UNITED STATES

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549

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Form 10-K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014 

Commission file number: 001-34635

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PostRock Energy Corporation

(Exact Name of Registrant as Specified in Its Charter)

 

 

Registrant’s telephone number, including area code:

(405) 600-7704

Securities Registered Pursuant to Section 12(b) of the Exchange Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Exchange Act:

None

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☑    No  ☐ 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☑    No  ☐ 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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 smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ☐    No   ☑ 

The aggregate market value of common stock held by non-affiliates of the registrant at June 30, 2014, was approximately $29.4 million, based upon the closing price of $1.50 per share as reported by the NASDAQ on such date.

The aggregate market value of outstanding common stock, including those held by affiliates of the registrant, at March 2, 2015, was approximately $25.2 million, based upon the closing price of $3.96 per share. There were 6,372,054 shares of common stock outstanding on that date.

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DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2015 Annual Meeting of Stockholders are incorporated by reference in Part III.

 

 

 

 

 

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TABLE OF CONTENTS

 

 

 

 

 

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GLOSSARY

 

The following abbreviations are used in this report:

 

 

This report contains forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See Item 1A. “Risk Factors—Forward-Looking Statements.”

 

 

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EXPLANATORY NOTE—RESTATEMENT OF FINANCIAL INFORMATION

 

This Annual Report on Form 10-K for the year ended December 31, 2014 includes (1) a restated balance sheet as of December 31, 2013, (2) restated consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholders’ equity (deficit) for the years ended December 31, 2012 and 2013, (3) restated quarterly financial information for the quarters ended March 31, 2014 and 2013, June 30, 2014 and 2013, and September 30, 2014 and 2013, and December 31, 2013, and (4) restated selected financial data for the years ended December 31, 2010, 2011, 2012, and 2013. See Item 6, “Selected Financial Data,” Item 8, “Financial Statements and Supplementary Data,” and Item 9A, “Controls and Procedures,” in Part II of this Annual Report on Form 10-K, including Notes 19 and 20 of the notes to the Consolidated Financial Statements, for more information concerning these restatements.

 

We do not plan to amend previously filed reports in connection with the restatement. The financial information that has been previously filed or otherwise reported for these periods is superseded by the information in this Annual Report on Form 10-K. Unless otherwise stated, all financial and accounting information contained in this Annual Report on Form 10-K is presented on a restated basis.

 

PART I

 

ITEM 1. BUSINESS 

 

PostRock Energy Corporation (“PostRock”) is a Delaware corporation formed in 2009. It was formed to combine its predecessor entities, Quest Resource Corporation, Quest Energy Partners, L.P. and Quest Midstream Partners, L.P. (collectively, the “Predecessors”) into a single entity. In March 2010, PostRock completed the combination of these entities (the “Recombination”). Unless the context requires otherwise, references to “the Company,” “we,” “us” and “our” refer to PostRock from the date of the Recombination and to the Predecessors on a consolidated basis prior thereto.

 

Background

 

We are an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. Our primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma, and central Oklahoma. We also have minor oil and gas producing properties in the Appalachian Basin. Our Cherokee Basin and Central Oklahoma properties comprise our MidContinent area of operations.

 

Production and Reserves

 

At December 31, 2014, our total assets consisted of 3,158 gross and 3,109 net productive wells. These wells are on approximately 344,000 net acres of leasehold, classified as developed, while we also have approximately 66,100 net acres classified as undeveloped. Our net production in 2014 totaled 13.2 Bcf of natural gas and 274,919 barrels of oil for an average of 36.2 MMcf/d of gas and 753 Bbls/d of oil. At year end, our estimated proved reserves included 119.1 Bcf of natural gas and 4.1 MMBbl of oil for a total of 143.9 Bcfe.

 

Cherokee Basin

 

At December 31, 2014, our Cherokee Basin assets consisted of 2,683 gross and 2,675 net productive wells. These wells are on approximately 324,500 net developed acres of leasehold, while we also have 38,500 net undeveloped acres in the region. Our net production in 2014 totaled 12.6 Bcf of natural gas and 66,962 barrels of oil for an average of 34.6 MMcf/d of gas and 183 Bbls/d of oil. At year end, our estimated proved reserves attributable to these properties included 106.9 Bcf of natural gas and 0.9 MMBbl of oil for a total of 112.5 Bcfe.

