Edgar Filing: PRIMEENERGY CORP

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Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

¨	TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From to .

Commission File Number 0-7406

PrimeEnergy Corporation

(Exact name of registrant as specified in its charter)


Delaware		84-0637348
(state or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

9821 Katy Freeway, Houston, Texas		77024
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 735-0000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, par value $.10 per share

(Title of Class)

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate whether 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 filing requirements for the past 90 days. Yes x 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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a small reporting company.

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the voting stock of the Registrant held by non-affiliates, computed by reference to the average bid and asked price of such common equity as of the last business day of the Registrant’s most recently completed second fiscal quarter, was $52,718,414

The number of shares outstanding of each class of the Registrant’s Common Stock as of March 4, 2015 was 2,316,459 shares, Common Stock, $0.10 par value.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s proxy statement to be furnished to stockholders in connection with its Annual Meeting of Stockholders to be held in May 2015, are incorporated by reference in Part III hereof.

TABLE OF CONTENTS


PART I
	Item 1.	Business	4
	Item 1A.	Risk Factors	16
	Item 1B.	Unresolved Staff Comments	23
	Item 2.	Properties	23
	Item 3.	Legal Proceedings	29
	Item 4.	Mine Safety Disclosures	29

PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
	Item 6.	Selected Financial Data	31
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	36
	Item 8.	Financial Statements and Supplementary Data	36
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	36
	Item 9A.	Controls and Procedures	36
	Item 9B.	Other Information	37

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	38
	Item 11.	Executive Compensation	38
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	38
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	38
	Item 14.	Principal Accountant Fees and Services	38

PART IV
	Item 15.	Exhibits and Financial Statement Schedules	39

SIGNATURES			43

FINANCIAL STATEMENTS:
	Index to Consolidated Financial Statements		F-1

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 statement or to update the reasons why actual results could differ from those projected in the forward-looking statements.

PrimeEnergy Corporation

FORM 10-K ANNUAL REPORT

For the Fiscal Year Ended

December 31, 2014

PART I

Item 1.

BUSINESS.

General

PrimeEnergy Corporation (the “Company”) was organized in March, 1973, under the laws of the State of Delaware.

We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana. All of our oil and gas properties and interests are located in the United States. Through our subsidiaries Prime Operating Company, Southwest Oilfield Construction Company, Eastern Oil Well Service Company and EOWS Midland Company, we act as operator and provide well servicing support operations for many of the onshore oil and gas wells in which we have an interest, as well as for third parties. We have owned and operated properties in the Gulf of Mexico through our subsidiary Prime Offshore L.L.C. We are also active in the acquisition of producing oil and gas properties through joint ventures with industry partners. Our subsidiary, PrimeEnergy Management Corporation (“PEMC”), acts as the managing general partner of eighteen oil and gas limited partnerships (the “Partnerships”), and acts as the managing trustee of two asset and income business trusts (“the Trusts”).

Exploration, Development and Recent Activities

The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance, we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zones with a lateral wellbore. Our Oklahoma horizontal development is primarily in Grant and Canadian counties where we have approximately 6,450 net acres which we believe have significant resource potential based on our drilling results and those of offset operators. We began our West Texas, Upton County horizontal drilling program in the first quarter of 2015, and will drill up to 4 wells in this phase at a net cost of approximately $10 million. The first well was spudded March 17, 2015 and discussions with our joint venture partner in that program, Apache Corporation, indicate that including additional phases of development in the program will result in approximately 60 horizontal wells being drilled over the next 18 to 24 months at a cost of approximately $470 million. The actual number of wells to be drilled and the timing of the drilling may vary based on commodity market conditions. We own various interests, ranging from 16% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. We maintain an acreage position of over 26,000 gross (16,500 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We have currently identified 126 proved undeveloped drilling locations there and believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional drilling locations opportunities.

As of December 31, 2014, we had net capitalized costs related to proved oil and gas properties of $208 million. Total expenditures for the acquisition, exploration and development of our properties during 2014 were $36 million. In addition, during 2014 we spent $2.8 million to update and increase our field service equipment. Proved reserves as of December 31, 2014, were 37,200 thousand barrels of oil equivalent (“MBoe”) which consisted of 37% proved developed reserves and 63% proved undeveloped reserves.

Significant 2014 Activity

During 2014, we participated in drilling a total of 25 gross (11.50 net) wells; all of these wells are currently producing. This included 7 wells in our West Texas drilling program, one well in our Gulf Coast region and the drilling of 17 wells in our Mid-Continent region.

In July 2014, we executed equipment financing facilities totaling $6.0 million. In August 2014 and December 2014 we drew down $4.8 million and $0.5 million, respectively, of this facility that is secured by field service equipment recently purchased and these proceeds were used to pay down on our revolving credit facility, and as a result, free up additional funds under the credit facility for future acquisitions, development and operations. The remaining $0.7 million under this facility is available to finance the acquisition of any future field service equipment. During 2014, we decreased our outstanding debt under the revolving credit facility by $23.6 million from $112.5 million at December 31, 2013 to $88.9 million as of December 31, 2014. As of December 31, 2014 we have $41.1 million available for future borrowings.

We believe that our diversified portfolio approach to our drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile.

We attempt to assume the position of operator in all acquisitions of producing properties. We will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests and are actively pursuing the acquisition of producing properties. 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 increase our net worth and increase our oil and gas reserve base.

We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana, and we own a substantial amount of well servicing equipment.

We do not own any refinery or marketing facilities, and do not currently own or lease any bulk storage facilities or pipelines other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems. All of our oil and gas properties and interests are located in the United States.

In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of shut-in and/or reduced takes of gas production during summer months. Prolonged shut-ins could result in reduced field operating income from properties in which we act as operator.

Exploration for oil and gas requires substantial expenditures particularly in exploratory drilling in undeveloped areas, or “wildcat drilling.” As is customary in the oil and gas industry, substantially all of our exploration and development activities are conducted through joint drilling and operating agreements with others engaged in the oil and gas business.

Summaries of our oil and gas drilling activities, oil and gas production, and undeveloped leasehold, mineral and royalty interests are set forth under Item 2., “Properties,” below. Summaries of our oil and gas reserves, future net revenue and present value of future net revenue are also set forth under Item 2., “Properties—Reserves”, below.

Well Operations

Our operations are conducted through our principal offices in Houston, Texas, and district offices in Houston and Midland, Texas, Oklahoma City, Oklahoma, and Charleston, West Virginia. We currently operate 1,555 wells, 328 through the Houston office, 379 through the Midland office, 371 through the Oklahoma City

office and 477 through the Charleston, West Virginia office. Substantially all of the wells we operate are wells in which we have an interest.

We operate wells pursuant to operating agreements which govern the relationship between us, as operator, and the other owners of working interests in the properties, including the Partnerships, Trusts and joint venture participants. For each operated well, we receive monthly fees that are competitive in the areas of operations and also are reimbursed for expenses incurred in connection with well operations.

The Partnerships, Trusts and Joint Ventures

Since 1975, PEMC has acted as managing general partner of various partnerships, trusts and joint ventures.

PEMC, as managing general partner of the Partnerships and managing trustee of the Trusts, is responsible for all Partnership and Trust activities, the drilling of development wells and the production and sale of oil and gas from productive wells. PEMC also provides administration, accounting and tax preparation for the Partnerships and Trusts from our offices in Stamford, Connecticut. PEMC is liable for all debts and liabilities of the Partnerships and Trusts, to the extent that the assets of a given limited partnership or trust are not sufficient to satisfy its obligations. We stopped sponsoring partnerships and trusts in 1992. Today there are only 18 partnerships and 2 trusts remaining. The aggregate number of limited partners in the Partnerships and beneficial owners of the Trusts now administered by PEMC is approximately 1989.

Regulation

Regulation of Oil and Natural Gas Exploration and Production:

Exploration and production operations of oil and natural gas are subject to various types of regulations under a wide range of local, state and federal statutes, rules, orders and regulations. These regulations include requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

Our offshore operations were conducted on federal leases which are administered by the Bureau of Ocean Energy Management (the “BOEM”) and are required to comply with the regulations and orders promulgated by the BOEM under the Outer Continental Shelf Lands Act (“OCSLA”). These leases required compliance with detailed BOEM, Bureau of Safety and Environmental Enforcement (the “BSEE”), and other government agency regulations and orders that are subject to interpretation and change. The BOEM and BSEE have promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines.

The failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions affecting operations.

Regulation of Transportation and Sale of Natural Gas:

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended (“NGA”), the Natural Gas Policy Act of 1978, as amended (“NGPA”), and regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”) and its predecessors. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended (the “Decontrol Act”). Effective January 1, 1993, the Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas and deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005, as amended (the “2005 Act”), the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established new regulations that are intended to increase natural gas pricing transparency through, among other things, requiring market participants to report their gas sales transactions annually to the FERC, and new regulations that require certain non-interstate pipelines to post daily scheduled volume information and design capacity for certain points on their systems. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC’s regulations. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties in an effort to add greater fairness, consistency and transparency to its enforcement program.

Our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation, because the prices we receive for our production are affected by the cost of transporting the gas to the consuming market. Through a series of comprehensive rulemakings, beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and most pipelines have also implemented the large-scale divestiture of their gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generally provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. Sellers and buyers of gas have gained direct access to the particular pipeline services they need, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict

what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.

The OCSLA, which is administered by the BOEM and the FERC, requires that all pipelines operating on or across the Outer Continental Shelf (“OCS”) provide open access, non-discriminatory transportation service. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, the BOEM issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.

In December 2007, the FERC issued rules (Order No. 704) requiring that any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtu”) during a calendar year must annually report, starting May 1, 2009, such sales and purchases to the FERC. These rules are intended to increase transparency of the wholesale natural gas markets and assist the FERC in monitoring such markets and in detecting market manipulation.

Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from the effect of such regulation on competitors.

Regulation of Transportation and Sale of Oil:

Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service, and that such service not be unduly discriminatory or preferential.

Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer

Price Index for Finished Goods plus 2.65 percent should be the oil pricing index for the five-year period beginning July 1, 2011. The result of indexing is a “ceiling rate” for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost-of-service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of the Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the services provided, that were a basis for the rate. There is no such limitation on complaints alleging that the pipeline’s rates or term and conditions of service are unduly discriminatory or preferential.

Another FERC matter that may impact our transportation costs relates to a policy that allows a pipeline structured as a master limited partnership or similar non-corporate entity to include in its rates a tax allowance with respect to income for which there is an “actual or potential income tax liability,” to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We currently do not transport any of our oil or natural gas liquids on a pipeline structured as a master limited partnership.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe the regulation of oil transportation rates will not affect our operations in any way that is materially different from the effect of such regulation on competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe access to oil pipeline transportation services generally will be available to us to the same extent as to competitors.

In November 2009, the Federal Trade Commission (the “FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1.0 million per violation per day. In July 2010, the U.S. Congress passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (the “CFTC”) to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FERC with respect to anti-manipulation in the gas industry and the FTC with respect to oil purchases and sales, as described above. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation.

Transportation of Hazardous Materials:

The federal Department of Transportation has adopted regulations requiring that certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation of hazardous materials. The Company does not believe that these requirements will have an adverse effect on the Company or its operations. The Company cannot provide any assurance that the security plans required under these regulations would protect against all security risks and prevent an attack or other incident related to the Company’s transportation of hazardous materials.

Environmental Regulations:

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), the Federal Oil Pollution Act of 1990, as amended (“OPA”), the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), the Safe Drinking Water Act of 1974, as amended (the “Safe Drinking Water Act”), and the Federal Clean Air Act, as amended (the “Clean Air Act”) affect our operations and costs. In particular, exploration, development and production operations, activities in connection with storage and transportation of oil and other hydrocarbons and use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state legislation. These laws and regulations:

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

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impose substantial liabilities for pollution resulting from operations.

Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief. Changes in environmental laws and regulations occur regularly, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the oil and natural gas industry in general. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.

The transition zone and shallow-water areas of the U.S. Gulf Coast are ecologically sensitive. Environmental issues have led to higher drilling costs and a more difficult and lengthy well permitting process. U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.

As with the industry generally, compliance with existing regulations increases the overall cost of business. The areas affected include:

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unit production expenses primarily related to the control and limitation of air emissions and the disposal of produced water;

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capital costs to drill exploration and development wells primarily related to the management and disposal of drilling fluids and other oil and natural gas exploration wastes; and

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capital costs to construct, maintain and upgrade equipment and facilities.

Superfund. The CERCLA, also known as the “Superfund” law, and comparable state laws and regulations imposes liability, without regard to fault or the legality of the original conduct, on certain parties with respect to the release of hazardous substances into the environment. These parties include the current and past owners and

operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such parties may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency (“EPA”), and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible

parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substance released into the environment. In the course of ordinary operations, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

We currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on, under or from the properties currently owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, these properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

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to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators;

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to clean up contaminated property, including contaminated groundwater; or

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to perform remedial operations to prevent future contamination.

At this time, we do not believe that we are associated with any Superfund site and have not been notified of any claim, liability or damages under CERCLA.

Oil Pollution Act of 1990. The OPA and regulations thereunder impose liability on responsible parties for damages resulting from oil spills into or upon navigable waters, and adjoining shorelines or in the exclusive economic zone of the United States. Liability under OPA is strict, and under certain circumstances joint and several, and potentially unlimited. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150.0 million depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in the oil and gas industry. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA and believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on our operations.

U.S. Environmental Protection Agency. The U.S. Environmental Protection Agency regulations address the disposal of oil and natural gas operational wastes under three federal acts more fully discussed in the paragraphs

that follow. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), provides a framework for the safe disposal of discarded materials and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited under the authority of the Clean Water Act. When injected underground, oil and natural gas wastes are regulated by the Underground Injection Control program under the Safe Drinking Water Act. If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed at an approved hazardous waste facility. We have coverage under the Region VI National Production Discharge Elimination System Permit

for discharges associated with exploration and development activities. We take the necessary steps to ensure all offshore discharges associated with a proposed operation, including produced waters, will be conducted in accordance with the permit.

Resource Conservation and Recovery Act. The RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failure to meet such requirements on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because the operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

Clean Water Act. The Clean Water Act and resulting regulations imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges.

Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Safe Drinking Water Act. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. The Safe Drinking Water Act establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In Louisiana and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to abide by the permits could subject us to civil and/or criminal enforcement. We believe we are in compliance in all material respects with the requirements of applicable state underground injection control programs and permits.

Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids, usually consisting mostly of water but typically including small amounts of several chemical additives, as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including but not limited to requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

Greenhouse Gas. Based on findings made by the EPA in December 2009 that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources, should such sources exceed threshold emission levels.

While Congress has, from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future federal laws or regulations that impose reporting obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operations could have an adverse effect on our cost of doing business and could adversely affect demand for the oil and gas we produce.

Marine Protected Areas. Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

Marine Mammal and Endangered Species. Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). The Bureau of Safety and Environmental Enforcement (“BSEE”) also issue numerous regulations under the nomenclature Notice to Lessees and Operators (“NTL”) that provide formal guidelines on implementation of OCS regulations and standards. We believe we are in compliance in all material respects with the requirements regarding protection of marine species.

Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including OCSLA, the National Environmental Policy Act (“NEPA”), and the Coastal Zone Management Act (“CZMA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for instance, requires the U.S. Department of Interior (“DOI”) to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires DOI and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the DOI, we must certify that we will conduct our activities in a manner consistent with an applicable program.

Lead-Based Paints. Various pieces of equipment and structures we own may have been coated with lead-based paints as was customary in the industry at the time these pieces of equipment were fabricated and constructed. These paints may contain lead at a concentration high enough to be considered a regulated hazardous waste when removed. If we need to remove such paints in connection with maintenance or other activities and they qualify as a regulated hazardous waste, this would increase the cost of disposal. High lead levels in the paint might also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and BSEE to ensure worker safety during paint removal.

Air Pollution Control. The Clean Air Act and state air pollution laws adopted to fulfill its mandates provide a framework for national, state and local efforts to protect air quality. Operations utilize equipment that emits air pollutants subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Air emissions associated with offshore activities are projected using a matrix and formula supplied by BSEE, which has primacy from the EPA for regulating such emissions.

Naturally Occurring Radioactive Materials. Naturally Occurring Radioactive Materials (“NORM”) are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and natural gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection, treatment, storage and disposal of NORM waste, management of waste piles, containers and tanks, and limitations upon the release of NORM contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards established by the states, as applicable.

OSHA and Other Laws and Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA), and comparable state laws. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.

Taxation

Our oil and gas operations are affected by federal income tax laws applicable to the petroleum industry. For U.S. income tax reporting purposes, intangible drilling and development costs incurred or borne during the year are permitted to be deducted currently, rather than capitalized. As an independent producer, we are also entitled to a deduction for percentage depletion with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced, if such percentage depletion exceeds cost depletion. Generally, this deduction is computed based upon the lesser of 100% of the net income, or 15% of the gross income from a property, without reference to the basis in the property. The amount of the percentage depletion deduction so computed which may be deducted in any given year is limited to 65% of taxable income. Any percentage depletion deduction disallowed due to the 65% of taxable income test may be carried forward indefinitely.

During the past several years, many changes to the tax code have been proposed which would, if adopted, repeal many tax incentives and deductions that have significantly reduced our tax liabilities in the current and previous years. The proposals include the repeal of the percentage depletion allowance for oil and natural gas properties, elimination of the ability to fully deduct intangible drilling costs in the year incurred, and the repeal of the manufacturing tax deduction for oil and gas companies. Should some or all of these proposals become law, our taxes will increase, potentially significantly, which would have a negative effect on our net income and cash flows.

See Notes 1 and 9 to the consolidated financial statements included in this Report for a discussion of accounting for income taxes.

Competition and Markets

The business of acquiring producing properties and non-producing leases suitable for exploration and development is highly competitive. Our competition, in our efforts to acquire both producing and non-producing properties, include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those available to us. Furthermore, domestic producers of oil and gas must not only compete with each other in marketing their output, but must also compete with producers of imported oil and gas and alternative energy sources such as coal, nuclear power and hydroelectric power. Competition among petroleum companies for favorable oil and gas properties and leases can be expected to increase.

The availability of a ready market for any oil and gas produced by us at acceptable prices per unit of production will depend upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the proximity of our producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels. There is no assurance that we will be able to market all of the oil or gas produced by us or that favorable prices can be obtained for the oil and gas production.

Major Customers

Listed below are the percent of our total oil and gas sales made to each of our customers whose purchases represented more than 10% of our oil and gas sales in 2014.


Oil Purchasers:
Plains All American Inc.	46	%
Sunoco, Inc.	26	%
Gas Purchasers:
Atlas Pipeline Mid-Continent	37	%
Unimark LLC	13	%

Although there are no long-term purchasing agreements with these purchasers, we believe that they will continue to purchase our oil and gas products and, if not, could be readily replaced by other purchasers.

Employees

At March 1, 2015, we had 226 full-time and 4 part-time employees, 36 of whom were employed at our principal offices in Houston, Texas, at the offices of Prime Operating Company, Eastern Oil Well Service Company, EOWS Midland Company and Prime Offshore L.L.C., 12 employees in Stamford, Connecticut, and 182 employees who were primarily involved in our district operations in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia.

Item 1A.

RISK FACTORS.

Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Natural gas prices increased from an average price of $3.73 per MMbtu in 2013 to an average price of $4.37 per MMbtu in 2014. Oil prices decreased from an average price of $97.98 per barrel in 2013 to an average price of $93.17 per barrel in 2014. Depressed prices in the future would have a negative impact on our future financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

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the level of consumer product demand;

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weather conditions;

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political conditions in natural gas and oil producing regions, including the Middle East;

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the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

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the price of foreign imports;

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actions of governmental authorities;

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pipeline capacity constraints;

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inventory storage levels;

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domestic and foreign governmental regulations;

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the price, availability and acceptance of alternative fuels; and

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overall economic conditions.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

Drilling natural gas and oil wells is a high-risk activity.

Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

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unexpected drilling conditions, pressure or irregularities in formations;

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equipment failures or accidents;

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adverse weather conditions;

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compliance with governmental requirements; and

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shortages or delays in the availability of required goods or services such as drilling rigs or crews, the delivery of equipment and the availability of sufficient water for drilling operations.

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

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the results of exploration efforts and the acquisition, review and analysis of the seismic data;

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the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

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the approval of the prospects by other participants after additional data has been compiled;

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economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;

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our financial resources and results; and

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the availability of leases and permits on reasonable terms for the prospects.

These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.

Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

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the quality and quantity of available data;

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the interpretation of that data;

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the accuracy of various mandated economic assumptions; and

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the judgment of the persons preparing the estimate.

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on 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, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (“FASB”) in Accounting Standards Codification (“ASC”) Section 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

The Company’s expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.

The Company has identified drilling locations and prospects for future drilling opportunities, including development and infill drilling activities. These drilling locations and prospects represent a significant part of the Company’s future drilling plans. The Company’s proved reserves as of December 31, 2014 include proved undeveloped reserves of 14.7 MMBbls of oil, 4.3 MMBbls of NGLs and 26.3 Bcf of gas. The Company’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could adversely impact the Company’s ability to successfully complete those programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely impact the Company’s ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately meet the Company’s expectations for success. As such, the Company’s actual drilling activities may materially differ from the Company’s current expectations, which could have a significant adverse effect on the Company’s proved reserves, financial condition and results of operations.

Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.

In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.

We are continually identifying and evaluating opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.

We face a variety of hazards and risks that could cause substantial financial losses.

Our business involves a variety of operating risks, including:

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blowouts, cratering and explosions;

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mechanical problems;

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uncontrolled flows of natural gas, oil or well fluids;

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formations with abnormal pressures;

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pollution and other environmental risks; and

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natural disasters.

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures.

We may not be insured against all of the operating risks to which we are exposed.

We maintain insurance coverage against certain, but not all, hazards that could arise from our operations both onshore and offshore. Such insurance is believed to be reasonable for the hazards and risks faced by us. We do not carry business interruption insurance. In addition pollution and environmental risks are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

As of December 31, 2014, we maintain for onshore operations total excess liability insurance with limits of $20 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per occurrence, subject to all terms, restrictions and sub-limits of the policies. Through July 30, 2012, when plugging and abandonment of our operated offshore properties were substantially complete, we also maintained for offshore operations total excess liability insurance with limits of $35 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per occurrence, subject to all terms, restrictions and sub-limits of the policies. We also maintain general liability insurance limits of $1 million per occurrence and $2 million in the aggregate for our onshore operations.

We have several policies that cover environmental risks. We have environmental coverage under the per occurrence and aggregate limits of our general and umbrella liability policies (for a twelve-month term). These policies provide third-party surface cleanup, bodily injury and property damage coverage, and defense costs when a pollution event is sudden and accidental and is discovered within thirty days of commencement and reported to the insurance company within ninety days of discovery. This is standard coverage in oil and gas insurance policies.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of limits sufficient to meet the legal financial responsibility requirement of the BSEE as prescribed under the OPA and individual state legal financial responsibility requirements.

Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers and contractors. However, customers and contractors who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

With regard to our offshore operations, generally, indemnities and insurance limits for each contract are negotiated with each of our contractors. Our contracts generally follow the industry standard of providing mutual hold harmless and indemnity agreements, which results in each party being liable or responsible for all claims related to its employees and its contractors, as well as any damage to its and its contractor’s property. Currently, substantially all of our contracts contain mutual hold harmless and indemnity provisions.

From time to time, a small number of our contractors have requested contractual provisions that require us to respond to third-party claims. In some of these instances we have accepted the risk with the understanding that it would be covered under our current coverage. We evaluate these risk-transferring negotiations cautiously, and we feel that we have adequately mitigated this risk through existing coverage or acquiring supplemental coverage when appropriate.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.

Bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Terrorist activities and the potential for military and other actions could adversely affect our business.

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.

Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.

We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. These hedging arrangements limit the benefit to us of increases in prices. While there are many different types of derivatives available, we generally utilize collar and swap agreements to attempt to manage price risk more effectively.

The collar arrangements are put and call options used to establish floor and ceiling prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

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a counterparty is unable to satisfy its obligations

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production is less than expected; or

•

there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and

entities, such as the Company, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations for its implementation. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide derivative transactions. As these new position limit rules are not yet final, the impact of those provisions on the Company is uncertain at this time. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require the Company, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although the Company believes it qualifies for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the Company’s derivatives. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished or what the effect of any such regulations will be on the Company. For example, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to the Company for capital expenditures, therefore reducing its ability to execute derivatives to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to the Company is uncertain at this time. The full impact of the Dodd-Frank Act and related regulatory requirements upon the Company’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters and reduce the Company’s ability to monetize or restructure its existing derivative contracts. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company’s ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. The Company’s revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company, its financial condition and its results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent the Company transacts with counterparties in foreign jurisdictions, it may become subject to such regulations. At this time, the impact of such regulations is not clear.

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.

The Company’s business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and gas producer, the Company faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the Company’s facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected the Company’s operations to increased risks that could have a material adverse effect on the Company’s business. In particular, the Company’s implementation of various procedures and controls to monitor and mitigate security threats and to increase security for the Company’s information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to the Company’s operations and could have a material adverse effect on the Company’s reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage the Company’s reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Item 1B.

UNRESOLVED STAFF COMMENTS.

We are a smaller reporting company and therefore no response is required pursuant to this Item.

Item 2.

PROPERTIES.

Our executive offices as well as offices of Prime Operating Company, Eastern Oil Well Service Company, EOWS Midland Company and Prime Offshore L.L.C., are located in leased premises in Houston, Texas, and the offices of Southwest Oilfield Construction Company are in Oklahoma City, Oklahoma. We also maintain leased office space at One Landmark Square, Stamford, Connecticut for the administration, accounting and tax preparation for the Partnerships and Trusts.

We maintain district offices in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia, and have field offices in Carrizo Springs and Midland, Texas, Crescent and Elmore City, Oklahoma and Orma, West Virginia.

Substantially all of our oil and gas properties are subject to a mortgage given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.

The information set forth below concerning our properties, activities, and oil and gas reserves include our interests in affiliated entities.

The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the three years ended December 31, 2014.


	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Exploratory:
Oil		—		—		—		—		1		0.42
Gas		—		—		—		—		1		0.50
Dry		—		—		—		—		1		0.03
Development:
Oil		25		11.79		23		13.60		36		27.96
Gas		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total:
Oil		25		11.79		23		13.60		37		28.38
Gas		—		—		—		—		1		0.50
Dry		—		—		—		—		1		0.03

		25		11.79		23		13.60		39		28.91

Oil and Gas Production

As of December 31, 2014, we had ownership interests in the following numbers of gross and net producing oil and gas wells ⁽¹⁾.


	Gross		Net
Producing wells⁽¹⁾:
Oil Wells		893		425
Gas Wells		945		478

⁽¹⁾	A gross well is a well in which a working interest is owned. A net well is the sum of the fractional revenue interests owned in gross wells. Wells are classified by their primary product. Some wells produce both oil and gas.

The following table shows our net production of oil and natural gas for each of the three years ended December 31, 2014. “Net” production is net after royalty interests of others are deducted and is determined by multiplying the gross production volume of properties in which we have an interest by percentage of the leasehold, mineral or royalty interest owned by us.


	2014		2013		2012
Oil (barrels)		759,000		730,000		745,000
Gas (Mcf)		4,741,000		4,897,000		4,715,000

The following table sets forth our average sales price per barrel of oil and average sales prices per one thousand cubic feet (“Mcf”) of gas, together with our average production costs per unit of production for the three years ended December 31, 2014.


	2014		2013		2012
Average sales price per barrel	$	86.68	$	90.85	$	90.34
Average sales price per Mcf		5.15		5.13		4.45
Average production costs per net equivalent barrel⁽¹⁾		25.51		25.21		23.14

⁽¹⁾	Net equivalent barrels are computed at a rate of 6 Mcf per barrel and costs exclude production taxes.

Average oil and gas prices received excluding the impact of derivatives were:


	2014		2013		2012
Oil Price per barrel	$	86.73	$	93.75	$	89.67
Gas Price per Mcf		5.32		4.97		4.45

Acreage

The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold and mineral interests as of December 31, 2014. “Undeveloped acreage” is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.


	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
Leasehold acreage		199,233		95,450		800		436		200,033		95,886
Mineral fee acreage		1,640		117		19,257		417		20,897		534

Total		200,873		95,567		20,057		853		220,930		96,420

Total Net Undeveloped Acreage Expiration

In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as of December 31, 2014 is 436 acres for the year ending December 31, 2015, and none in 2016 and 2017.

Reserves

Our interests, including the interests held by the Partnerships, in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2014. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserves estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Houston Central 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, geologists and geophysicists and technicians with between approximately ten and thirty-five years of industry experience, and between three and twenty years of experience managing our reserves. Our Houston Central manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over twenty-five years of experience, holds a Bachelor of Science degree in Natural Gas Engineering and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologists. See Part II, Item 8., “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows.

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)
							(a)								(a)								(a)
2012		7,178		2,909		27,833		14,726		5,907		2,877		12,613		10,886		13,085		5,786		40,446		25,612
2013		6,687		2,223		31,628		14,182		9,066		3,707		19,772		16,068		15,753		5,930		51,400		30,250
2014		6,239		2,160		32,267		13,777		14,709		4,322		26,331		23,420		20,948		6,482		58,958		37,197

(a)	In computing total reserves on a barrels of oil equivalent (Boe), 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.

