PRIMEENERGY RESOURCES CORP - Quarter Report: 2019 June (Form 10-Q)

 

 

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 June 30, 2019

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 Resources 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)

 

 

Securities registered pursuant to Section 12(b) of the Act

 

Title of each class		Trading Symbol		Name of each exchange on which registered
Common Stock, par value $0.10 (per share)		PNRG		NASDAQ

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, 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 August 9, 2019 was: Common Stock, $0.10 par value 2,010,613 shares.

 

 

 

PrimeEnergy Resources Corporation

Index to Form 10-Q

June 30, 2019

 

		Page
Part I—Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – June  30, 2019 and December 31, 2018			3
Condensed Consolidated Statements of Operations – For the six and three months ended June 30, 2019 and 2018			4
Condensed Consolidated Statement of Equity – For the six months ended June 30, 2019 and 2018			5
Condensed Consolidated Statements of Cash Flows – For the six months ended June 30, 2019 and 2018			6
Notes to Condensed Consolidated Financial Statements – June  30, 2019			7-14
Item  2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation			14-24
Item 3. Quantitative and Qualitative Disclosures About Market Risk			24
Item 4. Controls and Procedures			24
Part II - Other Information
Item 1. Legal Proceedings			24
Item 1A. Risk Factors			24
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			25
Item 3. Defaults Upon Senior Securities			26
Item 4. Reserved			26
Item 5. Other Information			26
Item 6. Exhibits			27
Signatures			29

 

2

PART I—FINANCIAL INFORMATION

 

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – Unaudited

(Thousands of dollars)

 

		June 30, 2019				December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents		$	2,821			$	6,315
Accounts receivable, net			16,848				14,961
Prepaid obligations			485				640
Derivative asset short-term			1,081				1,674
Other current assets			139				144
Total Current Assets			21,374				23,734
Property and Equipment, at cost
Oil and gas properties (successful efforts method), net			216,123				223,669
Field and office equipment, net			6,905				6,756
Total Property and Equipment, Net			223,028				230,425
Derivative asset long-term and other assets.			623				893
Total Assets		$	245,025			$	255,052
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		$	13,440			$	9,553
Accrued liabilities			6,767				18,431
Current portion of long-term debt			—				698
Current portion of asset retirement and other obligations			2,098				1,687
Derivative liability short-term			1,675				88
Due to Related Parties			—				5
Total Current Liabilities			23,980				30,462
Long-Term Bank Debt			62,000				65,547
Asset Retirement Obligations			19,377				19,647
Derivative Liability Long-Term			—				10
Deferred Income Taxes			33,534				32,828
Other Long-Term Obligations			608				555
Total Liabilities			139,499				149,049
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2019 and 2018: Authorized and Issued: 2,810,000 shares; outstanding 2019: 2,017,508 shares; 2018: 2,039,919 shares			281				281
Paid-in capital			7,612				7,388
Retained earnings			128,381				125,644
Treasury stock, at cost; 2019: 792,492 shares; 2018: 770,081 shares			(34,316	)			(31,304	)
Total Stockholders’ Equity – PrimeEnergy			101,958				102,009
Non-controlling interest			3,568				3,994
Total Equity			105,526				106,003
Total Liabilities and Equity		$	245,025			$	255,052

 

3

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – Unaudited

Three and six months ended June 30, 2019 and 2018

(Thousands of dollars, except per share amounts)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2019				2018				2019				2018
Revenues
Oil sales		$	19,644			$	16,622			$	38,442			$	36,723
Natural gas sales			1,355				1,989				3,590				4,352
Natural gas liquids sales			2,375				3,098				5,219				5,698
Realized loss on derivative instruments, net			(851	)			(1,081	)			(773	)			(1,576	)
Field service income			4,757				4,447				9,490				8,662
Administrative overhead fees			1,388				1,426				2,812				2,930
Unrealized gain (loss) on derivative instruments, net			2,862				(4,136	)			(2,890	)			(5,957	)
Other income			4				22				63				22
Total Revenues			31,534				22,387				55,953				50,854
Costs and Expenses
Lease operating expense			8,149				8,757				16,225				17,336
Field service expense			3,979				3,219				7,644				6,429
Depreciation, depletion, amortization and accretion on discounted liabilities			9,292				7,909				18,550				15,832
General and administrative expense			2,895				2,571				9,771				8,547
Total Costs and Expenses			24,315				22,456				52,190				48,144
Gain on Sale and Exchange of Assets			1,023				185				1,689				2,657
Income from Operations			8,242				116				5,452				5,367
Other Income (Expense)
Interest Income			3				12				10				23
Interest (Expense)			(1,013	)			(917	)			(1,988	)			(1,779	)
Income (Loss) Before Income Taxes			7,232				(789	)			3,474				3,611
Income Taxes Expense (Benefit)			1,410				(192	)			683				907
Net Income (Loss)			5,822				(597	)			2,791				2,704
Less: Net Income (Loss) Attributable to Non-Controlling Interests			47				(37	)			54				(22	)
Net Income (Loss) Attributable to PrimeEnergy		$	5,775			$	(560	)			2,737				2,726
Basic Income (Loss) Per Common Share		$	2.85			$	(0.27	)		$	1.35			$	1.29
Diluted Income (Loss) Per Common Share		$	2.07			$	(0.27	)		$	0.98			$	0.95

 