 

We also have a gathering system in the Cherokee Basin. The system provides a market outlet for gas produced in an area of approximately 1,000 square miles. We gather substantially all of our production in the Cherokee Basin and a minor amount of gas produced by others. At year end, throughput on the system averaged 43.8 MMcf/d of which approximately 1.8 MMcf/d and 7.4 MMcf/d was attributable to third parties and to our royalty owners, respectively. Third-party gathering contracts generally permit us to retain 20% to 30% of the sales price of the gas gathered. The gathering system includes 57 leased compressors totaling approximately 431,000 horsepower and five gas treatment facilities. The system has an estimated throughput capacity of approximately 55 MMcf/d.

 

Central Oklahoma

 

At December 31, 2014, our Central Oklahoma oil assets consisted of 72 gross and 57 net productive wells. These wells are on approximately 10,700 net developed acres of leasehold. We also have approximately 23,000 net undeveloped acres in the region.

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During 2014, net production from these wells increased 140% to a total of 196,287 barrels of oil, or an average of 538 Bbls/d. At year end, our estimated proved reserves attributable to these properties included 3.6 Bcf of natural gas and 3.0 MMBbl of oil or a total of 21.6 Bcfe. 

 

Appalachian Basin

 

At December 31, 2014, our Appalachian Basin assets consisted of 403 gross and 377 net productive wells. These wells are on approximately 8,800 net developed acres of leasehold; additionally we have approximately 4,600 net undeveloped acres in the region. During 2014, net production from our wells was 0.5 Bcf of natural gas and 11,670 barrels of oil for an average of 1.3 MMcf/d of gas and 32 Bbls/d of oil. At year end, our estimated proved reserves attributable to these properties included 8.7 Bcf of natural gas and 0.2 MMBbl of oil for a total of 9.8 Bcfe.

 

We also have a 141.1 mile gathering system in the Appalachian Basin. At December 31, 2014, this system had an average throughput of approximately 1.9 MMcf/d of which approximately 1.3 MMcf/d was attributable to our net production with the remaining 0.6 MMcf/d attributable to our royalty or joint interest owners. All of our gas produced in the area is transported by this system.

 

Acquisitions and Divestitures

 

During June 2014, we entered into a joint venture (“JV”) agreement with Silver Creek Oil and Gas, LLC (“Silver Creek”) covering approximately 17,900 gross unproved acres in Cleveland and Pottawatomie Counties in central Oklahoma. The JV included an acre for acre swap of approximately 3,800 total net acres. After the swap, the ownership split in the development area is 30% PostRock and 70% Silver Creek, with Silver Creek serving as the operator. We also sold approximately 1,150 net acres to Silver Creek for $466,000 in cash.

 

During 2013, we closed on three acquisitions for oil and gas properties in Central Oklahoma. The largest of the acquisitions included approximately 22,000 net acres (approximately 9,000 net acres are held by production) of leasehold mineral interests, including certain producing oil and gas properties and related wells, for approximately $10.0 million. During January 2014, we acquired additional well interests in Central Oklahoma. The total purchase price of the acquired well interests after closing adjustments was $1.7 million which was paid in cash of approximately $800,000 and 72,581 shares of our common stock. See Note 3 in Part II, Item 8 “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K for further discussion of these acquisitions.

 

On September 28, 2012, we sold our PostRock KPC Pipeline, LLC (“KPC”) subsidiary to MV Pipelines, LLC (“MV”) for $53.5 million in cash, $53.4 million net after a working capital adjustment. MV also agreed to make additional payments of $1.0 million for each of the next four years if qualified EBITDA, as defined in the purchase agreement, of KPC for that year exceeds a target amount. No payment was received for 2013 or 2014.

 

Financial information and revenues from external customers are located in Part II, Item 8 “Financial Statements and Supplemental Data” in this Annual Report on Form 10-K.

 

Description of Production Properties and Projects

 

Properties

 

We produce conventional oil and coal bed methane (“CBM”) gas from our properties in the Cherokee Basin which is situated between the Forest City Basin to the north, the Arkoma Basin to the south, the Ozark Dome to the east and the Nemaha Ridge to the west. The Cherokee Basin is a mature producing area with respect to conventional oil producing reservoirs; such as, the Bartlesville and other Pennsylvanian age sandstones, which were initially discovered and developed beginning in the early 1900s.