Our proved undeveloped reserves of 10,886 MBoe as of December 31, 2012 included 127 drilling locations in our West Texas drilling program, 11 drilling locations in our Mid-Continent region and 2 drilling locations in our Gulf Coast region. During 2013 we drilled 9 West Texas wells and 14 Mid-Continent wells at a cost of $25.9 million converting 913 MBoe to proved developed producing reserves and added 40 additional proved undeveloped drilling locations. Proved undeveloped reserves of 16,068 MBoe as of December 31, 2013 included 148 drilling locations in our West Texas drilling program, 10 drilling locations in our Mid-Continent region and 4 drilling locations in our Gulf Coast region.

During 2014 we drilled 7 West Texas wells and 17 Mid-Continent wells and 1 Gulf Coast well at a cost of $34.6 million converting 623 MBoe to proved developed producing reserves. Following our strategic plan to reduce vertical drilling and increase horizontal drilling we removed 49 vertical drilling locations and added 34 horizontal drilling locations to our West Texas drilling plan. Proved undeveloped reserves of 23.4 MBoe as of December 31, 2014 included 126 drilling locations in our West Texas drilling program, 10 drilling locations in our Mid-Continent region and 3 drilling locations in our Gulf Coast region. We have no proved undeveloped reserves scheduled for development five years beyond date of first booking.

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.

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, 2014, 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
2012	$	380,346	$	214,533	$	290,594	$	73,340	$	670,940	$	287,873	$	74,600	$	213,273
2013		341,841		204,326		455,622		131,510		797,463		335,836		97,608		238,228
2014		295,554		185,566		864,024		312,073		1,159,578		497,639		154,351		343,288

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 relatively major expenditure is required for recompletion. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% 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.

The range of Henry Hub daily gas prices per MMbtu during the year 2014 was a low of $2.74 and a high of $8.15 and the average was $4.37. The range during the first two months of 2015 has been from $2.55 to $3.29 with an average of $2.92. The recent futures market prices have fluctuated around $2.80 per MMbtu.

The range of NYMEX oil prices per barrel during the year 2014 was a low of $53.45 and a high of $107.95 and the average was $93.17. The range during the first two months of 2015 has been from $44.45 to $53.53, with an average of $48.98. The recent futures market prices have fluctuated around $50.00 per barrel.

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.

Since January 1, 2015, 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.

District Information

The following table presents certain reserve, production and well information as of December 31, 2014.


	Appalachian		Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves at Year End (MBoe)
Developed		1,231		1,042		3,240		8,143		121		13,777
Undeveloped		—		189		256		22,975		—		23,420

Total		1,231		1,231		3,496		31,118		121		37,197

Average Daily Production (Boe per day)		356		636		1,188		2,001		63		4,244

Gross Wells		645		322		655		503		107		2,232
Net Wells		350		134		252		202		17		953
Gross Operated Wells		477		271		371		379		57		1,555

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.

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, 2014, we had 645 wells (350 net), of which 477 wells are operated by us. 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 2014 was 356 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, 2014, we had 1,231 MBoe of proved reserves (substantially all natural gas) in the Appalachian region, constituting 3% of our total proved reserves. We maintain an acreage position of over 40,200 gross (33,400 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 March 1, 2015 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 Louisiana, southeast Texas and south Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Marg Tex, Wilcox, Pettit, Glenrose, Woodbine, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 322 wells (134 net) in the Gulf Coast region as of December 31, 2014, of which 271 wells are operated by us. Average daily production in 2014 was 636 Boe. At December 31, 2014, we had 1,231 MBoe of proved reserves (36% oil) in the Gulf Coast region, which represented 3% of our total proved reserves. We maintain an acreage position of over 20,000 gross (9,500 net) acres in this region, primarily in Dimmit, Duval and Polk counties. We have currently identified three proved undeveloped drilling locations in the Gulf Coast Region. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing 3 workover rigs, 18 water transport trucks, one saltwater disposal well 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 March 1, 2015 the Gulf Coast 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.

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, 2014, we had 655 wells (252 net) in the Mid-Continent area, of which 371 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 2014 was 1,188 Boe. At December 31, 2014, we had 3,496 MBoe of proved reserves (50% oil) in the Mid-Continent area, or 9% of our total proved reserves. We maintain an acreage position of over 86,000 gross (29,000 net) acres in this region, primarily in Canadian, Grant and Kingfisher counties. We have currently identified ten proved undeveloped drilling locations in the Mid-Continent Region. We operate a field service group in this region from two field offices, one in Crescent Oklahoma utilizing 2 workover rigs and the other in Elmore City, utilizing one workover rig and 1 saltwater hauling truck. Services are provided to third party operators as well as utilized in our own operated wells and locations. As of March 1, 2015 the Mid-Continent region has one well in the process of being drilled and three wells awaiting completion, no waterfloods in the process of being installed and no other related activities of material importance.

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 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 casinghead 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 Dean, 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, 2014, we had 503 wells (202 net) in the West Texas area, of which 379 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp and San Andres formations at depths ranging from 5,500 to 12,500 feet. Average net daily production in 2014 was 2,001 Boe. At December 31, 2014, we had 31,118 MBoe of proved reserves (60% oil) in the West Texas area, or 84% of our total proved reserves. We maintain an acreage position of over 26,000 gross (16,500 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We have currently identified 126 proved undeveloped drilling locations there and believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional drilling locations opportunities. We operate a field service group in this region utilizing 8 workover rigs, 4 hot oiler trucks and 1 kill 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. As of March 1, 2015 the West Texas 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.

Item 3.

LEGAL PROCEEDINGS.

None.

Item 4.

MINE SAFETY DISCLOSURES.

Not applicable.

PART II

Item 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock is listed and principally traded on the NASDAQ Stock Market under the ticker symbol “PNRG”. The following table presents the high and low closing prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system.


	High		Low
2014
First Quarter	$	61.56	$	44.01
Second Quarter		63.95		48.56
Third Quarter		69.10		59.53
Fourth Quarter		77.53		46.55
2013
First Quarter	$	30.03	$	22.70
Second Quarter		37.00		26.24
Third Quarter		53.25		33.62
Fourth Quarter		51.50		38.11

The above quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.

As of March 16, 2015, there were 478 registered holders of the common stock.

No dividends have been declared or paid during the past two years on our common stock. Provisions of our line of credit agreement restrict our ability to pay dividends. Such dividends may be declared out of funds legally available therefore, when and as declared by our Board of Directors.

Issuer Purchases of Equity Securities

In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, the Board of Directors of the Company approved an additional 500,000 shares of the Company’s stock to be included in the stock repurchase program. A total of 3,500,000 shares have been authorized, to date, under this program. Through December 31, 2014, a total of 3,213,052 shares have been repurchased under this program for $52,184,311 at an average price of $16.24 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital.


2014 Month	Number of Shares		Average Price Paid per share		Maximum Number of Shares that May Yet Be Purchased Under The Program at Month-End
January		6,214	$	50.34		336,114
February		714		52.21		335,400
March		13,684		50.92		321,716
April		1,201		55.15		320,515
May		2,366		58.33		318,149
June		663		61.08		317,486
July		6,444		62.18		311,042
August		156		65.10		310,886
September		13,357		63.69		297,529
October		139		64.61		297,390
November		1,787		67.64		295,603
December		8,655		68.59		286,948

Total / Average		55,380	$	59.17

Item 6.

SELECTED FINANCIAL DATA

We are a smaller reporting company and therefore no response is required pursuant to this Item.

Item 7.

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 Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.

Overview:

We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position 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 generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. In order to diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets so as to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We 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. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

Critical Accounting Estimates:

Proved Oil and Gas Reserves

Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Liquidity And Capital Resources:

Net cash provided by operating activities for the year ended December 31, 2014 was $56 million, compared to $36 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of derivatives.

If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through additional bank financing.

As of March 1, 2015, the Company maintains a credit facility totaling $250 million, with a borrowing base of $130 million. 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. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. We continued our drilling program in our West Texas and Mid-Continent regions. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zone with a lateral wellbore.

During 2014, we drilled a total of 25 gross (11.8 net) wells, primarily in the West Texas and Oklahoma areas at a net cost of $36 million. In our Mid-Continent region, the horizontal development is primarily in Grant and Canadian counties where we have approximately 6,450 net acres which we believe have significant resource potential based on our drilling results and those of offset operators. We began our West Texas, Upton County horizontal drilling program in the first quarter of 2015, and will drill up to 4 wells in this phase at a net cost of approximately $10 million. The first well was spudded March 17, 2015 and discussions with our joint venture partner in that program, Apache Corporation, indicate that including additional phases of development in the program will result in approximately 60 horizontal wells being drilled over the next 18 to 24 months at a cost of approximately $470. The actual number of wells to be drilled and the timing of the drilling may vary based on commodity market conditions. We own various interests, ranging from 16% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. We maintain an acreage position of over 26,000 gross (16,500 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We have currently identified 126 proved undeveloped drilling locations there and believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional drilling locations opportunities.

We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. As of March 1, 2015, the Company has $11.8 million outstanding on our equipment financing facilities which are secured by substantially all of our field service equipment, with an additional $700,000 available for the acquisition of new equipment. However, the majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company has in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2014 was $3.6 million. The Company expects continued spending under these programs in 2015.

Results of Operations:

2014 and 2013 Compared

We reported net income for 2014 of $27.05 million, or $11.45 per share, compared to net income for 2013 of $12.27 million, or $5.04 per share. Gains on derivative instruments substantially increased related to the decrease in commodity prices while price declines in oil and gas sales were partially offset with the increase in oil production compared to 2013. The remaining increase was attributed to the increase in the net field service income and gains on the sale of non-essential assets. The increases in revenues were partially offset by increases in depreciation, depletion and tax expense. The significant components of net income are discussed below.

Oil and gas sales decreased $1.74 million, or 2% from $92.79 million for the year ended December 31, 2013 to $91.05 million for the year ended December 31, 2014. 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 decreased an average of $7.02 per barrel, or 7% on crude oil and increased $0.35 per Mcf, or 7% on natural gas during 2014 as compared to 2013.