4

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF EQUITY – Unaudited

Six months ended June 30, 2019 and 2018

(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, 2017			3,836,397			$	383			$	8,729			$	138,320			$	(52,123	)		$	95,309			$	7,130			$	102,439
Repurchase 72,839 shares of common stock			—				—				—				—				(3,696	)			(3,696	)			—				(3,696	)
Net income (loss)			—				—				—				2,726				—				2,726				(22	)			2,704
Purchase of Non- controlling Interest			—				—				43				—				—				43				(53	)			(10	)
Balance at June 30, 2018			3,836,397			$	383			$	8,772			$	141,046			$	(55,819	)		$	94,382			$	7,055			$	101,437
Balance at December 31, 2018			2,810,000			$	281			$	7,388			$	125,644			$	(31,304	)		$	102,009			$	3,994			$	106,003
Repurchase 22,411 shares of common stock			—				—				—				—				(3,012	)			(3,012	)			—				(3,012	)
Net income			—				—				—				2,737				—				2,737				54				2,791
Purchase of Non- controlling Interest			—				—				224				—				—				224				(480	)			(256	)
Balance at June 30, 2019			2,810,000			$	281			$	7,612			$	128,381			$	(34,316	)		$	101,958			$	3,568			$	105,526

 

5

PRIMEENERGY RESOURCES CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – Unaudited

Six months ended June 30, 2019 and 2018

(Thousands of dollars)

 

		2019				2018
Cash Flows from Operating Activities:
Net Income including non-controlling interest		$	2,791			$	2,704
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities			18,550				15,832
Gain on sale of properties			(1,689	)			(2,657	)
Unrealized loss on derivative instruments, net			2,890				5,957
Provision for deferred income taxes			706				961
Changes in operating assets and liabilities:
Accounts receivable			(1,887	)			3,174
Due to related parties			(5	)			6
Other assets			160				620
Accounts payable			3,887				(12,042	)
Accrued liabilities			(11,664	)			(7,121	)
Net Cash Provided by Operating Activities			13,739				7,434
Cash Flows from Investing Activities:
Capital expenditures			(11,412	)			(18,709	)
Proceeds from sale of properties and equipment			1,693				2,112
Net Cash Used in Investing Activities			(9,719	)			(16,597	)
Cash Flows from Financing Activities:
Purchase of stock for treasury			(3,012	)			(3,696	)
Purchase of non-controlling interests			(256	)			(10	)
Proceeds from long-term bank debt and other long-term obligations			13,000				35,300
Repayment of long-term bank debt and other long-term obligations			(17,246	)			(25,428	)
Net Cash (Used in) Provided by Financing Activities			(7,514	)			6,166
Net (Decrease) Increase in Cash and Cash Equivalents			(3,494	)			(2,997	)
Cash and Cash Equivalents at the Beginning of the Period			6,315				8,438
Cash and Cash Equivalents at the End of the Period		$	2,821			$	5,441
Supplemental Disclosures:
Income taxes paid		$	130			$	4,341
Interest paid		$	2,015			$	1,950

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

 

6

PRIMEENERGY RESOURCES CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2019

(Unaudited)

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” 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, 2018. 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 June 30, 2019 and December 31, 2018, the condensed consolidated results of operations, cash flows and equity for the six months ended June 30, 2019 and 2018.

As of June 30, 2019, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018, with the exception of Accounting Standards Update (ASU) 2016-02, “Leases (Topic 842)” discussed below. 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 Adopted Accounting Pronouncements

Leases. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, “Leases (Topic 842)” (“ASC 842”) which supersedes the lease recognition requirements in Accounting Standards Codification (“ASC”) 840, “Leases” (“ASC 840”), and requires lessees to recognize lease assets and lease liabilities for those leases previously classified as operating leases. The Company adopted ASC 842 as of January 1, 2019 using the modified retrospective transition method. The Company elected to apply the transition guidance under ASU 2018-11, “Leases (Topic 842) Targeted Improvements,” in which ASC 842 is applied at the adoption date, while the comparative periods continue to be reported in accordance with historic accounting under ASC 840. This standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

ASC 842 allowed for the election of certain practical expedients at adoption to ease the burden of implementation. At implementation, the Company elected to (i) maintain the historical lease classification for leases prior to January 1, 2019, (ii) maintain the historical accounting treatment for land easements that existed at adoption, (iii) use historical practices in assessing the lease term of existing contracts at adoption, (iv) combine lease and non-lease components of a contract as a single lease and (v) not record short-term leases on the consolidated balance sheet, all in accordance with ASC 842.

The adoption of ASC 842 did not have a material impact on the consolidated statements of operations and had no impact on cash flows. The Company did not record a change to its opening retained earnings as of January 1, 2019, as there was no material change to the timing or pattern of recognition of lease costs due to the adoption of ASC 842. As of June 30, 2019, the Company has operating lease assets and liabilities of $452 thousand and a financing lease included in property and equipment and lease liabilities for $13 thousand.

New Pronouncements Issued But Not Yet Adopted

In August 2018, the FASB issued ASU 2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. ASU 2018-13 is effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. The company is currently evaluating the impact of adoption of this ASU on its related disclosures and does not expect it to have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This pronouncement is effective for fiscal years, and for interim periods within those fiscal

 

7

years, beginning after December 15, 2019. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. The Company is currently evaluating the impact of adoption of this ASU on its consolidated financial statements and does not expect it to have a material impact.

(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 $256,000 and $10,000 for the six months ended June 30, 2019 and 2018, respectively.

During the first six months of 2019 and 2018, the Company sold or farmed out interests in certain non-core oil and natural gas properties and undeveloped acreage through a number of separate, individually negotiated transactions in exchange for cash or cash and a royalty or working interest in Texas, Oklahoma, Colorado and West Virginia. Proceeds under these agreements were $1.6 million and $2.8 million, respectively.

During the first six months of 2018, the Company acquired approximately 464 net mineral acres and working interest in 53 oil and gas wells for $6.08 million and sold or farmed out interests in certain non-core undeveloped oil and natural gas properties located in Oklahoma, Kansas, Colorado and Texas, in exchange for cash and a royalty or working interest, with proceeds of $2.19 million.