 

The principal gas formations targeted include the Mulky, the Weir-Pittsburgh and the Riverton. These coal seams are blanket type deposits, which extend across large areas of the Cherokee Basin. Each seam is generally two to five feet thick. Additional minor coal seams such as the Summit, Bevier, Fleming and Rowe are found at varying locations. These seams range in thickness from one to two feet.

 

CBM is considered an “unconventional resource” in that the coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional gas, but in CBM, most, and frequently all, of the gas is stored by adsorption. This adsorption leads to gas being stored at relatively low pressures. Gas flow can be increased by reducing the reservoir pressure. Frequently, the coal bed pore space, which is in the form of cleats or fractures, is filled

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with water. The reservoir pressure is reduced by pumping out the water, allowing methane to “desorb” from the coal and flow through the cleat structure to the well bore. Because of the necessity to remove water and reduce the pressure within the coal seam, CBM, unlike most conventional hydrocarbons, often will not produce significant gas immediately on initial production testing. Coal bed formations typically require extensive dewatering and de-pressuring before desorption can occur and the methane begins to flow at commercial rates. The ability to flow gas and water to the wellbore in a CBM well is determined by the fracture or cleat network in the coal. While these fractures, at shallow depths of less than 500 feet, are sometimes open enough to produce the fluids naturally, at greater depths the networks are progressively squeezed shut, reducing the ability to flow naturally. It is necessary to provide other avenues of flow, such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal. A slurry of water, certain chemicals and sand is pumped at high pressures into the fractures, with the sand essentially propping the fractures open. After the release of pressure, the flow of both water and gas is improved, allowing the production of gas.

 

Our Central Oklahoma area of focus encompasses much of seven counties. At present, our production is located in Seminole and Pottawatomie counties. The majority of our current production is from the Hunton carbonate; however, we also produce from other reservoirs including the Woodford, Viola, Redfork, and Wilcox. We also have non-producing leasehold in Payne, Lincoln, Cleveland, McClain and Garvin counties. Oil has been produced in the region since the early 1900s from multiple horizons including the Hunton, Viola, Wilcox, Arbuckle, Redfork, and Woodford shale. In all, at least 18 different geologic horizons are productive regionally. Producing depths range from less than 1,000 feet to 6,000 feet. There are numerous opportunities in the region to apply modern drilling, completion and operating technology to enhance recovery from reservoirs, such as the Hunton carbonate among others, that have produced historically and also to develop unconventional reservoirs, like the Woodford and Mississippian. Our plans include vertical and horizontal drilling and completion techniques.

 

The Appalachian Basin is one of the largest and oldest producing basins in the United States. Our main area of operation in the Appalachian Basin is West Virginia, where our producing formations range in depth from 1,500 feet to approximately 6,500 feet. Our main production formations are the lower Devonian Marcellus Shale, the shallow Mississippian (Big Injun, Maxton, Berea, Pocono, Big Lime) and the Upper Devonian (Riley, Benson, Java, Alexander, Elk, Cashaqua, Middlesex, West River and Genesee, including the Huron Shale member and Rhinestreet Shales).

 

Projects

 

Our 2014 exploration and development capital expenditures totaled $32.2 million. Included in the $32.2 million, we successfully completed five new wells and recompleted 13 wells in Central Oklahoma, and completed eight new gas wells and recompleted one gas well in the Cherokee Basin. Additionally, we participated in five non operated oil wells completed in Central Oklahoma. Our development activity in 2014 was directed toward increasing oil production and reserves in response to low natural gas prices. As a result of oil focused development, oil production in 2014 increased 43% over the prior year to 274,919 barrels, but primarily due to lower crude oil prices oil reserves decreased from 4.4 MMBbl at year-end 2013 to 4.1 MMBbl at year-end 2014.

 

With the recent collapse of oil and natural gas prices, our focus for 2015 will be to limit capital expenditures and reduce costs. We have budgeted approximately $5.5 million in capital projects with the majority of our budget focused on completing projects from 2014. There are currently no plans to drill any new wells in 2015. If attractive opportunities arise or oil and natural gas prices increase, additional capital may be directed towards further oil development in Central Oklahoma. We intend to fund our 2015 capital expenditures with cash flow from operations and availability under our credit facility.

 

Cherokee Basin

 

One of our most significant projects has been to reconfigure our entire compression system in the Cherokee Basin. This program was piloted with a proof of concept phase in 2012 and began to be fully implemented in 2013 and 2014. The project was completed in 2014 for a total cost of approximately $8.6 million, with roughly $4.6 million in 2014. This is expected to result in compression rental savings of approximately $4.6 million per year and to reduce fuel use of about 1.6 MMcf/d as compared to fueled used prior to the project.