Our crude oil production increased by 29,000 barrels, or 4% from 730,000 barrels for the year ended December 31, 2013 to 759,000 barrels for the year ended December 31, 2014. Our natural gas production decreased by 156 MMcf, or 3% from 4,897 MMcf for the year ended December 31, 2013 to 4,741 MMcf for the year ended December 31, 2014. The increase in crude oil production volumes are a result of our continued drilling success in West Texas, Gulf Coast and Oklahoma regions as we place new wells into production, partially offset by the natural decline of existing properties. The natural gas volume decreases are primarily due to the natural decline of existing properties substantially offset by production from new wells in the West Texas and Oklahoma regions recently placed into production.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2014 and 2013 (excluding realized gains and losses from derivatives).


	Year Ended December 31,				Increase (Decrease)
	2014		2013		Amount			Percent
Barrels of Oil Produced		759,000		730,000		29,000			4	%
Average Price Received (excluding the impact of derivatives)	$	86.73	$	93.75	$	(7.02	)		(7	)%

Oil Revenue (In 000’s)	$	65,824	$	68,446	$	(2,622	)		(4	)%

Mcf of Gas Produced		4,741,000		4,897,000		(156,000	)		(3	)%
Average Price Received (excluding the impact of derivatives)	$	5.32	$	4.97	$	0.35			7	%

Gas Revenue (In 000’s)	$	25,221	$	24,339	$	882			4	%

Total Oil & Gas Revenue (In 000’s)	$	91,045	$	92,785	$	(1,740	)		(2	)%

Realized net gains (losses) on derivative instruments, net include net gains of $0.6 million and net losses of $0.5 million on the settlements of crude oil and natural gas derivatives, respectively for the year ended December 31, 2014. During 2014, we unwound and monetized natural gas swaps with original settlement dates from January 2015 through December 2015 for net proceeds of $0.28 million. In addition we unwound and monetized crude oil swaps with original settlement dates from January 2016 through December 2016 for net proceeds of $0.70 million. The $0.98 million in gains associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2014.

Oil and gas prices received including the impact of derivatives but excluding the early settlement transactions were:


	Year Ended December 31,				Increase (Decrease)
	2014		2013		Amount			Percent
Oil Price	$	86.67	$	90.85	$	(4.18	)		(5	)%
Gas Price	$	5.15	$	5.13	$	0.02			0	%

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 consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During the year ended December 31, 2014, we recognized net unrealized gains of $15.03 million associated with crude oil fixed swaps and collars and net unrealized gains of $2.54 million associated with natural gas fixed swap contracts due to market fluctuations in natural gas and crude oil futures market prices between January 1, 2014 and December 31, 2014.

Field service income increased $1.34 million, or 5% from $24.93 million for the year ended December 31, 2013 to $26.27 million for the year ended December 31, 2014. Workover rig services represent the bulk of our field service operations, and with the upgrading of our rigs during late 2013, income from rigs has increased during 2014 in our most active districts. In addition, during 2014 we added new and upgraded existing SWD facilities adding capacity for additional disposal services which contributed to the increase in net income. Income from hot oiler services have increased in our West Texas district with the addition of service equipment in the area.

Lease operating expense increased $0.2 million, or 0% from $43.81 million for the year ended December 31, 2013 to $43.97 million for the year ended December 31, 2014. This slight increase is primarily due to new wells coming on line from the recent drilling, partially offset by reduced SWD expenses reflecting the switch from hauling to piping salt water to SWD facilities.

Field service expense increased $0.2 million, or 1% from $21.03 million for the year ended December 31, 2013 to $21.19 million for the year ended December 31, 2014. Field service expenses primarily consist of salaries and vehicle operating expenses.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $4.00 million, or 18% from $21.86 million for the year ended December 31, 2013 to $25.86 million for the year ended December 31, 2014. This increase is primarily due to increased depletion expenses related to new wells coming on line from the recent drilling success in West Texas and Oklahoma.

General and administrative expense decreased $2.20 million, or 13% from $16.66 million for the year ended December 31, 2013 to $14.46 million for the year ended December 31, 2014. The largest components of these general and administrative expenses are personnel costs, including salaries and employee related taxes and insurance. Increases in these costs during 2014 were substantially offset in with the reimbursement of administrative expenses associated with development activities.

Gain on sale and exchange of assets of $6.12 million for the year ended December 31, 2014 and $2.82 million for the year ended December 31, 2013 consists of sales of non-producing acreage and non-core oil and gas interests and non-essential field service equipment.

Interest expense decreased $0.2 million, or 5% from $4.22 million for the year ended December 31, 2013 to $4.02 million for the year ended December 31, 2014. This decrease relates to a decrease in average debt

outstanding during 2014 as compared to 2013 combined with a decrease in weighted average interest rates during the 2014 periods. The average interest rate paid on outstanding bank borrowings subject to interest during 2014 and 2013 were 3.53% and 3.58%, respectively. As of December 31, 2014 and 2013, the total outstanding borrowings were $101 million and $122 million, respectively.

A provision for income taxes of $13.84 million, or an effective tax rate of 34% was recorded for the year ended December 31, 2014 verses a provision of $6.82 million, or an effective tax rate of 36% for the year ended December 31, 2013. Our provision for income taxes varies from the federal statutory tax rate of 34% primarily due to percentage depletion. We are entitled to percentage depletion on certain of our wells for tax purposes, 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 lowers our effective rate.

Item 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are a smaller reporting company and therefore no response is required pursuant to this Item.

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1 of this Report.

Item 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

Item 9A.

CONTROLS AND PROCEDURES.

As of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”). Disclosure Controls, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Our management, including the chief executive officer and chief financial officer, does not expect that our Disclosure Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Members of our management, including our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange

Act Rules 13a-15 or 15d-15, as of December 31, 2014, the end of the period covered by this Report. Based upon that evaluation, these officers concluded that our disclosure controls and procedures were effective as of December 31, 2014.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with U.S. generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control—Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2014.

This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B.

OTHER INFORMATION.

None.

PART III

Item 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Information relating to the Company’s Directors, nominees for Directors and executive officers will be included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in May, 2015 which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2014, and which is incorporated herein by reference.

Item 11.

EXECUTIVE COMPENSATION.

Information relating to executive compensation will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2015, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2014, and which is incorporated herein by reference.

Item 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

Information relating to security ownership of certain beneficial owners and management will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2015, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2014, and which is incorporated herein by reference.

Item 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Information relating to certain transactions by Directors and executive officers of the Company will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2015, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2014, and which is incorporated herein by reference.

Item 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Information relating to principal accountant fees and services will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2015, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2014, and which is incorporated herein by reference.

PART IV

Item 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

The following documents are filed as part of this Report:

Financial statements (Index to Consolidated Financial Statements at page F-1 of this Report)

Financial Statement Schedules (Index to Consolidated Financial Statements—Supplementary Information at page F-1 of this Report)

Exhibits:


Exhibit No.

3.1		Restated Certificate of Incorporation of PrimeEnergy Corporation (effective July 1, 2009) (Incorporated by reference to Exhibit 3.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2009).

3.2		Bylaws of PrimeEnergy Corporation (Incorporated by reference to Exhibit 3.2 of PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010).

10.18		Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Corporation Form 10-K for the year ended December 31, 2004).

10.22.5.9		Second Amended and Restated Credit Agreement dated July 30, 2010, by and among PrimeEnergy Corporation, the Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, and EOWS Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB) As Administrative Agent and Letter of Credit Issuer, BBVA Compass, As Sole Lead Arranger and Sole Bookrunner and The Lenders Signatory Hereto (BNP Paribas, JPMorgan Chase Bank, N.A. and Amegy Bank National Association) (Incorporated by reference to Exhibit 10.22.5.9 of PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010).

10.22.5.9.1		First Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective September 30, 2010 (Incorporated by reference to Exhibit 10.22.5.9.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2010).

10.22.5.9.2		Second Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective June 22, 2011 (Incorporated by reference to Exhibit 10.22.5.9.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2011).


Exhibit No.

10.22.5.9.3		Third Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective December 8, 2011 (Incorporated by reference to Exhibit 10.22.5.9.3 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2011).

10.22.5.9.4		Fourth Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective June 25, 2012 (Incorporated by reference to Exhibit 10.22.5.9.4 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2012).

10.22.5.9.5		Fifth Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company, Prime Offshore L.L.C.), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., Amegy Bank National Association, KeyBank National Association) effective November 26, 2012 (Incorporated by reference to Exhibit 10.22.5.9.5 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2012).

10.22.5.9.6		Sixth Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company, Prime Offshore L.L.C.), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., Amegy Bank National Association, KeyBank National Association) effective June 28, 2013 (Incorporated by reference to Exhibit 10.22.5.9.6 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2013).

10.22.5.9.7		Assignment Agreement made by and among Amegy Bank National Association, as Assignor, and Compass Bank (successor in interest to Guaranty Bank, FSB), Wells Fargo Bank, National Association, JPMorgan Chase Bank and KeyBank National Association, as Assignees, effective December 23, 2013 (Incorporated by reference to Exhibit 10.22.5.9.7 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2013).

10.22.5.9.8		Seventh Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company, Prime Offshore L.L.C.), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., KeyBank National Association) effective June 26, 2014 (Incorporated by reference to Exhibit 10.22.5.9.8 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2014).


Exhibit No.

10.23.1		Loan and Security Agreement dated July 31, 2013, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).

10.23.2		Business Purpose Promissory Note dated July 31, 2013, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.23.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).

10.23.3		Guaranty dated July 31, 2013, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.23.3 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).

10.23.4		Agreement of Equipment Substitution dated January 15, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.4 to PrimeEnergy Corporation Form 10-Q for the quarter ended March 31, 2014).

10.24.1		Loan and Security Agreement dated July 29, 2014, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.24.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014).

10.24.2		Business Purpose Promissory Note dated July 29, 2014, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.24.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014).

10.24.3		Guaranty dated July 29, 2014, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. (Incorporated by reference to Exhibit 10.24.3 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2014).

14		PrimeEnergy Corporation Code of Business Conduct and Ethics, as amended December 16, 2011 (Incorporated by reference to Exhibit 14 of PrimeEnergy Corporation Form 10-K for the year ended December 31, 2011).