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:

 

(Thousands of dollars)		June 30, 2019				December 31, 2018
Accounts Receivable:
Joint interest billing		$	2,303			$	1,976
Trade receivables			2,725				1,979
Oil and gas sales			11,131				6,112
Tax refund receivable			—				4,760
Other			913				358
			17,072				15,185
Less: Allowance for doubtful accounts			(224	)			(224	)
Total		$	16,848			$	14,961
Accounts Payable:
Trade		$	5,399			$	1,174
Royalty and other owners			5,742				6,197
Partner advances			1,335				1,357
Other			964				825
Total		$	13,440			$	9,553
Accrued Liabilities:
Compensation and related expenses		$	3,161			$	2,907
Property costs			3,606				14,993
Other			—				531
Total		$	6,767			$	18,431

 

8

(4) Property and Equipment:

Property and equipment at June 30, 2019 and December 31, 2018 consisted of the following:

 

(Thousands of dollars)		June 30, 2019				December 31, 2018
Proved oil and gas properties, at cost		$	522,239			$	514,821
Less: Accumulated depletion and depreciation			(306,116	)			(291,152	)
Oil and Gas Properties, Net		$	216,123			$	223,669
Field and office equipment		$	28,188			$	27,252
Less: Accumulated depreciation			(21,283	)			(20,496	)
Field and Office Equipment, Net		$	6,905			$	6,756
Total Property and Equipment, Net		$	223,028			$	230,425

(5) Long-Term Debt:

Bank Debt:

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. 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.

On December 22, 2017, the Company and its lenders entered into a First Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes the addition of a new lender and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $85 million.

On July 17, 2018, the Company and its lenders entered into a Second Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes modifications for the borrowing base utilization margins and rates by type of borrowing, revises minimum quantifications for individual borrowings, reduces the overall percentage required for commodity hedge agreements, modifies the requirements placed on the companies’ ability to purchase equity interests and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $90 million.

On January 8, 2019, the Company and its lenders entered into a Third Amendment to the Third Amended and Restated Credit Agreement. The credit agreement includes additions for a Beneficial Ownership Certification on the effective date of the amendment. The agreement includes further clarifications for potential Libor loan market rate issues, swap agreement modifications and retains all other aspects of the original credit agreement. As of the effective date of this amendment the Company’s borrowing base was increased to $100 million. Effective on June 26, 2019 the Company’s lenders adjusted the borrowing base to $90 million.

At June 30 2019, the Company had a total of $62 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 5.52% and $28 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 5.53% for the six months ended June 30, 2019 as compared to 5.38% for six months ended June 30, 2018. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.

Equipment Loans:

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

 

9

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.

On January 12, 2018, the Company made a principal payment towards the third interim loan in the amount of $20,858. Effective with the payment due of January 26, 2018 the required monthly payments (principal and interest) on this loan changed to $7,986 with a continuing effective rate of 3.50% and a final maturity of June 26, 2020.

On May 23, 2019, the Company made its final payment towards both the second and third loans. At this time all equipment loans have been paid in full and the field service equipment liens secured by these loans have been cancelled and all titles returned to the Company.

(6) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for office equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 5.5%. Certain leases may contain variable costs above the minimum required payments and are not included in the right-of-use assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet.

Operating lease costs for the six months ended June 30, 2019 were $293 thousand. Cash payments included in the operating lease cost for the six months ended June 30, 2019 were $284 thousand. The weighted-average remaining operating lease terms is 12 months. The amortization and interest expense for financing lease amounted to $1,275 and the cash payment for the lease was $1,200 and the lease term remaining was for 22 months.

The payment schedule for the Company’s operating and financing lease obligations as of June 30, 2019 is as follows:

 

(Thousands of dollars)		Operating Leases				Financing Leases
2019		$	299			$	5
2020			155				7
2021			17				2
Total undiscounted lease payments		$	471			$	14
Less: Amount associated with discounting			(19	)			(1	)
Net operating lease liabilities		$	452			$	13

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the six months ended June 30, 2019 is as follows:

 

(Thousands of dollars)		June 30, 2019
Asset retirement obligation at December 31, 2018		$	21,334
Liabilities incurred			—
Liabilities settled			(829	)
Accretion expense			560
Revisions in estimated liabilities			—
Asset retirement obligation at June 30, 2019		$	21,065

 

10

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.

(7) 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.

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.

(8) 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 June 30, 2019 and December 31, 2018, 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.

(9) 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 interests totaling $256,000 and $10,000 for the six months ended June 30, 2019 and 2018, respectively.

 

11

(10) 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 natural gas, crude oil price swaps and natural gas liquid 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 June 30, 2019 and December 31, 2018:

 

June 30, 2019		Quoted Prices in Active Markets For Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Balance at June 30, 2019
(Thousands of dollars)
Assets
Commodity derivative contracts		$	—			$	—			$	1,081			$	1,081
Total assets			—			$	—			$	1,081			$	1,081
Liabilities
Commodity derivative contracts		$	—			$	—			$	(1,675	)		$	(1,675	)
Total liabilities		$	—			$	—			$	(1,675	)		$	(1,675	)
December 31, 2018		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, 2018
(Thousands of dollars)
Assets
Commodity derivative contracts		$	—			$	—			$	2,394			$	2,394
Total assets		$	—			$	—			$	2,394			$	2,394
Liabilities
Commodity derivative contract		$	—			$	—			$	(98	)		$	(98	)
Total liabilities		$	—			$	—			$	(98	)		$	(98	)

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 , crude oil, natural gas liquids, 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 six months ended June 30, 2019.

 

(Thousands of dollars)
Net Asset– December 31, 2018		$	2,296
Total realized and unrealized (gains) losses:
Included in earnings (a)			(3,663	)
Purchases, sales, issuances and settlements			773
Net Liabilities June 30, 2019		$	(594	)

 

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.