 

Central Oklahoma

 

During the year, we performed development workovers on 13 wells. The combined cost of the workovers totaled approximately $3.2 million and we expect our internal rate of return (“IRR”) to exceed 100%. The development workovers increased production by approximately 87 net barrels of oil per day. During the last part of the year, we drilled and completed four horizontal wells targeting the Hunton formation at a cost of approximately $3.5 million per well. The horizontal wells produced slightly below 100,000 gross barrels of oil in 2014. Using actual revenue received through December 31, 2014 and applying a recent strip, the projected combined IRR for the wells exceeds 20%. Additionally, we participated in five non-operated oil wells during 2014 and we spent approximately $2.2 million on the two joint venture wells with Silver Creek.

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Oil and Gas Data

 

Preparation of Reserve Reports

 

Management has established, and is responsible for, internal controls designed to provide reasonable assurance that our reserve estimation is prepared and reported in accordance with rules and regulations promulgated by the Securities Exchange Commission (“SEC”) as well as established industry practices used by independent engineering firms and our peers. These internal controls include, but are not limited to: 1) documented process workflow timelines, 2) verification of economic data inputs to information supplied by our internal operations accounting, regional production and operations, land, and marketing groups, and 3) senior management review of internal reserve estimations prior to publication.

 

Cawley, Gillespie & Associates, Inc. (“CGA”) prepared our reserve estimates at December 31, 2012, 2013 and 2014. CGA is an independent firm of petroleum engineers, geologists, geophysicists and petro-physicists; they do not own any interest in our properties and are not employed on a contingent fee basis. The technical person responsible for our reserve estimates at CGA meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

 

Estimated Reserves

 

The following tables present our estimated net proved reserves based on our reserve reports, and the prices used to determine those reserves. Proved reserves are those quantities of oil and gas, which, by analysis of geo-scientific and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations and prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The data was prepared by CGA. Reserve pricing for the periods presented, seen in the table below, was determined by averaging the first day of the month price for the twelve months of the respective fiscal year.

 

 

 

 

The following table presents our proportionate share of proved reserves for 2012 and 2013 of continuing operations of Sanchez Production Partners LLC (formerly named Constellation Energy Partners LLC) (“SPP”); therefore, hereinafter we will refer to our investment as SPP). As of March 31, 2014, the Company no longer had significant influence over SPP; therefore, 2014 reserve amounts for SPP are not included. See Note 8 in Part II, Item 8 “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K for further discussion on our investment in SPP. These reserve amounts are based on publicly available data and are not subject to our internal controls described above. The Company has updated the previously filed amounts for December 31, 2012 related to SPP as discontinued operations have now been presented in their current public filing.

 

 

 

 

 

As disclosed above, we used a price of $4.35 per MMBtu, representing a first-day-of-month, twelve-month average price, to determine our natural gas reserves at December 31, 2014.  

 

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on geo-scientific and engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered. See Item 1A. “Risk Factors—Risks Related to Our Business—Our estimated reserves are based on many assumptions that may prove to be inaccurate.” Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

At December 31, 2014, we had 45.3 Bcfe of proved undeveloped reserves. During 2014, we spent approximately $6.9 million to develop five wells that were previously reported as proved undeveloped reserves in 2013, all of which were oil, as we directed our capital spending during the year toward oil projects. At December 31, 2014, we did not have material proved undeveloped reserves that remain undeveloped five years subsequent to their disclosure as proved undeveloped reserves. All of our proved undeveloped reserves included in our 2014 reserve report are scheduled to be developed before 2019.

 

Production Volumes, Sales Prices and Production Costs

 

The following table sets forth information regarding our producing properties. The production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells. All sales data excludes the effects of our derivative financial instruments, unless otherwise indicated.

 

 

 

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(1)Data includes the effects of our commodity derivative contracts that do not qualify for hedge accounting.

(2)Includes lease operating and gathering costs.

(3)Production taxes include severance and ad valorem taxes.

 

The following table presents realized gains and losses on our commodity derivative financial instruments:

 

 

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(1)2012 includes $30.2 million received from exiting above-market natural gas swap contracts originally scheduled for delivery in 2013.

 

The following table presents our production, average sales prices and production costs by area for the years ended December 31, 2012, 2013 and 2014:

 

 

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(1)Includes lease operating and gathering costs.

