PRIMEENERGY RESOURCES CORP - Quarter Report: 2017 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended September 30, 2017

Or

For the Transition Period From                  to                 

Commission File Number 0-7406

PrimeEnergy Corporation

(Exact name of registrant as specified in its charter)

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.

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 November 7, 2017 was: Common Stock, $0.10 par value 2,181,681 shares.

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PrimeEnergy Corporation

Index to Form 10-Q

September 30, 2017

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PART I—FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS -

PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars, except per share amounts)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

(Thousands of dollars, except per share amounts)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – Unaudited

Nine Months Ended September 30, 2017 and 2016

(Thousands of dollars)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Nine Months Ended September 30, 2017

(Thousands of dollars)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

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PRIMEENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Nine Months Ended September 30, 2017 and 2016

(Thousands of dollars)

The accompanying Notes are an integral part of these Condensed Consolidated Financial

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PRIMEENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 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 September 30, 2017 and December 31, 2016, the condensed consolidated results of operations for the three and nine months ended September 30, 2017 and 2016, and the condensed consolidated results of cash flows and equity for the nine months ended September 30, 2017. 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:

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. Extractivies – 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 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.

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. The adoption of this guidance had no effect on the Company’s financial statements.

(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 $187,000 for the nine months ended September 30, 2017 and 2016, respectively.

During the nine months ended September 30, 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 West Texas, New Mexico and Oklahoma. Proceeds under these agreements were $47 million.

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During the nine months of 2017, the Company acquired approximately 118 net mineral acres for $596,000 adjacent to existing Company acreage in order to facilitate the drilling of future horizontal wells.

(3) Restricted Cash and Cash Equivalents:

Restricted cash and cash equivalents include $4.19 million and $3.54 million at September 30, 2017 and December 31, 2016, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at September 30, 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:

(5) Property and Equipment:

Property and equipment at September 30, 2017 and December 31, 2016 consisted of the following:

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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 amended and restated by 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 by substantially all of the Company’s oil and gas properties. As of September 30, 2017, the Company’s borrowing base was $67 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 September 30, 2017, the Company had a total of $49.8 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 4.67% and $17.2 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 4.98% for the nine months ended September 30, 2017 as compared to 3.83% for the nine months ended September 30, 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 $7,000 related to the settlement of interest rate swaps for the nine months ended September 30, 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 September 30, 2017, the Company had a total of $1.80 million outstanding on this Equipment Loan.

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 September 30, 2017, the Company had a total of $2.14 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 $3,941 million and $6,958 million at September 30, 2017 and 2016, respectively, using a discounted cash flow model.

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(7) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company has 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:

Rent expense for office space for the nine months ended September 30, 2017 and 2016 was $509,000 and $677,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2017 is as follows:

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. At September 30, 2017, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities and the Company believes these reserves will be sufficient to satisfy Partnership 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.

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 September 30, 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.

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(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 $187,000 for the nine months ended September 30, 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 September 30, 2017 and December 31, 2016:

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.

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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 six months ended September 30, 2017.

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 as of September 30, 2017 and December 31, 2016.The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at September 30, 2017 and December 31, 2016:

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The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine month periods ended September 30, 2017 and 2016:

(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:

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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, and Colorado. 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 (12,742 net) acres, approximately 92% 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, Wolfcamp and other intervals for additional horizontal drilling that could support the drilling potential in excess of 400 additional horizontal wells. In Oklahoma we maintain an acreage position of approximately 82,572 gross (12,980 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,231 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 75 new horizontal wells based on an estimate of only two wells per section, per formation ( Woodford & Mississippian ), 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 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 level of our acquisition, disposition 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, currently includes a total of 28 wells that were drilled, completed and placed on production as of the end of the third quarter 2017. This program positioned in Upton and Martin County offsets two large Pioneer Natural Resources developments, Giddings Ranch in Upton and Sales Ranch in Martin.

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 the end of the third quarter 2017, 16 wells have been drilled, completed and placed on production. During the fourth quarter of 2017, an additional 12 wells (Company ownership between 31% and 38%) were drilled and brought online. There are also 6 additional wells with 1% or less ownership that are currently being drilled, completed, or are awaiting hydraulic fracture. Apache drilling plans indicate 5 additional wells will be spud first quarter of 2018 at a cost of $40 million, of which our share is approximately $17 million. Apache has begun pad drilling of the acreage and future development is anticipated to result in approximately 80 additional horizontal wells being drilled at a cost of about $616 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 $171 million. The total number of wells that will be drilled and the timing of drilling will vary based on drilling schedule and commodity prices.

In Martin County, Texas we are developing a 960 acre block with RSP Permian and the Company owns from 35% to 38% interest. Through the end of the third quarter 2017, 4 wells have been drilled and placed on production. Further development plans for this acreage have not been received from RSP at this time. In addition to the development with RSP, the Company has also participated with Crownquest Operating in 15 wells in which Company ownership is less than 1%. Eight of the wells have been drilled and put on production and the remaining 7 are currently being drilled, completed, or are awaiting hydraulic fracture.