 

12

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. The value of interest rate swaps if applicable, would be recorded in accumulated other comprehensive loss, net of tax. There are no current interest rate swaps for the periods ending June 30, 2019 and December 31, 2018.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at June 30, 2019 and December 31, 2018:

 

						Fair Value
(Thousands of dollars)		Balance Sheet Location				June 30, 2019				December 31, 2018
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Natural gas commodity contracts			Derivative asset short-term			$	136			$	63
Natural gas liquid contracts			Derivative asset short-term			$	185			$	138
Crude oil commodity contracts			Derivative asset short-term			$	760			$	1,473
Natural gas commodity contracts			Derivative asset long-term and other assets			$	—			$	7
Crude oil commodity contracts			Derivative asset long-term and other assets				—				713
Total						$	1,081			$	2,394
Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts			Derivative liability short-term			$	(1,675	)		$	—
Natural gas commodity contracts			Derivative liability short-term				—				(75	)
Natural gas liquid contracts			Derivative liability short-term				—				(13	)
Natural gas commodity contracts			Derivative liability long-term				—				(10	)
Total						$	(1,675	)		$	(98	)
Total derivative instruments						$	(594	)		$	2,296

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the six-month period ended June 30, 2019 and 2018:

 

		Location of gain (loss) recognized in income		Amount of gain/loss recognized in income
(Thousands of dollars)				2019				2018
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts		Unrealized gain (loss) on derivative instruments, net		$	151			$	(328	)
Crude oil commodity contracts		Unrealized loss on derivative instruments, net			(3,101	)			(5,432	)
Natural gas liquids contracts		Unrealized gain (loss) on derivative instruments, net			60				(197	)
Natural gas commodity contracts		Realized (loss) gain on derivative instruments, net			(8	)			85
Crude oil commodity contracts		Realized loss on derivative instruments, net			(876	)			(1,634	)
Natural gas liquids contracts		Realized gain (loss) on derivative instruments, net			111				(27	)
				$	(3,663	)		$	(7,533	)

 

13

(11) 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:

 

		Six Months Ended June 30,
		2019												2018
		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		$	2,737				2,031,569			$	1.35			$	2,726				2,119,343			$	1.29
Effect of dilutive securities:
Options							761,169												753,404
Diluted		$	2,737				2,792,738			$	0.98			$	2,726				2,872,747			$	0.95
		Three Months Ended June 30,
		2019												2018
		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		$	5,775				2,026,119			$	2.85			$	(560	)			2,097,737			$	(0.27	)
Effect of dilutive securities:
Options (a)							761,584
Diluted		$	5,775				2,787,702			$	2.07			$	(560	)			2,097,737			$	(0.27	)

 

(a)	The effect of the 767,500 outstanding stock option is anti-dilutive for the three months ended June 30, 2018 due to net loss for the period.

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.

 

14

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 and West Virginia. 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 approximately 19,830 gross (12,580 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused. Recent results from our wells and the wells of other operators have proven the potential of the Lower Spraberry, Jo Mill and Wolfcamp A intervals, in addition to the Middle Wolfcamp. We believe our Permian Basin acreage has the resource potential to support the future drilling of as many as 375 horizontal wells.

In Oklahoma we maintain an acreage position of approximately 81,800 gross (10,900 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 2,210 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 105 new horizontal wells based on an estimate of four to eight wells per section depending on the reservoir target area.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and availability of funds under our revolving credit facility.

District Information

The following table represents certain reserve and well information as of December 31, 2018.

 

		Appalachian				Gulf Coast				Mid- Continent				West Texas				Other				Total
Proved Reserves as of December 31, 2018 (MBoe)
Developed			559				814				2,839				8,401				8				12,622
Undeveloped			—				—				43				—				—				43
Total			559				814				2,882				8,401				8				12,665
Average Daily Production (Boe per day)			244				572				977				4,248				7				6,048
Gross Productive Wells (Working Interest and ORRI Wells)			547				293				580				558				105				2,083
Gross Productive Wells (Working Interest Only)			500				263				430				519				45				1,757
Net Productive Wells (Working Interest Only)			469				164				227				256				4				1,120
Gross Operated Productive Wells			476				211				243				354				—				1,284
Gross Operated Water Disposal, Injection and Supply wells			1				9				67				7				—				84

In several of our regions we operate field service groups to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

West Texas Region

Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The Spraberry field was discovered in 1949, encompasses eight counties in West Texas and the Company believes it is the second largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casing-head gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from six formations; the Upper and Lower Spraberry, the Wolfcamp, the Strawn and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2018, we had 519 wells (256 net) in the West Texas area, of which 361 wells are operated by us. Principal producing intervals for the

 

15

Company are in the Spraberry, Jo Mill, Wolfcamp and San Andres formations at depths ranging from 5,500 to 12,500 feet. Average net daily production in 2018 was 4,248 Boe. At December 31, 2018, we had 8,401 MBoe of proved reserves in the West Texas area, or 66% of our total proved reserves. We maintain an acreage position of approximately 19,830 gross (12,580 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, five hot oiler trucks, one kill truck and one roustabout truck. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations. In the first quarter of 2019, in our West Texas horizontal drilling program, the Company participated for 49.3% interest in eight one-mile horizontal wells drilled in the Middle Wolfcamp. These wells were brought on production in February, 2019. The total cost of these eight wells and their facilities is approximately $50.6 million, with the Company’s share being $24.9 million. Since completion these wells will have produced approximately 600,000 barrels of oil, along with associated gas. PrimeEnergy’s net revenue interest is 36.82%, therefore, our share of the oil recovered in just the first six months is approximately 212,500 barrels. We are pleased with the economic performance of these eight wells and expect 100% capital recover in less than two years.