 

Productive Wells

 

The following table sets forth information regarding our ownership of wells at December 31, 2012, 2013 and 2014. Our data is comprised of all producing wells and wells mechanically capable of production.

 

 

 

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(1)Gross wells are the sum of all wells in which we own an interest.

(2)Net wells are gross wells multiplied by our fractional interests in the wells.

 

Acreage Statistics

 

The following table sets forth our developed and undeveloped lease and mineral acreage at December 31, 2012, 2013 and 2014.  

 

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(1)Includes acreage in the states of Kansas, Oklahoma, West Virginia, and New York.

(2)Gross acres are an approximation of the sum of all acres in which we own an interest.

(3)Net acres are approximated gross acres multiplied by our fractional interest in the acreage.

 

At December 31, 2014, we had approximately 324,500 net developed and 38,500 net undeveloped acres in the Cherokee Basin, approximately 10,700 net developed and 23,000 net undeveloped acres in Central Oklahoma, and approximately 8,800 net developed and 4,600 net undeveloped acres in the Appalachian Basin. Developed acres are acres spaced or assigned to productive wells/units based upon governmental authority or standard industry practice. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.

 

Drilling Activities

 

Our drilling, recompletion, abandonment and acquisition activities for the periods indicated are shown below. This information includes wells in all areas in the period in which they were completed.

 

 

 

During 2014, we plugged and abandoned 46 wells, 33 of which were inactive and not capable of producing during the entire period of our ownership of the wells. We also acquired two wells that were plugged by the previous owner and are not included in the table above. As of the date of filing, there has been no new drilling activity for the year.

 

 

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Exploration and Production

 

General

 

As the operator of wells in which we have an interest, we design and manage the development of these wells and supervise operation and maintenance activities on a day-to-day basis. We employ production and reservoir engineers, geologists and other specialists.

 

Field operations conducted by our personnel include duties performed by “production techs” or employees whose primary responsibility is to operate the wells. Other field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new wells (such as electric service, disposal wells and gas well flow lines). The primary equipment we own includes trucks, well service rigs, stimulation assets and construction equipment. At times we utilize third-party contractors to supplement our field personnel.

 

In the Cherokee Basin, we provide, on an in-house basis, many of the services required for the completion and maintenance of our CBM wells. Internally sourcing these functions significantly reduces our reliance on third-party contractors, which typically provide these services. We believe that we are able to realize significant cost savings because we can reduce delays in executing our plan of development and avoid paying price markups. We currently rely on third-party contractors to drill our wells. Once a well is drilled, either we or a third-party contractor run the casing. We perform the cementing, fracturing and the majority of stimulation in completing our own wells. In Central Oklahoma and the Appalachian Basin, we rely entirely on third-party contractors for these completion services.

 

Leases

 

At December 31, 2014, we had approximately 9,500 leases covering approximately 410,100 net acres. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount ranges from 18.0% to 22.5% resulting in an 77.5% to 82.0% net revenue interest to us.

 

Because the acquisition of oil and natural gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other operators. In order to gain the right to drill these leases, we may purchase leases from them.

 

In the Cherokee Basin, at year end, we held leases on approximately 363,000 net acres, of which 3,200 net acres are not currently held by production. In Central Oklahoma we held leases on approximately 33,700 net acres, of which 23,000 net acres are not currently held by production. Unless we establish commercial production on the properties subject to these leases during their term, these leases will expire. Leases in the Cherokee Basin and Central Oklahoma covering approximately 1,700 and 3,800 net acres, respectively, are scheduled to expire before December 31, 2015, unless developed, extended or renewed. If these leases expire, we will lose the right we currently have to develop the related properties.

 

Marketing and Major Customers

 

During 2014, approximately 99% of our MidContinent gas production was sold to BP Energy Company and approximately 75% and 18% of our MidContinent oil production was sold to Sunoco Partners Marketing & Terminals L.P. and Holly Frontier Refining & Marketing LLC, respectively.  Approximately 90% of our 2014 Appalachian Basin gas production was sold to South Jersey Resources Group. All of our oil production in the Appalachian Basin was sold to BD Oil Gathering.

 

If we were to lose any of these purchasers, we believe that we would be able to promptly replace them because we believe there are multiple options for marketing our commodities. The physical location of our production provides ample options for marketing the commodities to creditworthy parties.