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Once all wells are on production, our current West Texas horizontal drilling program will consist of 58 wells.

In Eddy County, New Mexico, the Company term assigned 80 net mineral acres for $400,000, retaining an overriding royalty on future horizontal development.    

Our Oklahoma horizontal development program, which began in 2012, has, through the third quarter of 2017, participated in 26 horizontal wells for approximately $26 million. Over this same time period the Company chose to retain an overriding royalty interest in 26 other horizontal wells. Through the third quarter of 2017, we participated in 2 horizontal wells that have been placed on production: The Company participated with 19.7% interest in the drilling of a horizontal well in Canadian County operated by Devon Energy that spud in November of 2016 and was placed on production in early April 2017. The Company also participated with 11.5% interest in a horizontal well drilled by Marathon Oil Company in Kingfisher County that was spud in February of 2017 and put on production in early June 2017. The Company is currently participating in 2 wells drilled in Grady County, with approximately 10% interest in a well operated by Linn Operating, Inc. drilled in June 2017 but not yet completed and 1% in a well operated by Citizen Energy II LLC. which were drilled in May 2017 but are not yet completed. The total cost for these 2 wells will be about $14,700,000 and the Company’s share will be approximately $826,000. The Company is also participating in a horizontal well in Garvin County operated by Rimrock Resource Operating in which the Company has approximately 6.25% interest with an expected net cost of $621,000, this well was drilled in July 2017 and treated in September 2017 but not yet producing. In addition, we have elected to retain an overriding royalty interest in 2 horizontal wells drilled. The first well drilled by White Star Petroleum in Garfield County, retained 3.1% ORRI, drilled in November 2016 and put on production in February 2017 and second well drilled by Chaparral Energy Corp. in Garfield County, retained 0.325% overriding royalty interest, drilled in May 2017 and put on production in July 2017.

RESULTS OF OPERATIONS

2017 and 2016 Compared

We reported a net loss for the three months ended September 30, 2017 of $2.0 million, or $1.22 per share and a net income for the nine months ended September 30, 2017 of $20.6 million, or $9.29 per share, as compared to net income of $4.9 million, or $2.15 per share and $5.6 million, or $2.44 per share for the three and nine months ended September 30, 2016, respectively. Current year net income reflects an increase in oil production combined with increased commodity prices over the nine months ended September 30, 2017 combined with gains related to the sale of acreage during the nine months ended September 2017. The significant components of income and expense are discussed below.

Oil and gas sales increased $1.0 million, or 9.1% from $11.6 million for the three months ended September 30, 2016 to $12.6 million for the three months ended September 30, 2017 and increased $11.6 million, or 42.5% from $27.4 million for the nine months ended September 30, 2016 to $39.0 million for the nine months ended September 30, 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 $3.20 per barrel, or 7.6% and $8.86 per barrel, or 23.5%, on crude oil during the three and nine months ended September 30, 2017, respectively from the same periods in 2016 while our average well head price for natural gas increased $0.26 per mcf, or 9.1% and $0.87 per mcf, or 35.2% during the three and nine months ended September 30, 2017, respectively from the same periods in 2016.

Our crude oil production decreased by 9,000 barrels or 4.5% from 199,000 barrels for the third quarter 2016 to 190,000 barrels for the third quarter 2017 and increased by 80,000 barrels, or 15.77% from 511,000 barrels for the nine months ended September 30, 2016 to 591,000 barrels for the nine months ended September 30, 2017. Our natural gas production increased by 170,000 mcf, or 15.1% from 1,124,000 mcf for the third quarter 2016 to 1,294,000 mcf for the third quarter 2017 and increased by 158,000 mcf, or 4.8% from 3,308,000 mcf for the nine months ended September 30, 2016 to 3,466,000 mcf for the nine months ended September 30, 2017. The changes in crude oil and natural gas production volumes reflect the natural decline of the previously existing properties, offset by production from new wells added in late 2016 and the first half of 2017. Production from our horizontal wells in West Texas was shut in during the ladder half of the third quarter of 2017 to facilitate the completion operations on our offset leases of fourteen new horizontal wells which came on line during the fourth quarter. We also experienced some shut-ins of our Gulf Coast production due to hurricane Harvey during the third quarter.

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The following table summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2017 and 2016 (excluding realized gains and losses from derivatives).