In the second quarter of 2019, in our West Texas horizontal drilling program, we completed three new horizontal wells in intervals above the Middle Wolfcamp that previously were not proven as horizontal target reservoirs for our acreage. In the first 60 days of production the three wells have produced 125,000 gross barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower Spraberry, 46,000 barrels from the Jo Mill, and 31,000 barrels from the Upper Wolfcamp. PrimeEnergy has 49% working interest and 40.7% net revenue interest in the Lower Spraberry well, 47% working interest and 39% net revenue interest in the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the Upper Wolfcamp well. Our share of the gross $26 million cost of these three wells is approximately $8.9 million.

These three new horizontal wells in Upton County are important tests of the economic viability of the shallower target zones, both for the 1,300 acre block in which they were drilled, as well as for our nearby 2,600 leasehold AMI (Area of Mutual Interest) acreage with Apache that holds similar potential. The successful outcome has proven-up 21 additional locations in the 1,300 acre block, making these locations more likely to be drilled in the near future. The gross cost of an additional 21 wells would be approximately $182 million, with the Company’s share being $60 million. In the nearby Apache AMI, Prime holds several leases with interest varying from 14% to 56%. The strong performance of these new horizontals is likely to spur the drilling of as many as 96 additional horizontal wells in the Apache AMI over the coming years. The gross cost of 96 wells here would be approximately $748 million with the Company’s share being approximately $284 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.

In the Permian Basin of West Texas the Company maintains an acreage position of approximately 19,830 gross (12,580 net) acres primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in approximately 10 reservoir benches, including benches of the Spraberry, Jo Mill, and Wolfcamp formations to support the potential for drilling as many as 375 additional horizontal wells.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2018, we had 580 wells (227 net) in the Mid-Continent area, of which 310 wells are operated by us. Principal producing intervals are in the Roberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. Average net daily production in 2018 was 977 Boe. At December 31, 2018, we had 2,882 MBoe of proved reserves in the Mid-Continent area, or 23% of our total proved reserves. We maintain an acreage position of approximately 81,800 gross (10,900 net) acres in this region, primarily in Canadian, Kingfisher, Grant and Garvin counties. We operate a field service group in this region from a field office in Elmore City, utilizing one workover rig and one saltwater hauling truck. Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the STACK and SCOOP shale plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, Woodford, and Hunton formations.

In the Mid-Continent Region, in 2018, the Company participated in 11 wells in Oklahoma, with six of these on production by year-end. Another five of the 11 wells were drilled by Marathon in the “Ruthie 1609” tract in Kingsfisher County and brought on-line in March of 2019. Prime participated with 11.87% interest in these five new wells, investing approximately $4.9 million. This group of wells is showing strong initial production performance. This activity has now been closely followed by the

 

16

proposed drilling of 19 new wells by Encana Corporation in nearby leases in which PrimeEnergy has an average of 7.05% interest. Twelve of these wells were spud in June 2019 and the Company has agreed to participate for its average interest in these wells of 4.9% interest. Drilling and completion costs of these 19 wells net to our interest are expected to be $9.3 million. Also in Oklahoma, the Company recently participated with Roane Resources, Inc. in the drilling of seven wells in Grady County, Oklahoma. The Company has 10% interest in one of these seven wells and less than one percent interest in the remaining six. These wells were included as Proved Undeveloped in the 2018 year-end reserve report. The estimated total expenditure net to the Company is approximately $1.46 Million. Three of these seven wells came on line July, 2019 and we anticipate the other four wells will also be completed and put into production in the third quarter of 2019. In addition, there are eight new wells spud in the first and second quarter of 2019 from which the Company will receive a minor over-riding royalty interest.

The Company’s horizontal activity in Oklahoma is primarily focused in Canadian, Grady, Kingfisher, and Garvin counties where we have approximately 2,210 net leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has significant additional resource potential that could support the drilling of as many as 105 new horizontal wells based on an estimate of eight wells per section: four in the Mississippian and four in the Woodford Shale.

Appalachian Region

Our Appalachian activities are concentrated primarily in West Virginia. This region is managed from our office in Charleston, West Virginia. Our assets in this region include a large acreage position and a high concentration of wells. At December 31, 2018, we had interest in 500 wells (469 net), of which 477 wells are operated. There are multiple producing intervals that include the Big Lime, Injun, Blue Monday, Weir, Berea, Gordon and Devonian Shale formations at depths primarily ranging from 1,600 to 5,600 feet. Average net daily production in 2018 was 244 Boe. While natural gas production volumes from Appalachian reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of Appalachian reserves is relatively long. At December 31, 2018, we had 559 MBoe of proved developed reserves (substantially all natural gas) in the Appalachian region, constituting 4% of our total proved reserves. We maintain an acreage position of over 40,200 gross (39,700 net) acres in this region, primarily in Calhoun, Clay, and Roane counties. We operate a small field service group in this region utilizing one swab rig, one paraffin truck, one saltwater hauling truck and limited excavating equipment to primarily service our own operated wells and locations. As of June 30, 2019, the Appalachian region has no wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Gulf Coast Region

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 263 producing wells (164 net) in the Gulf Coast region as of December 31, 2018, of which 220 wells are operated by us. Average daily production in 2018 was 572 Boe.

At December 31, 2018, we had 925 MBoe of proved reserves in the Gulf Coast region, which represented 6% of our total proved reserves. We maintain an acreage position of over 12,700 gross (5,120 net) acres in this region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, nineteen water transport trucks, two saltwater disposal wells and several trucks and excavating equipment. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations.