 

Commodity Derivative Activities

 

Prices for crude oil and natural gas are affected by a variety of factors beyond our control and can be volatile. When commodity futures prices have been at appropriate levels we have used derivative instruments to reduce commodity price uncertainty and increase cash flow predictability inherent to the marketing of our production. For additional information about our derivatives, see Part I, Item 1A. “Risk Factors—Our commodity price risk management activities may prevent us from benefiting fully from price increases and may expose us to other risks” and Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”

 

Competition

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We operate in a highly competitive environment for acquiring properties, marketing our production and employing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. As a result, our competitors may be able to pay more for properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in our industry.

Title to Properties

 

Production Properties

 

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of development operations on those properties, we conduct a title examination and perform curative work with respect to significant defects that we discover. To the extent title opinions or other investigations reflect title defects on properties, we are typically responsible for curing such title defects at our expense. We generally will not commence development operations on a property until we have cured any material title defects that we discover on such property. We believe that we have satisfactory title to our material producing properties in accordance with standards generally accepted in our industry.

 

In some cases, title to these properties is subject to encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry. We believe, however, that no such liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties, our interest therein, or their use in the operation of our business. In some cases, lands over which leases have been obtained are subject to prior liens which have not been subordinated to the leases. We believe, however, that we have obtained sufficient right-of-way grants and permits from public authorities and private parties in order to operate our business in all material respects.

 

Pipeline Rights-of-Way

 

Substantially all of our gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

 

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets, and state highways; where necessary. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

 

Certain of our rights to lay and maintain pipelines are derived from recorded oil and natural gas leases for wells that are currently in production; however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

 

Seasonality

 

In the past, freezing weather and storms in the winter and flooding in the spring and summer have resulted in a number of our wells being off-line for a short period of time sometimes for many consecutive days. This adversely affects our production volumes and revenues and increases our lease operating costs due to the time spent by field employees to bring the wells back on-line. This has also resulted in wells producing at lower rates for extended periods after returning to production. We have recently had success managing this exposure by using products that limit freezing on wells and compressors and using heavy equipment to facilitate faster access to wells in inclement weather to return them to production after outages.

 

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Government Regulation

 

Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated by a number of federal, state and local governmental authorities under various laws and regulations governing a wide variety of matters, including allowable rates of production, plugging of abandoned wells, transportation, prevention of waste and pollution, protection of the environment and worker health and safety. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both.

These laws are under constant review for amendment or expansion. Moreover, the possibility exists that new legislation or regulations may be adopted. Amended, expanded or new laws and regulations increasing the regulatory burden on the crude oil and natural gas industry can have a significant impact on our operations or our customers’ ability to use natural gas and may require us or our customers to change their operations significantly or incur substantial costs. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the US Environmental Protection Agency (“EPA”), the Federal Energy Regulatory Commission (“FERC”), the Commodity Futures Trading Commission (“CFTC”), other federal and state regulatory agencies and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

 

Management believes that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. We have internal procedures and policies that we believe help to ensure that our operations are conducted in substantial regulatory compliance. Governmental regulations applicable to our operations include those relating to worker safety, environmental matters, exploration and production activities, natural gas gathering pipelines and natural gas sales.

 

Environmental Matters

 

Our operations are subject to various, increasingly stringent federal, state and local laws and regulations relating to the emission, release and discharge of materials into, and the protection of, the environment and the protection of natural resources and wildlife and the imposition of liability for pollution. We have made and will continue to make expenditures in our efforts to comply with these requirements. We do not believe that we have, to date, expended material amounts in connection with such activities or that compliance with these requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the oil and gas industry, to date, we do not believe they have affected us to any greater or lesser extent than other companies in the industry. Due to the size of our operations, significant new environmental regulation could have a disproportionate adverse effect on our operations. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders limiting or enjoining future operations or imposing additional compliance requirements or operational limitations on our business. See Part I, Item 1A. Risk Factors—“We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental and operational safety regulations or an accidental release of hazardous substances into the environment”;  “We may face unanticipated water and other waste disposal costs”; and “Recent and future environmental laws and regulations may significantly limit, and increase the cost of, our exploration, production and gathering operations.”

 

Production

 

Federal, state and local regulations apply to our exploration and production activities and impose permitting, bonding and reporting requirements. Most states, and some counties and municipalities, in which we operate also regulate the location and method of drilling and casing of wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and/or notice to surface owners and other third parties. Some state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while others rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and reduce our interest in the unitized properties. In addition, some state conservation laws establish maximum rates of production from oil and gas wells. These laws generally prohibit venting or flaring of gas and impose requirements regarding the ratability of production. Moreover, some states impose a production or severance tax on the production and sale of oil, gas and gas liquids within its jurisdiction.