Realized gain (loss) on derivative instruments, net include net gains of $81 thousand and $75 thousand on the settlements of crude oil and natural gas derivatives, respectively for the third quarter 2017. Realized gain (loss) on derivative instruments include net gains of $81 thousand and net losses of $130 thousand on the settlements of crude oil and natural gas derivatives, respectively for the nine months ended September 30, 2017. No such gains or losses were realized 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 and nine months ended September 30, 2017, we recognized net unrealized losses of $143 thousand and net unrealized gains of $1.80 million, respectively associated with natural gas fixed swap contracts and net unrealized losses of $1.12 million and net unrealized gains of $1.38 million, respectively associated with crude oil fixed swaps due to market fluctuations in natural gas and crude oil futures market prices between December 31, 2016 and September 30, 2017. No such gains were recognized in 2016.

There were no swaps in place related to the three and nine months ended September 30, 2016. Oil and gas prices received for the three and nine months ended September 30, 2017 including the impact of derivatives were:

Field service income increased $0.4 million, or 11.2% from $3.7 million for the third quarter 2016 to $4.1 million for the third quarter 2017 and $0.5 million, or 4.7% from $11.6 million for the nine months ended September 30, 2016 to $12.2 million for the nine months ended September 30, 2017. Workover rig services represent the bulk of our field service operations, and working rates have increased between the periods in our most active districts. The increase in revenues from these services has been supplemented by increases in our salt water disposal revenues.

Lease operating expense increased $0.5 million, or 7.6% from $6.3 million for the third quarter 2016 to $6.7 million for the third quarter 2017 and decreased $0.7 million, or 3.2% from $21.8 million for the nine months ended September 30, 2016 to $21.0 million for the nine months ended September 30, 2017. This decrease is primarily due to reductions in costs in our marginal fields including personnel cut backs and decreased vendor services offset by increased production taxes related to increased oil and natural gas prices during 2017 as compared to the same periods of 2016.

Field service expense increased $0.4 million, or 17.4% from $2.7 million for the third quarter 2016 to $3.1 million for the third quarter 2017 and decreased $0.4 million, or 4.5% from $9.58 million for the nine months ended September 30, 2016 to $9.2 million for the nine months ended September 30, 2017. Field service expenses primarily consist of wages and vehicle operating expenses which have trended upward during the nine months ended September 30, 2017 from the same period of 2016 as a direct result of increases in hourly wage rates and hours, and utilization of the operating equipment in West Texas.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $0.5 million, or 6.9% from $7.3 million for the third quarter 2016 to $7.8 million for the third quarter 2017 and $4.9 million, or 26.1% from $18.9 million for the nine months ended September 30, 2016 to $23.8 million for the nine months ended September 30, 2017 reflecting the increased production during 2017 as compared to the same periods of 2016 and the increase capital cost base of recently drilled and completed wells.

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General and administrative expense increased $0.2 million, or 2.9% from $6.7 million for the nine months ended September 30, 2016 to $6.9 million for the nine months ended September 30, 2017, and $0.1 million, or 4.9% from $2.4 million for the three months ended September 30, 2016 to $2.5 million for the three months ended September 30, 2017. The largest component of these personnel costs are salaries and employee related taxes and insurance with quarterly variances due to the reimbursement of administrative expenses associated with property activities during the period.

Gain on sale and exchange of assets of $42.1 million and $26.9 million for the nine months ended September 30, 2017 and September 30, 2016, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense decreased from $1.10 million for the third quarter 2016 to $0.6 million for the third quarter 2017 and from $2.8 million for the nine months ended September 30, 2016 to $1.7 million for the nine months ended September 30, 2017. This decrease reflects the reduction in current borrowings under our revolving credit agreement.

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A tax provision of $12.4 million was recorded for the nine months ended September 30, 2017 versus a tax provision of $3 million for the nine months ended September 30, 2016. Our provision for income taxes can vary from the federal statutory tax rate of 34% primarily due to state taxes and percentage depletion deductions. We are entitled to percentage depletion on certain of our wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which would have the effect of lowering our effective rate.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of non-core acreage.

Net cash provided by our operating activities for the nine months ended September 30, 2017 was $21.4 million compared to $5.0 million for the nine months ended September 30, 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.

We currently maintain a credit facility totaling $300 million, with a borrowing base of $67 million. As of September 30, 2017, The Company has $49.8 million in outstanding borrowings. 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 November 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 credit 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 forecasted for as PDP reserves in our borrowing base review engineering report. Accordingly the Company has in place the following swap agreements for oil and natural gas.

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 current 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.

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 nine month period ended September 30, 2017, we have spent $5,060,000 million under these programs.

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The Company is a smaller reporting company and no response is required pursuant to this Item.

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 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 controls over financial reporting that occurred during the nine months ended September 30, 2017 that materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

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PART II—OTHER INFORMATION

None.

The Company is a smaller reporting company and no response is required pursuant to this Item.

There were no sales of equity securities by the Company during the period covered by this report.

During the nine months ended September 30, 2017, the Company purchased the following shares of common stock as treasury shares.

None

None

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The following exhibits are filed as a part of this report:

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SIGNATURES

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.

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