21		Subsidiaries (filed herewith).

23		Consent of Ryder Scott Company, L.P. (filed herewith).

31.1		Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

31.2		Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

99.1		Summary Reserve Report dated March 4, 2015, of Ryder Scott Company, L.P. (filed herewith).

101.INS		XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)

101.SCH		XBRL Taxonomy Extension Schema Document (filed herewith)


Exhibit No.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)

101.LAB		XBRL Taxonomy Extension Label Linkbase Document (filed herewith)

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 18^th day of March, 2015


PrimeEnergy Corporation

By:		/S/ CHARLES E. DRIMAL, JR.
		Charles E. Drimal, Jr.
		Chairman, Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 18^th day of March, 2015.


/s/ CHARLES E. DRIMAL, JR. Charles E. Drimal, Jr.				Chairman, Chief Executive Officer and President; The Principal Executive Officer

/s/ BEVERLY A. CUMMINGS Beverly A. Cummings				Director, Executive Vice President and Treasurer; The Principal Financial Officer


/S/ GAINES WEHRLE	Director	/s/ CLINT HURT	Director
Gaines Wehrle		Clint Hurt

/s/ H. GIFFORD FONG	Director	/s/ JAN K. SMEETS	Director
H. Gifford Fong		Jan K. Smeets

/s/ THOMAS S.T. GIMBEL	Director
Thomas S.T. Gimbel

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm			F-2

Financial Statements
Consolidated Balance Sheet – As of December 31, 2014 and 2013			F-3
Consolidated Statement of Operations – For the years ended December 31, 2014 and 2013			F-4
Consolidated Statement of Comprehensive Income – For the years ended December 31, 2014 and 2013			F-5
Consolidated Statement of Equity – For the years ended December 31, 2014 and 2013			F-6
Consolidated Statement of Cash Flows – For the years ended December 31, 2014 and 2013			F-7
Notes to Consolidated Financial Statements			F-8

Supplementary Information:
Capitalized Costs Relating to Oil and Gas Producing Activities, years ended December 31, 2014 and 2013			F-23
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities, years ended December 31, 2014 and 2013			F-23
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, years ended December 31, 2014 and 2013			F-23
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves, years ended December 31, 2014 and 2013			F-24
Reserve Quantity Information, years ended December 31, 2014 and 2013			F-25
Results of Operations from Oil and Gas Producing Activities, years ended December 31, 2014 and 2013			F-25
Notes to Supplementary Information			F-26

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

PrimeEnergy Corporation and Subsidiaries:

We have audited the accompanying consolidated balance sheets of PrimeEnergy Corporation and Subsidiaries (the Company) as of December 31, 2014 and 2013, and related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years then ended. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of PrimeEnergy Corporation and Subsidiaries as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Grassi & Co., CPAs, P.C.

GRASSI & CO., CPAs, P.C.

New York, New York

March 13, 2015

F-2

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Thousands of dollars)


	As of December 31,
	2014			2013
ASSETS
Current Assets
Cash and cash equivalents	$	9,209		$	9,526
Restricted cash and cash equivalents		3,877			2,065
Accounts receivable, net		12,315			17,693
Prepaid obligations		877			1,188
Derivative contracts		16,914			357
Other current assets		613			1,846

Total Current Assets		43,805			32,675
Property and Equipment
Oil and gas properties at cost		396,588			364,123
Less: Accumulated depletion and depreciation		(188,988	)		(169,100	)

		207,600			195,023

Field and office equipment at cost		27,403			26,653
Less: Accumulated depreciation		(14,702	)		(13,251	)

		12,701			13,402

Total Property and Equipment, Net		220,301			208,425
Derivative Contracts Long-Term		13			1,066
Other Assets		781			756

Total Assets	$	264,900		$	242,922

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	16,258		$	16,249
Accrued liabilities		12,401			6,832
Current portion of long-term debt		2,903			1,870
Current portion of asset retirement and other long-term obligations		1,366			3,310
Current portion of deferred tax liability		5,547			—
Derivative liability short-term		170			2,194
Due to related parties		45			23

Total Current Liabilities		38,690			30,478
Long-Term Bank Debt		98,490			120,023
Asset Retirement Obligations		11,269			7,227
Derivative Liability Long-Term		—			94
Deferred Income Taxes		38,191			31,962

Total Liabilities		186,640			189,784
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2014 and 2013: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2014: 2,333,404 shares; 2013: 2,388,784 shares		383			383
Paid-in capital		7,186			6,803
Retained earnings		105,662			78,616
Accumulated other comprehensive loss, net		(92	)		(123	)
Treasury stock, at cost; 2014: 1,502,993 shares; 2013: 1,447,613 shares		(43,527	)		(40,251	)

Total Stockholders’ Equity—PrimeEnergy		69,612			45,428
Non-controlling interest		8,648			7,710

Total Equity		78,260			53,138

Total Liabilities and Equity	$	264,900		$	242,922

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

F-3

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(Thousands of dollars, except per share amounts)


	For the Year Ended December 31,
	2014			2013
Revenues
Oil and gas sales	$	91,045		$	92,785
Realized gain (loss) on derivative instruments, net		135			(1,322	)
Field service income		26,270			24,934
Administrative overhead fees		9,373			9,255
Unrealized gain (loss) on derivative instruments		17,574			(649	)
Other income		183			64

Total Revenues		144,580			125,067
Costs and Expenses
Lease operating expense		43,972			43,809
Field service expense		21,185			21,027
Depreciation, depletion, amortization and accretion on discounted liabilities		25,864			21,861
(Gain) Loss on settlement of asset retirement obligations		(1,797	)		40
General and administrative expense		14,460			16,659
Exploration costs		—			8

Total Costs and Expenses		103,684			103,404
Gain on Sale and Exchange of Assets		6,115			2,816

Income from Operations		47,011			24,479
Other Income and Expenses
Less: Interest expense		4,018			4,223
Add: Interest income		—			2

Income Before Provision for Income Taxes		42,993			20,258
Provision for Income Taxes		13,844			6,818

Net Income		29,149			13,440
Less: Net Income Attributable to Non-Controlling Interest		2,103			1,169

Net Income Attributable to PrimeEnergy	$	27,046		$	12,271

Basic Income Per Common Share	$	11.45		$	5.04

Diluted Income Per Common Share	$	8.68		$	3.86

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

F-4

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of dollars)


	For the Year Ended December 31,
	2014		2013
Net income	$	29,149	$	13,440

Other Comprehensive Income (Loss), net of taxes:
Changes in fair value of hedge positions, net of taxes of $(17) and $50, respectively		31		(88	)

Total other comprehensive income (loss)		31		(88	)

Comprehensive income		29,180		13,352
Less: Comprehensive income attributable to non-controlling interest		2,103		1,169

Comprehensive income attributable to PrimeEnergy	$	27,077	$	12,183

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

F-5

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

(Thousands of dollars)


	Common Stock				Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity
	Shares		Amount		Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity
Balance at December 31, 2012		3,836,397	$	383	$	6,690	$	66,345	$	(35	)	$	(36,113	)	$	37,270		$	6,932		$	44,202
Purchase 121,776 shares of common stock		—		—		—		—		—			(4,138	)		(4,138	)		—			(4,138	)
Net income		—		—		—		12,271		—			—			12,271			1,169			13,440
Other comprehensive loss, net of taxes		—		—		—		—		(88	)		—			(88	)		—			(88	)
Purchase of non-controlling interest		—		—		113		—		—			—			113			(161	)		(48	)
Distributions to non-controlling interest		—		—		—		—		—			—			—			(230	)		(230	)

Balance at December 31, 2013		3,836,397	$	383	$	6,803	$	78,616	$	(123	)	$	(40,251	)	$	45,428		$	7,710		$	53,138
Purchase 55,380 shares of common stock		—		—		—		—		—			(3,276	)		(3,276	)		—			(3,276	)
Net income		—		—		—		27,046		—			—			27,046			2,103			29,149
Other comprehensive income, net of taxes		—		—		—		—		31			—			31			—			31
Purchase of non-controlling interest		—		—		383		—		—			—			383			(657	)		(274	)
Distributions to non-controlling interest		—		—		—		—		—			—			—			(508	)		(508	)

Balance at December 31, 2014		3,836,397	$	383	$	7,186	$	105,662	$	(92	)	$	(43,527	)	$	69,612		$	8,648		$	78,260

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

F-6

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of dollars)


	For the Year Ended December 31,
	2014			2013
Cash Flows from Operating Activities:
Net income	$	29,149		$	13,440
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		25,864			21,861
Gain on sale of properties		(6,115	)		(2,816	)
Unrealized (gain) loss on derivative instruments		(17,574	)		649
Provision for deferred income taxes		13,237			7,014
(Gain) loss on settlement of asset retirement obligations		(1,797	)		40

Changes in assets and liabilities:
Decrease (increase) in accounts receivable		5,379			(4,481	)
Increase in due from related parties		(247	)		(96	)
Decrease in inventories		24			91
Decrease in prepaid expenses and other assets		286			378
Increase (decrease) in accounts payable		534			(712	)
Increase in accrued liabilities		7,425			332

Net Cash Provided by Operating Activities		56,165			35,700

Cash Flows from Investing Activities:
Capital expenditures, including exploration expense		(38,758	)		(33,934	)
Proceeds from sale of properties and equipment		6,834			3,681

Net Cash Used in Investing Activities		(31,924	)		(30,253	)

Cash Flows from Financing Activities:
Purchase of stock for treasury		(3,276	)		(4,138	)
Purchase of non-controlling interests		(274	)		(48	)
Increase in long-term bank debt and other long-term obligations		57,417			68,750
Repayment of long-term bank debt and other long-term obligations		(77,917	)		(68,857	)
Distribution to non-controlling interest		(508	)		(230	)

Net Cash Used in Financing Activities		(24,558	)		(4,523	)

Net (Decrease) Increase in Cash and Cash Equivalents		(317	)		924
Cash and Cash Equivalents at the Beginning of the Year		9,526			8,602

Cash and Cash Equivalents at the End of the Year	$	9,209		$	9,526

Supplemental Disclosures:
Income taxes paid during the year	$	320		$	754
Interest paid during the year	$	4,025		$	4,183

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

F-7

PRIMEENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Operations and Significant Accounting Policies

Nature of Operations:

PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, West Virginia and Wyoming and the Gulf of Mexico. The Company operates approximately 1,600 wells and owns non-operating interests in approximately 700 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol “PNRG.” PEC owns Eastern Oil Well Service Company (“EOWSC”), EOWS Midland Company (“EMID”) and Southwest Oilfield Construction Company (“SOCC”), all of which perform oil and gas field servicing. PEC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. PEC also owns Prime Offshore L.L.C. (“Prime Offshore”), formerly F-W Oil Exploration LLC, which has owned and operated properties in the Gulf of Mexico. PrimeEnergy Management Corporation (“PEMC”), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 18 limited partnerships and 2 trusts (collectively, the “Partnerships”). The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources.