 

The Cherokee Basin has been an active producing region for a number of years. Many of our properties had abandoned oil and conventional gas wells on them at the time the current lease was entered. A number of these wells remain unplugged or were improperly plugged by a prior landowner or operator. Many of the former operators of these wells have ceased operations and cannot be located or do not have the financial resources to plug these wells. We believe that we are not responsible for plugging an abandoned well on one of our leases, unless we have used, attempted to use or invaded the abandoned well bore in our operations on

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the land or have otherwise agreed to assume responsibility for plugging the wells. While the Kansas Corporation Commission’s (“KCC”) current interpretation of Kansas law is consistent with our position, it could change in the future.

 

Regulation of Gathering Pipelines

 

Our gathering pipeline operations are currently limited to the States of Kansas, Oklahoma, and West Virginia. State regulation of gathering facilities generally includes various permitting, safety, environmental and, in some circumstances, non-discriminatory take requirements and complaint-based rate regulation. We are licensed as an operator of a natural gas gathering system with the KCC and are required to file periodic information reports with it. We are not required to be licensed as an operator or to file reports in Oklahoma and West Virginia.

 

On those portions of our gathering system that are open to third-party producers, the producers have the ability to file complaints challenging our gathering rates, terms of services and practices. We have contracts with all of the third-party producers for which we gather gas and are not aware of any complaints being filed. Our fees, terms and practices must be just, reasonable, not unjustly discriminatory and not unduly preferential. If the KCC or the Oklahoma Corporation Commission (“OCC”), as applicable, were to determine that the rates charged to a complainant did not meet this standard, the KCC or the OCC, as applicable, would have the ability to adjust our rates with respect to the wells subject to the complaint. We are not aware of any instance in which either the KCC or the OCC has made such a determination in the past.

 

These regulatory burdens may affect profitability and management is unable to predict the future cost or impact of complying with such regulations. While state regulation of pipeline transportation does not materially affect our operations, we do own several small, discrete delivery laterals in Kansas that are subject to a limited jurisdiction certificate issued by the KCC. State regulation of pipeline transportation may influence certain aspects of our business and the market price for our products.

 

Our natural gas gathering pipeline facilities are generally exempt from FERC’s jurisdiction and regulation pursuant to Section 1(b) of the Natural Gas Act of 1938 (“NGA”), which exempts pipeline facilities that perform primarily a gathering function, rather than a transportation function. However, if FERC were to determine that the facilities perform primarily a transmission function rather than a gathering function, these facilities may become subject to regulation as interstate natural gas pipeline facilities which may subject us to fines and additional costs and regulatory burdens that would substantially increase our operating costs and adversely affect our profitability. See Part I, Item 1A. Risk Factors—“A change in the jurisdictional characterization of some of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our gathering assets, which may indirectly cause our revenues to decline and operating expenses to increase.”

 

Sales of Natural Gas

 

The price at which we buy and sell natural gas currently is not subject to federal regulation or, for the most part, state regulation, other than those regulations that prohibit certain practices, such as price manipulation, in the sale of natural gas. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. These initiatives may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations.

 

Employees

 

At December 31, 2014, we had 143 field employees in offices located in Kansas, Oklahoma and West Virginia, and 56 executive and administrative personnel located at our headquarters in Oklahoma City. None of our employees are covered by a collective bargaining agreement and management considers its relations with employees to be satisfactory. Subsequent to year-end we have reduced our staffing levels by approximately 17% in both field and administrative personnel.

 

Where To Find Additional Information

 

Additional information about us can be found on our website at www.pstr.com. Information on our website is not part of this document. We also provide, free of charge on our website, our filings with the SEC, including our annual reports, quarterly reports and current reports, along with any amendments thereto, as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC.

You may also find information related to our corporate governance, board committees and company code of ethics at our website. Among the information you can find there is the following:

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•Audit Committee Charter;

 

•Compensation Committee Charter;

 

•Nominating, Corporate Governance, Safety and Environment Committee Charter; and

•Code of Business Conduct and Ethics.

 

ITEM 1A. RISK FACTORS 

 

Risks Related to Our Business

 

Energy prices are very volatile, and if commodity prices are depressed or decline, our revenues, profitability and cash flows will be adversely affected.