As of June 30, 2019, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

 

17

Reserve Information:

Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2018. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and over ten years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over twenty-five years of experience, holds a Bachelor’s degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:

 

		Reserve Category
		Proved Developed																Proved Undeveloped																Total
As of December 31,		Oil (MBbls)				NGLs (MBbls)				Gas (MMcf)				Total (MBoe)				Oil (MBbls)				NGLs (MBbls)				Gas (MMcf)				Total (MBoe)				Oil (MBbls)				NGLs (MBbls)				Gas (MMcf)				Total (MBoe)
2016			3,107				1,265				13,001				6,539				643				159				2,003				1,135				3,750				1,424				15,004				7,674
2017			5,333				1,703				17,143				9,893				505				156				710				779				5,838				1,859				17,853				10,672
2018			6,404				2,707				21,065				12,622				10				12				124				43				6,414				2,719				21,189				12,665

 

(a)	In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.

At December 31, 2016, we had undeveloped reserves of 1,135 MBoe, attributable to 20 wells that were all put on production in the first quarter of 2017. During 2017, 22 horizontal wells were drilled and completed in West Texas, two in Oklahoma, and one vertical well in the Gulf Coast of Texas. In addition, we had an increase in reserves from overriding royalty interest in nine horizontal wells drilled in Oklahoma by other operators.

At December 31, 2017 our reserve report included 779 MBoe of proved undeveloped reserves attributable to 22 horizontal wells that were all completed in 2018, and therefore, 100% of these reserves were converted to proved developed in the 2018 year-end reserves report.

In 2018, the Company completed and put on production nine horizontal wells in West Texas and six horizontal wells in Oklahoma. Proved Developed reserves at year-end included an additional eight Shut-In horizontal wells in West Texas that have been brought on production in February, 2019 and five Shut-In horizontal wells in Oklahoma brought on production in March, 2019. In addition, at December 31, 2018, our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight horizontal wells drilled in Oklahoma. These eight wells are expected to be completed and put on production in the second and third quarters of 2019. Additional 2019 activity is discussed in the Recent Activities section below.

We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

 

18

The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2018, are summarized as follows (in thousands of dollars):

 

		Proved Developed								Proved Undeveloped								Total
As of December 31,		Future Net Revenue				Present Value 10 Of Future Net Revenue				Future Net Revenue				Present Value 10 Of Future Net Revenue				Future Net Revenue				Present Value 10 Of Future Net Revenue				Present Value 10 Of Future Income Taxes				Standardized Measure of Discounted Cash flow
2016		$	56,467			$	46,827			$	18,114			$	10,403			$	74,581			$	57,230			$	4,993			$	52,237
2017		$	160,737			$	111,614			$	13,564			$	6,100			$	174,301			$	117,714			$	10,800			$	106,914
2018		$	239,337			$	161,376			$	767			$	525			$	240,104			$	161,901			$	23,992			$	137,909

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV 10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV 10 of future income taxes represents the sole reconciling item between this non-GAAP PV 10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a major expenditure is required before the well is put on production. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 3% of our reserves.

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

While it may reasonably be anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.10 per MMBtu in 2018 as compared to $2.98 per MMBtu in 2017 and $2.49 per MMBtu in 2016. Oil prices, based on the NYMEX first of the month average price, were $65.56 per barrel in 2018 as compared to $51.34 per barrel in 2017, and $42.75 per barrel in 2016. Since January 1, 2019, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

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.

 

19

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.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2019, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2019 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.

RECENT ACTIVITIES

Since the start of our West Texas horizontal drilling program in 2015 the Company has participated in 67 horizontal wells and invested approximately $103 million dollars. The Company has an acreage position approximately 12,580 net acres in West Texas with the potential to drill 375 or more new horizontal wells. In Oklahoma, since the start in 2012 of our horizontal drilling program in the SCOOP/STACK shale plays, the Company has drilled or committed to drill 64 wells with a total investment of approximately $46 million dollars, plus has elected to receive an overriding royalty interest in 63 additional wells drilled to-date. The Company holds approximately 2,210 net acres within the SCOOP/STACK shale plays with the potential for 105 new horizontal wells.

In 2018, the Company participated in a total of 28 gross (6.1 net) horizontal wells with an investment to our share of approximately $41 million. We completed 17 horizontal wells in our West Texas horizontal development program and 11 horizontal wells in our Scoop-Stack horizontal development program in Oklahoma. All 28 wells were successful and are producing.

In the first quarter of 2019, in our West Texas horizontal drilling program, the Company participated for 49.3% interest in eight one-mile horizontal wells drilled in the Middle Wolfcamp. These wells were brought on production in February, 2019. The total cost of these eight wells and their facilities is approximately $50.6 million, with the Company’s share being $24.9 million.    Since completion these wells will have produced approximately 600,000 barrels of oil, along with associated gas. PrimeEnergy’s net revenue interest is 36.82%, therefore, our share of the oil recovered in just the first six months is approximately 212,500 barrels. We are pleased with the economic performance of these eight wells and expect 100% capital recover in less than two years.

In the second quarter of 2019, in our West Texas horizontal drilling program, we completed three new horizontal wells in intervals above the Middle Wolfcamp that previously were not proven as horizontal target reservoirs for our acreage. In the first 60 days of production the three wells have produced 125,000 gross barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower Spraberry, 46,000 barrels from the Jo Mill, and 31,000 barrels from the Upper Wolfcamp. PrimeEnergy has 49% working interest and 40.7% net revenue interest in the Lower Spraberry well, 47% working interest and 39% net revenue interest in the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the Upper Wolfcamp well. Our share of the gross $26 million cost of these three wells is approximately $8.9 million.

These three new horizontal wells in Upton County are important tests of the economic viability of the shallower target zones, both for the 1,300 acre block in which they were drilled, as well as for our nearby 2,600 leasehold AMI acreage with Apache that holds similar potential. The successful outcome has proven-up 21 additional locations in the 1,300 acre block, making these locations more likely to be drilled in the near future. The gross cost of an additional 21 wells would be approximately $182 million, with the Company’s share being $60 million. In the nearby Apache AMI, Prime holds several leases with interest varying from 14% to 56%. The strong performance of these new horizontals is likely to spur the drilling of as many as 96 additional horizontal wells in the Apache AMI over the coming years. The gross cost of 96 wells here would be approximately $748 million with the Company’s share being approximately $284 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.