Consolidation and Presentation:

The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.

Reclassifications:

Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions.

F-8

Subsequent Events:

Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure.

Use of Estimates:

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset is less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.

Property and Equipment:

The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings.

Capitalization of Interest:

Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.

Impairment of Long-Lived Assets:

The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

Fair Value:

The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted

F-9

accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

Asset Retirement Obligation:

The Company follows the accounting standard for asset retirement obligation. The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties (including removal of offshore platforms) at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.

Income Taxes:

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

General and Administrative Expenses:

General and administrative expenses represent cost and expenses associated with the operation of the Company.

F-10

Earnings Per Common 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.

Statements of Cash Flows:

For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.

Concentration of Credit Risk:

The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.

Hedging:

The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2014 and 2013, the entire other comprehensive income amount comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations.

Recently Adopted Accounting Standards:

In July 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance required entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance eliminated the diversity in practice in the presentation of unrecognized tax benefits but did not alter the way in which entities assess deferred tax assets for realizability. ASU 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The requirements of ASU 2013-11 did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2014.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 requires an entity to recognize the amount of revenue to which it expects to be entitled for transfer of promised

F-11

goods or services to customers. ASU-2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. ASU-2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016, using one of two retrospective application methods. Early application is not permitted. The Company is currently evaluating the effect that the adoption of ASU 2014-09 will have on the Company’s consolidated financial statements.

2. Acquisitions and Dispositions

Historically, the Company has repurchased the noncontrolling interests of the partners and trust unit holders in certain of the Partnerships, which consist primarily of oil and gas interests. The Company purchased such noncontrolling interests in an amount totaling $274,000 in 2014 and $48,000 in 2013.

3. Additional Balance Sheet Information

Accounts receivable at December 31, 2014 and 2013 consisted of the following:


	December 31,
(Thousands of dollars)	2014			2013
Joint interest billings	$	2,882		$	6,287
Trade receivables		1,980			2,014
Oil and gas sales		6,245			9,604
Other		1,751			122

		12,858			18,027
Less: Allowance for doubtful accounts		(543	)		(334	)

Total	$	12,315		$	17,693

Accounts payable at December 31, 2014 and 2013 consisted of the following:


	December 31,
(Thousands of dollars)	2014		2013
Trade	$	3,995	$	1,596
Royalty and other owners		8,444		7,391
Partner advances		1,344		3,378
Prepaid drilling deposits		786		978
Other		1,689		2,906

Total	$	16,258	$	16,249

Accrued liabilities at December 31, 2014 and 2013 consisted of the following:


	December 31,
(Thousands of dollars)	2014		2013
Compensation and related expenses	$	2,350	$	3,062
Property costs		9,204		3,119
Income tax		554		268
Other		293		383

Total	$	12,401	$	6,832

F-12

4. Property and Equipment

Capitalized interest is included as part of the cost of oil and gas properties. The capitalized rates are based upon the Company’s weighted-average cost of borrowings used to finance the expenditures. There was no interest capitalized during 2014 or 2013.

5. 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 has 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 is secured by substantially all of the Company’s oil and gas properties. The credit facility is 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. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redetermination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be redetermined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.

The Credit Agreement has been amended from time to time to further define the limitations on loans or advances and investments made in the Company’s limited partnerships; modify the Company’s borrowing base and monthly reduction amounts; remove the floor rate component of LIBO rate loans; modify financial reporting requirements to the agent; increase hedging allowances; allow for a one-time advance to be made to the Company’s offshore subsidiary; and amend restrictions on the payments for dividends, distributions or repurchase of PEC’s stock.

The 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.

Under the Credit Agreement, the maximum percentage of production available to enter into commodity hedge agreements is 90% of proved developed producing reserves for each of the next succeeding four calendar years for crude oil and natural gas computed separately. In addition, the Company’s restrictions on the payment of dividends, distributions or purchase of treasury stock is limited to an aggregate of $5.0 million in each calendar year.

At December 31, 2014, the credit facility borrowing base was $130.0 million with no monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at December 31, 2014) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.50% to 3.00%. At December 31, 2014, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 4.75% and 2.65%, respectively.

At December 31, 2014, the Company had $88.9 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.42%, and $41.1 million available for future borrowings. The

F-13

combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.53% for the year ended December 31, 2014, as compared to 3.58% for the year ended December 31, 2013.

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%. For the year ended December 31, 2014, the Company recorded interest expense and paid $289,000 related to the settlement of interest rate swaps.

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 December 31, 2014, the Company had a total of $7.5 million outstanding on this Equipment Loan.

On July 29, 2014, the Company entered into additional equipment financing facilities 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. As of December 31, 2014, the Company had a total of $4.5 million outstanding on this facility. The remaining $1.2 million under this facility is available to finance the acquisition of any future field service equipment. In December 2014, the Company drew down an additional $0.5 million of this facility that is secured by recently purchased field service equipment. Interim draws on this facility carry a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and in July 2015 will convert along with subsequent draws, if any, into a fixed term loan requiring monthly payments (principal and interest) and a final maturity date of June 30, 2020.

6. Commitments

Operating Leases:

The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the operating leases at December 31, 2014 are as follows.


(Thousands of dollars)	Operating Leases
2015	$	651
2016		546
2017		46

Total minimum payments	$	1,243

Rent expense for office space for the years ended December 31, 2014 and 2013 was $785,000 and $699,000, respectively.

F-14

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2014 and 2013 is as follows:


	Year Ended December 31,
(Thousands of dollars)	2014			2013
Asset retirement obligation at beginning of period	$	10,537		$	9,012
Liabilities incurred		1,627			338
(Gain) loss on settlement of obligations		(1,797	)		40
Liabilities settled		(1,074	)		(776	)
Accretion expense		370			394
Revisions in estimated liabilities		2,838			1,529

Asset retirement obligation at end of period	$	12,501		$	10,537

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. In 2014, the Company recognized a gain on the settlement of asset retirement obligations associated with insurance recoveries related to obligations previously recognized on the plugging and abandonment of a well. During 2014 and 2013 revisions in estimated liabilities for asset retirement obligations resulted from increased field costs resulting in shorter productive life of marginal wells and the enactment of new federal regulation requirements for plugging and abandonment.

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. At December 31, 2014, 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.

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 December 31, 2014 and 2013, options 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.

F-15

9. Income Taxes

The components of the provision (benefit) for income taxes for the years ended December 31, 2014 and 2013 are as follows:


	Year Ended December 31,
(Thousands of dollars)	2014		2013
Current:
Federal	$	345	$	(462	)
State		262		266

Total current		607		(196	)
Deferred:
Federal		13,134		6,549
State		103		465

Total deferred		13,237		7,014

Total income tax provision	$	13,844	$	6,818

The components of net deferred tax assets and liabilities are as follows:


	At December 31,
(Thousands of dollars)	2014		2013
Current Assets:
Accrued liabilities	$	610	$	683
Allowance for doubtful accounts		124		118
Derivative contracts		52		677

Total current assets		786		1,478
Current Liabilities:
Derivative contracts		6,333		—

Total current liabilities		6,333		—

Net current deferred income tax liabilities (assets)	$	5,547	$	(1,478	)

Non-Current Assets:
Alternative minimum tax credits	$	5,722	$	5,852
Net operating loss carry-forwards		620		168
Percentage depletion carry-forwards		3,959		4,543

Total non-current assets		10,301		10,563
Non-Current Liabilities:
Basis differences relating to managed partnerships		4,300		2,462
Depletion and depreciation		44,192		39,694
Derivative contracts		—		369

Total non-current liabilities		48,492		42,525

Net non-current deferred income tax liabilities	$	38,191	$	31,962

F-16

The total provision for income taxes for the years ended December 31, 2014 and 2013 varies from the federal statutory tax rate as a result of the following:


	Year Ended December 31,
(Thousands of dollars)	2014			2013
Expected tax expense	$	13,902		$	6,491
State income tax, net of federal benefit		254			488
Percentage depletion		(312	)		(422	)
Other, net		—			261

Total income tax provision	$	13,844		$	6,818

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Differences relating to oil and gas properties owned through Prime Offshore are reflected under “Depletion and depreciation,” while basis differences relating to the managed partnerships are reflected under “Basis differences relating to managed partnerships.”

The Company is entitled to percentage depletion on certain of its 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 lowers the Company’s effective rate.

The Company has $5.7 million in alternative minimum tax (“AMT”) credits which can be used to lower the regular tax liability to the tentative AMT amount in years where the tentative AMT amount is less. These credits do not expire.

The Company is allowed a credit against the Texas Franchise Tax based on net operating losses incurred in prior periods. The credits allowed are $26 thousand in the years 2014 through 2016, and $89 thousand in the years 2017 through 2026. Any credits not utilized in a given year due to the allowable credit exceeding the tax liability may be carried forward. No credit may be carried forward past 2026. The value of the credit is shown net of the federal income tax effect.

The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, and 2009 federal income tax returns have been audited by the Internal Revenue Service, while the 2011, 2012 and 2013 returns remain open for examination. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general, no assessment of income tax may be made for those years on which the statute has closed. State returns for the years 2011, 2012 and 2013 remain open for examination by the relevant taxing authorities.

