the first quarter 2017. Field service expenses primarily consist of salaries and vehicle operating expenses which have decreased during the three months ended March 31, 2017 over the same period of 2016 as a direct result of decreased services and utilization of the equipment.
Depreciation, depletion, amortization and accretion on discounted liabilities increased $2.27 million, or 50% from $5.28 million for the first quarter 2016 to $7.94 million for the first quarter 2017 reflecting the increased production during the first three months of 2017 as compared to the same period of 2016 and the increase capital cost base of recently drilled and completed wells.
General and administrative expense decreased $0.70 million, or 29% from $2.43 million for the three months ended March 31, 2016 to $1.74 million for the three months ended March 31, 2017. This decrease in 2017 reflects the cost cutting measures including reductions in workforce put in place throughout 2016.
Gain on sale and exchange of assets of $41.6 million and $4.92 million for the three months ended March 31, 2017 and March 31, 2016, respectively consists of sales of non-essential oil and gas interests and field service equipment.
Interest expense decreased $0.26 million, or 30% from $0.87 million for the first quarter 2016 to $0.61 million for the first quarter 2017. This decrease reflects the reduction in current borrowings under our revolving credit agreement.
18
A tax provision of $13.7 million was recorded for the quarter ended March 31, 2017, versus a benefit of $890 thousand for the quarter ended March 31, 2016 directly related to the income and losses of the respective periods.
LIQUIDITY AND CAPITAL RESOURCES
Our primary sources of liquidity are cash flows generated from operations, through our producing oil & gas properties and field services business, and from sales of non-core acreage.
Net cash provided by our operating activities for the three months ended March 31, 2017 was $16.6 million compared to $1.16 million for the three months ended March 31, 2016. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of derivatives.
If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells, we will be able to access sufficient additional capital through bank financing.
We currently maintain a credit facility totaling $300 million, with a borrowing base of $75 million. As of March 31, 2017 the Company has $24.8 million in outstanding borrowings and $50.2 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for June 2017. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base.
Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly the Company has in place the following swap agreements for oil and natural gas.
| Monthly Hedge Volumes | Price | |||||||||||||||||||
| Year | BBLs | MMBTU | BBLs | MMBTU | ||||||||||||||||
| April through December |
2017 | 14,300 | 235,000 | $ | 50.10 | $ | 3.11 | |||||||||||||
| January through December |
2018 | 11,900 | 200,000 | $ | 52.02 | $ | 2.97 | |||||||||||||
| January through March |
2019 | 12,500 | 130,000 | $ | 50.75 | $ | 3.12 | |||||||||||||
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2017, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2017 capital budget is reflective of decreased commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.
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We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2017. For the three month period ended March 31, 2017, we have spent $85 thousand under these programs.
| Item 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Company is a smaller reporting company and no response is required pursuant to this Item.
| Item 4. | CONTROLS AND PROCEDURES |
As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief
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Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.
There were no changes in the Company’s internal control over financial reporting that occurred during the first three months of 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
| Item 1. | LEGAL PROCEEDINGS |
None.
| Item 1A. | RISK FACTORS |
The Company is a smaller reporting company and no response is required pursuant to this Item.
| Item 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
There were no sales of equity securities by the Company during the period covered by this report.
During the three months ended March 31, 2017, the Company purchased the following shares of common stock as treasury shares.