In the Permian Basin of West Texas the Company maintains an acreage position of approximately 19,830 gross (12,580 net) acres primarily in Reagan, Upton, Martin and Midland counties. We believe this acreage has significant resource potential in approximately 10 reservoir benches, including benches of the Spraberry, Jo Mill, and Wolfcamp formations to support the potential for drilling as many as 375 additional horizontal wells.

In Oklahoma, in 2018, the Company participated in 11 wells, with six of these on production by year-end. Five of these wells, drilled by Marathon in the “Ruthie 1609” tract in Kingsfisher County, were brought on-line in March of 2019. Prime participated with 11.87% interest in these five new wells, investing approximately $4.9 million. This group of wells is showing strong initial production performance. This activity has now been closely followed by the proposed drilling of 19 new wells by

 

20

Encana Corporation in nearby leases in which PrimeEnergy has an average of 7.05% interest. Twelve of these wells were spud in June 2019 and the Company has agreed to participate for its average interest in these wells of 4.9% interest. Drilling and completion costs of these 19 wells net to our interest are expected to be $9.3 million.

Also in Oklahoma, the Company recently participated with Roane Resources, Inc. in the drilling of seven wells in Grady County, Oklahoma. The Company has 10% interest in one of these seven wells and less than one percent interest in the remaining six. The estimated total expenditure net to the Company is approximately $1.46 Million. Three of these seven wells came on line July, 2019 and we anticipate the other four wells will also be completed and put into production in the third quarter of 2019. In addition, there are eight new wells spud in the first and second quarter of 2019 from which the Company will receive a minor over-riding royalty interest.

The Company’s horizontal activity in Oklahoma is primarily focused in Canadian, Grady, Kingfisher, and Garvin counties where we have approximately 2,210 net leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has significant additional resource potential that could support the drilling of as many as 105 new horizontal wells based on an estimate of eight wells per section: four in the Mississippian and four in the Woodford Shale.

RESULTS OF OPERATIONS

2019 and 2018 Compared

We reported net income of $2.7 million, or $1.35 per share and $5.8 million, or $2.85 per share for the six and three months ended June 30, 2019, respectively, as compared to net income for the six months ended June 30, 2018 of $2.7 million, or $1.29 per share and a net loss for the three months ended June 30, 2018 of $0.6 million, or $0.27 per share. Current year net income reflects an increase in production combined with commodity price changes over the three and six months ended June 30, 2019, decrease in gains related to the sale of acreage and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales increased $1.7 million, or 8% from $21.7 million for the three months ended June 30, 2018 to $23.4 million for the three months ended June 30, 2019 and increased $0.5 million, or 1% from $46.8 million for the six months ended June 30, 2018 to $47.2 million for the six months ended June 30, 2019.

Our realized prices at the well head decreased an average of $4.52 per barrel, or 7% and $7.04 per barrel, or 11% on crude oil during the three and six months ended June 30, 2019, respectively from the same periods in 2018. Our average price for natural gas decreased $1.01 per Mcf, or 49% and $0.73 per Mcf, or 31% during the three and six months ended June 30, 2019, respectively from the same periods in 2018. Our average price for NGLs sold decreased an average of $11.15 per barrel, or 41% and $8.61 per barrel, or 32% during the three and six months ended June 30, 2019, respectively from the same periods in 2018. Production increases were negatively impacted by natural gas prices at the Waha hub where Permian Basin production exceeded West Texas takeaway capacity. Gas prices traded at historic lows, and at times were negative, for portions of the second quarter of 2019. This gas pricing is expected to continue until Waha prices improve, which is anticipated when the third-party operated Gulf Coast Express (GCX) pipeline enters service in late September.

Our crude oil production increased by 71,000 barrels or 27% from 261,000 barrels for the second quarter 2018 to 332,000 barrels for the second quarter 2019 and increased by 104,000 barrels, or 18% from 584,000 barrels for the six months ended June 30, 2018 to 688,000 barrels for the six months ended June 30, 2019. Our natural gas production increased by 331,000 Mcf, or 34% from 964,000 Mcf for the second quarter 2018 to 1,295,000 Mcf for the second quarter 2019 and increased by 372,000 Mcf, or 20% from 1,871,000 Mcf for the six months ended June 30, 2018 to 2,243,000 Mcf for the six months ended June 30, 2019. Our NGL production increased by 33,000 barrels or 29% from 113,000 barrels for the second quarter 2018 to 146,000 barrels for the second quarter 2019 and increased by 75,000 barrels, or 35% from 213,000 barrels for the six months ended June 30, 2018 to 288,000 barrels for the six months ended June 30, 2019. The net increase in production volumes reflect by production from new wells added in February through May 2019, offset with the natural decline of the previously existing properties.

The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended June 30, 2019 and 2018 (excluding realized gains and losses from derivatives).