10. Segment Information and Major Customers

The Company operates in one industry—oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States.

The Company sells its oil and gas production to a number of purchasers. Listed below are the percent of the Company’s total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company’s oil and gas sales in the year 2014.


Oil Purchasers:			Gas Purchasers:
Plains All American Inc.	46	%	Atlas Pipeline Mid-Continent	37	%
Sunoco, Inc.	26	%	Unimark LLC	13	%

F-17

Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers.

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 December 31, 2014 and 2013:


December 31, 2014 (Thousands of dollars)	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, 2014
Assets
Commodity derivative contracts	$	—	$	—	$	16,901		$	16,901
Interest rate derivative contracts		—		—		26			26

Total assets	$	—	$	—	$	16,927		$	16,927

Liabilities
Interest rate derivative contracts	$	—	$	—	$	(170	)	$	(170	)

Total liabilities	$	—	$	—	$	(170	)	$	(170	)


December 31, 2013 (Thousands of dollars)	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, 2013
Assets
Commodity derivative contracts	$	—	$	—	$	1,337		$	1,337
Interest rate derivative contracts		—		—		86			86

Total assets	$	—	$	—	$	1,423		$	1,423

Liabilities
Commodity derivative contracts	$	—	$	—	$	(2,010	)	$	(2,010	)
Interest rate derivative contracts		—		—		(278	)		(278	)

Total liabilities	$	—	$	—	$	(2,288	)	$	(2,288	)

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.

F-18

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 years ended December 31, 2014 and 2013.


	Year Ended December 31,
(Thousands of dollars)	2014			2013
Net liabilities at beginning of period	$	(865	)	$	(78	)
Total realized and unrealized gains (losses):
Included in earnings (a)		17,420			(1,971	)
Included in other comprehensive income (loss)		48			(138	)
Purchases, sales, issuances and settlements		154			1,322

Net assets (liabilities) at end of period	$	16,757		$	(865	)

(a)	Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments, and interest rate swap instruments are reported as an increase or reduction to interest expense.

Derivative Instruments:

The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.

Interest rate swap derivatives continue to be treated as cash-flow hedges and are used to fix our float interest rates on existing debt. The value of these interest rate swaps at December 31, 2014 and 2013 are located in accumulated other comprehensive loss, net of tax. Settlement of the swaps, which began in January 2014, are recognized within interest expense.

F-19

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2014 and 2013:


		Fair Value at December 31,
(Thousands of dollars)	Balance Sheet Location	2014			2013
Asset Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Derivative contracts	$	12		$	—
Interest rate swap contracts	Derivative contracts long-term		13			86
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative contracts		14,629			307
Natural gas commodity contracts	Derivative contracts		2,273			50
Crude oil commodity contracts	Derivative contracts long-term		—			980

Total		$	16,927		$	1,423

Liability Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Derivative liability short-term	$	(170	)	$	(209	)
Interest rate swap contracts	Derivative liability long-term		—			(69	)
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative liability short-term		—			(1,667	)
Natural gas commodity contracts	Derivative liability short-term		—			(318	)
Crude oil commodity contracts	Derivative liability long-term		—			(25	)

Total		$	(170	)	$	(2,288	)

Total derivative instruments		$	16,757		$	(865	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2014 and 2013:


	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2014			2013
Derivative designated as cash-flow hedge instruments:
Interest rate swap contracts	Interest expense	$	(289	)	$	—
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net		2,542			(1,309	)
Crude oil commodity contracts	Unrealized gain on derivative instruments, net		15,032			660
Natural gas commodity contracts (a)	Realized gain (loss) on derivative instruments, net		(529	)		796
Crude oil commodity contracts (a)	Realized gain (loss) on derivative instruments, net		664			(2,118	)

		$	17,420		$	(1,971	)

F-20

(a)

In January 2014, the Company unwound and monetized natural gas swaps with original settlement dates from January 2015 through December 2015 for net proceeds of $276,000. In September 2014, the Company unwound and monetized crude oil swaps with original settlement dates from January 2016 through December 2016 for net proceeds of $703,000. The $979,000 gains associated with these early settlement transactions are included in realized gain on derivative instruments for the year ended December 31, 2014.

12. 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 an amount totaling $274,000 during 2014 and $48,000 during 2013.

Treasury stock purchases in any reported period may include shares from a related party. In December 2013, the Company purchased 4,500 shares of common stock as treasury shares from a Director for $222,750. There were no other related party treasury stock purchases during the years ended December 31, 2014 and 2013.

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.

13. Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents include $3.88 million and $2.01 million at December 31, 2014 and 2013, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at December 31, 2014 and 2013 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying consolidated balance sheets.

14. Salary Deferral Plan

The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions, of which $591,000 and $524,000 were made in 2014 and 2013, respectively.

F-21

15. Earnings per Share


	Year Ended December 31,
	2014						2013
	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	$	27,046		2,361,134	$	11.45	$	12,271		2,436,821	$	5.04

Effect of dilutive securities:
Options		—		753,897				—		746,085

Diluted	$	27,046		3,115,031	$	8.68	$	12,271		3,182,906	$	3.86

16. Shareholder’s Equity

The Company has in place a stock repurchase program whereby it may purchase outstanding shares of its common stock from time-to-time, in open market transactions or negotiated sales. The Company uses the cost method to account for its treasury share purchases.

F-22

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

CAPITALIZED COSTS RELATING TO

OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2014 and 2013

(Unaudited)


	As of December 31,
(Thousands of dollars)	2014		2013
Proved Developed oil and gas properties	$	395,314	$	362,186
Proved Undeveloped oil and gas properties		1,274		1,937
Unproved oil and gas properties		—		—

Total Capitalized Costs		396,588		364,123
Accumulated depreciation, depletion and valuation allowance		188,988		169,100

Net Capitalized Costs	$	207,600	$	195,023

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,

EXPLORATION AND DEVELOPMENT ACTIVITIES

Years Ended December 31, 2014 and 2013

(Unaudited)


	Year Ended December 31,
(Thousands of dollars)	2014		2013
Acquisition of Properties, Developed	$	59	$	7
Acquisition of Properties, Undeveloped		—		—
Exploration Costs		—		8
Development Costs		36,406		25,912

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2014 and 2013

(Unaudited)


	As of December 31,
(Thousands of dollars)	2014			2013
Future cash inflows	$	2,252,248		$	1,880,389
Future production costs		(738,531	)		(769,172	)
Future development costs		(354,139	)		(313,754	)
Future income tax expenses		(360,702	)		(234,191	)

Future Net Cash Flows		798,876			563,272
10% annual discount for estimated timing of cash flows		(455,588	)		(325,044	)

Standardized Measure of Discounted Future Net Cash Flows	$	343,288		$	238,228

See accompanying Notes to Supplementary Information

F-23

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS AND CHANGES THEREIN

RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2014 and 2013

(Unaudited)

The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2014 and 2013:


	Year Ended December 31,
(Thousands of dollars)	2014			2013
Sales of oil and gas produced, net of production costs	$	(47,074	)	$	(48,976	)
Net changes in prices and production costs		(18,510	)		(10,149	)
Extensions, discoveries and improved recovery		198,235			218,648
Revisions of previous quantity estimates		67,245			(733	)
Net change in development costs		(69,923	)		(129,672	)
Reserves sold		(69	)		—
Reserves purchased		—			—
Accretion of discount		23,823			21,327
Net change in income taxes		(56,744	)		(23,007	)
Changes in production rates (timing) and other		8,077			(2,483	)

Net change		105,060			24,955
Standardized measure of discounted future net cash flow:
Beginning of year		238,228			213,273

End of year	$	343,288		$	238,228

See accompanying Notes to Supplementary Information

F-24

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

RESERVE QUANTITY INFORMATION

Years Ended December 31, 2014 and 2013

(Unaudited)


	As of December 31,
	2014									2013
	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)
Proved Developed Reserves:
Beginning of year		6,687			2,223			31,628			7,178			2,909			27,833
Extensions, discoveries and improved recovery		186			222			424			87			—			402
Revisions of previous estimates		(278	)		(207	)		3,662			(361	)		(712	)		6,456
Converted from undeveloped reserves		407			93			735			513			199			1,207
Reserves sold		(4	)		—			—			—			—			—
Reserves purchased		—			—			—			—			—			—
Production		(759	)		(171	)		(4,182	)		(730	)		(173	)		(4,270	)

End of year		6,239			2,160			32,267			6,687			2,223			31,628

Proved Undeveloped Reserves:
Beginning of year		9,066			3,707			19,772			5,907			2,877			12,613
Extensions, discoveries and improved recovery		5,914			1,629			6,672			4,536			1,541			9,538
Revisions of previous estimates		136			(921	)		622			(864	)		(512	)		(1,172	)
Converted to developed reserves		(407	)		(93	)		(735	)		(513	)		(199	)		(1,207	)
Reserves sold		—			—			—			—			—			—
Reserves purchased		—			—			—			—			—			—

End of year		14,709			4,322			26,331			9,066			3,707			19,772

Total Proved Reserves at the End of the Year		20,948			6,482			58,598			15,753			5,930			51,400

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2014 and 2013

(Unaudited)


	Year Ended December 31,
(Thousands of dollars)	2014		2013
Revenue:
Oil and gas sales	$	91,045	$	92,785
Costs and Expenses:
Lease operating expenses		43,972		43,809
Exploration costs		—		8
Depreciation, depletion and accretion		22,906		19,218
Income tax expense		9,216		10,012

Total Costs and Expenses		76,094		73,047

Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$	14,951	$	19,738

See accompanying Notes to Supplementary Information

F-25

PRIMEENERGY CORPORATION AND SUBSIDIARIES

NOTES TO SUPPLEMENTARY INFORMATION

(Unaudited)

1. Presentation of Reserve Disclosure Information

Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.

2. Determination of Proved Reserves

The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

3. Results of Operations from Oil and Gas Producing Activities

The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.

4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.

Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.

Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.

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Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.

5. Changes in Reserves

The 2014 and 2013 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing 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 its 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.

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