| 2017 Month |
Number of Shares |
Average Price Paid per share |
Maximum Number of Shares that May Yet Be Purchased Under The Program at Month - End (1) |
|||||||||
| January |
101 | $ | 54.05 | 236,946 | ||||||||
| February |
140 | $ | 57.25 | 236,806 | ||||||||
| March |
251 | $ | 49.55 | 236,555 | ||||||||
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| Total/Average |
492 | $ | 52.66 | |||||||||
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| (1) | In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, the Board of Directors of the Company approved an additional 500,000 shares of the Company’s stock to be included in the stock repurchase program. A total of 3,500,000 shares have been authorized to date under this program. Through March 31, 2017, a total of 3,263,445 shares have been repurchased under this program for $55,155,560 at an average price of $16.90 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital. |
| Item 3. | DEFAULTS UPON SENIOR SECURITIES |
None
| Item 4. | RESERVED |
| Item 5. | OTHER INFORMATION |
None
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| Item 6. | EXHIBITS |
The following exhibits are filed as a part of this report:
| Exhibit No. |
||
| 3.1 |
Restated Certificate of Incorporation of PrimeEnergy Corporation (effective July 1, 2009) (Incorporated by reference to Exhibit 3.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2009). | |
| 3.2 |
Bylaws of PrimeEnergy Corporation as amended and restated as of May 20, 2015 (filed as Exhibit 3.2 of PrimeEnergy Corporation Form 8-K on May 21, 2015 and incorporated herein by reference). | |
| 10.18 |
Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Corporation Form 10-K for the year ended December 31, 2004). | |
| 10.22.5.10 |
Third Amended and Restated Credit Agreement dated as of February 15, 2017 among PrimeEnergy Corporation, as Borrower, Compass Bank, as Administrative Agent and Lender, Wells Fargo, National Association, as Document Agent, the Lenders Party Hereto (Compass Bank, Wells Fargo, National Association, Citibank, N.A.) and BBVA Compass Bank, as Letter of Credit Issuer and Sole Lead Arranger and Sole Bookrunner (Incorporated by reference to Exhibit 10.22.5.10 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2016). | |
| 10.22.5.11 |
Amended, Restated and Consolidated Guaranty dated as of February 15, 2017, among PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. in favor of Compass Bank, as Administrative Agent for the Lenders (Incorporated by reference to Exhibit 10.22.5.11 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2016). | |
| 10.22.5.12 |
Amended, Restated and Consolidated Pledge and Security Agreement dated as of February 15, 2017, among PrimeEnergy Corporation, PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. and Compass Bank, as Administrative Agent for the Secured Parties (Incorporated by reference to Exhibit 10.22.5.12 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2016). | |
| 10.22.5.13 |
Amended, Restated and Consolidated Deed of Trust, Mortgage, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (filed herewith). | |
| 10.22.5.14 |
Deed of Trust, Mortgage, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (filed herewith). | |
| 10.22.5.15 |
Amended, Restated and Consolidated Mortgage of Oil and Gas Property, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (filed herewith). | |
| 10.23.1 |
Loan and Security Agreement dated July 31, 2013, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013). | |
| 10.23.2 |
Business Purpose Promissory Note dated July 31, 2013, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.23.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013). | |
| 10.23.3 |
Guaranty dated July 31, 2013, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.23.3 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013). | |
| 10.23.4 |
Agreement of Equipment Substitution dated January 15, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by
reference to Exhibit 10.23.4 to PrimeEnergy Corporation Form 10-Q for the quarter ended March 31, 2014). | |
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| Exhibit No. |
||
| 10.24.1 |
Loan and Security Agreement dated July 29, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.24.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014). | |
| 10.24.2 |
Business Purpose Promissory Note dated July 29, 2014, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.24.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014). | |
| 10.24.3 |
Guaranty dated July 29, 2014, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.24.3 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014). | |
| 10.25 |
Purchase and Sale Agreement dated as of January 25, 2017, among PrimeEnergy Corporation, PrimeEnergy Management Corporation, PrimeEnergy Operating Company, PrimeEnergy Asset and Income Fund, L.P. A-2, PrimeEnergy Asset and Income Fund, L.P. A-3, PrimeEnergy Asset and Income Fund, L.P. AA-2, and PrimeEnergy Asset and Income Fund, L.P. AA-4, as Sellers and Guidon Operating LLC, as Purchaser (Incorporated by reference to Exhibit 10.22.5.10 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2016). | |
| 31.1 |
Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith). | |
| 31.2 |
Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith). | |
| 32.1 |
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). | |
| 32.2 |
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). | |
| 101.INS |
XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith) | |
| 101.SCH |
XBRL Taxonomy Extension Schema Document (filed herewith) | |
| 101.CAL |
XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith) | |
| 101.DEF |
XBRL Taxonomy Extension Definition Linkbase Document (filed herewith) | |
| 101.LAB |
XBRL Taxonomy Extension Label Linkbase Document (filed herewith) | |
| 101.PRE |
XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith) | |
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Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
| PrimeEnergy Corporation | ||||
| (Registrant) | ||||
| May 15, 2017 | /s/ Charles E. Drimal, Jr. | |||
| (Date) | Charles E. Drimal, Jr. | |||
| President | ||||
| Principal Executive Officer | ||||
| May 15, 2017 | /s/ Beverly A. Cummings | |||
| (Date) | Beverly A. Cummings | |||
| Executive Vice President | ||||
| Principal Financial Officer | ||||
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