 

						Six months ended June 30,
		2019				2018				Increase / (Decrease)				Increase / (Decrease)
Barrels of Oil Produced			688,000				584,000				104,000				18	%
Average Price Received		$	55.84			$	62.88			$	(7.04	)			(11	)%
Oil Revenue (In 000’s)		$	38,442			$	36,723			$	1,719				5	%
Mcf of Gas Sold			2,243,000				1,871,000				372,000				20	%

 

21

						Six months ended June 30,
		2019				2018				Increase / (Decrease)				Increase / (Decrease)
Average Price Received		$	1.60			$	2.33			$	(0.73	)			(31	)%
Gas Revenue (In 000’s)		$	3,590			$	4,352			$	(762	)			(18	)%
Barrels of Natural Gas Liquids Sold			288,000				213,000				75,000				35	%
Average Price Received		$	18.14			$	26.75			$	(8.61	)			(32	)%
Natural Gas Liquids Revenue (In 000’s)		$	5,219			$	5,698			$	(479	)			(8	)%
Total Oil & Gas Revenue (In 000’s)		$	47,251			$	46,773			$	478				1	%

 

						Three months ended June 30,
		2019				2018				Increase / (Decrease)				Increase / (Decrease)
Barrels of Oil Produced			332,000				261,000				71,000				27	%
Average Price Received		$	59.17			$	63.69			$	(4.52	)			(7	)%
Oil Revenue (In 000’s)		$	19,644			$	16,622			$	3,022				18	%
Mcf of Gas Sold			1,295,000				964,000				331,000				34	%
Average Price Received		$	1.05			$	2.06			$	(1.01	)			(49	)%
Gas Revenue (In 000’s)		$	1,355			$	1,989			$	(634	)			(32	)%
Barrels of Natural Gas Liquids Sold			146,000				113,000				33,000				29	%
Average Price Received		$	16.27			$	27.42			$	(11.15	)			(41	)%
Natural Gas Liquids Revenue (In 000’s)		$	2,375			$	3,098			$	(723	)			(23	)%
Total Oil & Gas Revenue (In 000’s)		$	23,374			$	21,709			$	1,665				8	%

Oil, Natural Gas and NGL Derivatives 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. The following table summarizes the results of our derivative instruments for the three and six months ended June 2019 and 2018:

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2019				2018				2019				2018
						($ in thousand)
Oil derivatives – realized gains (losses)		$	(964	)		$	(1,156	)		$	(876	)		$	(1,634	)
Oil derivatives – unrealized gains (losses)			2,637				(3,564	)			(3,101	)			(5,432	)
Total gains (losses) on oil derivatives		$	1,673			$	(4,720	)		$	(3,977	)		$	(7,066	)
Natural gas derivatives – realized gains (losses)		$	4			$	105			$	(8	)		$	85
Natural gas derivatives – unrealized gains (losses)			156				(249	)			151				(328	)
Total gains (losses) on natural gas derivatives		$	160			$	(144	)		$	143			$	(243	)
NGL derivatives – realized gain (losses)		$	109			$	(30	)		$	111			$	(27	)
NGL derivatives – unrealized gains (losses)			69				(323	)			60				(197	)
Total gains (losses) on NGL derivatives			178				(353	)			171				(225	)
Total gains (losses) on oil, natural gas and NGL derivatives		$	2,011			$	(5,217	)		$	(3,663	)		$	(7,533	)

Prices received for the six months ended June 30, 2019 and 2018, respectively, including the impact of derivatives were:

 

		2019				2018
Oil Price		$	54.56			$	59.26
Gas Price		$	1.00			$	2.17
NGLS Price		$	18.52			$	27.15

 

22

Field service income increased $0.4 million or 0.01% from $4.4 million for the second quarter 2018 to $4.8 million for the second quarter 2019 and $0.8 million, or 0.01% from $8.7 million for the six months ended June 30, 2018 to $9.5 million for the six months ended June 30, 2019. This increase is a combined result of increased utilization and rates charged to customers during the 2019 period. Workover rig services, hot oil treatments, salt water hauling and disposal represent the bulk of our field service operations.

Lease operating expense decreased $0.7 million or 0.01% from $8.8 million for the second quarter 2018 to $8.1 million for the second quarter 2019, and decreased $1.1 million or 0.01% from $17.3 million for the six months ended June 30, 2018 to $16.2 million for the six months ended June 30, 2019. This decrease is primarily due to the sales of high lifting cost properties during 2019 combined with lower production taxes related to lower commodity prices, offset by costs related to new wells brought on-line and general rate increases on vendor services during the first three months of 2019 as compared to the same period of 2018.

Field service expense increased $0.8 million or 0.02% from $3.2 million for the second quarter 2018 to $4.0 million for the second quarter 2019 and increased $1.2 million, or 0.02% from $6.4 million for the six months ended June 30, 2018 to $7.6 million for the six months ended June 30, 2019. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the six months ended June 30, 2019 over the same period of 2018 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $1.4 million, or 0.02% from $7.9 million for the second quarter 2018 to $9.3 million for the second quarter 2019 and $2.8 million, or 0.02% from $15.8 million for the six months ended June 30, 2018 to $18.6 million for the six months ended June 30, 2019, reflecting the increased production related to new wells placed on production late in 2018 and the first two quarters of 2019.

General and administrative expense increased $1.3 million, or 0.01% from $8.5 million for the six months ended June 30, 2018 to $9.8 million for the six months ended June 30, 2019, and increased $0.3 million, or 0.01% from $2.6 million for the three months ended June 30, 2018 to $2.9 million for the three months ended June 30, 2019. This increase in 2019 reflects the combination of a reduction in G&A reimbursements related to the sale of property and increases in personnel costs.

Gain on sale and exchange of assets of $2.7 million and $1.7 million for the six months ended June 30, 2018 and June 30, 2019, respectively consists of sales of non-essential oil and gas interests and field service equipment.

Interest expense increased from $0.9 million for the second quarter 2018 to $1.0 million for the second quarter 2019 and from $1.8 million for the six months ended June 30, 2018 to $2.0 million for the six months ended June 30, 2019. This increase reflects the increase in current borrowings under our revolving credit agreement.

Income tax expense for the June 30, 2018 and 2019 periods varied due to the change in net income for those 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 six months ended June 30, 2019 was $13.7 million compared to $7.4 million for the six months ended June 30, 2018. 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 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.

 

23