 

The prices we receive for our oil and gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and gas are commodities; therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Although we have recently focused our development efforts on crude oil, approximately 88.9% of our production in 2014 was natural gas. The prices that we receive for our production, and the levels of our production, depend on a variety of factors that are beyond our control, such as:

 

•the levels and location of oil and gas supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale on the global natural gas supply;

 

•price and level of foreign imports of oil and gas;

 

•level of consumer product demand;

 

•weather conditions;

 

•overall domestic and global economic conditions;

 

•political and economic conditions in oil and gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, acts of terrorism or sabotage;

 

•actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

 

•the impact of the U.S. dollar exchange rates on oil and gas prices;

 

•technological advances affecting energy consumption;

 

•governmental regulations and taxation;

 

•the impact of energy conservation efforts;

 

•the costs, proximity and capacity of gas pipelines and other transportation facilities; and

 

•the price and availability of alternative fuels.

 

Our revenue, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices will significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

 

•reduce the amount of cash flow available for capital expenditures, including the drilling of wells and the construction of infrastructure to transport the hydrocarbons produced;

 

•negatively impact the value of our reserves because declines in oil and gas prices would reduce the amount of oil and gas we can produce economically;

 

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•reduce the drilling and production activity of our third-party customers and increase the rate at which our customers shut in wells; and

 

•limit our ability to borrow money or raise additional capital.

 

 

 

We may be required to write-down the carrying value of our assets.

 

Lower oil and gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated reserves. Substantial decreases in oil and gas prices have rendered and may continue to render a significant number of our planned exploration and development projects uneconomic. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil or gas properties.

 

Under the full cost method of accounting for costs related to our oil and natural gas properties, we are required to write down the carrying value of our oil and natural gas assets if capitalized costs exceed the quarterly ceiling limit, which is based on the average of commodity prices on the first day of the month over the trailing 12-month period. In the second half of 2014, the NYMEX West Texas Intermediate (WTI) index price of oil declined significantly from $105.37 per Bbl as of June 30, 2014 to $53.27 per Bbl as of December 31, 2014, and the Henry Hub index price of natural gas declined from $4.46 per Mcf to $2.89 per Mcf over the same period. Oil prices have declined further in 2015. The NYMEX WTI index price of oil on March 2, 2015 was $49.59 per Bbl, and the Henry Hub index price of natural gas was $2.70 per Mcf. Based on the first-day-of the-month prices for the 11 months ended February 2015, a write-down on the carrying value of our oil and natural gas properties may occur in the first half of 2015. Further write-downs in subsequent quarters may occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters.

 

We are exposed to credit risk in the ordinary course of our business activities.

 

We are exposed to risks of loss in the event of nonperformance by our customers, vendors and other counterparties. Some of our customers, vendors and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Despite our credit review and analysis, we may experience financial losses in our dealings with these and other parties with which we enter into transactions as a normal part of our business activities. Any nonpayment or nonperformance by our customers, vendors or counterparties could have a material adverse impact on our consolidated financial position, results of operations or cash flows.

 

We are unable to pass through all of our costs and expenses for gathering and compression to royalty owners under our gas leases, which reduces our net income and cash flows.

 

We incur costs and expenses for gathering, dehydration, treating and compression of the gas that we produce. The terms of some of our existing gas leases and other development rights currently do not, and the terms of some of the gas leases and other development rights that we may acquire in the future may not, allow us to charge the full amount of these costs and expenses to the royalty owners under the leases or other agreements. During 2011, we reached settlements of several royalty owner lawsuits in Oklahoma and Kansas. These lawsuits were related, in part, to the amounts previously deducted by us to cover the costs and expenses for gathering and compression. As a result of these settlements, we are charging post-production costs to royalty and overriding royalty interest owners pursuant to an agreed upon formula. To the extent that we are unable to charge and recover the full amount of these costs and expenses from our royalty owners, our net income and cash flows will be reduced.

 

Unless we replace the reserves that we produce, our existing reserves and production will decline, which would adversely affect our revenues, profitability and cash flows.

 

Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas reserves, production and cash flow depend on our success in developing and exploiting our reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs or production from our existing wells could decline at a faster rate than we have estimated, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing gas prices and attractiveness of properties for sale.

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Our estimated reserves are based on assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

 

It is not possible to measure underground accumulations of oil and gas in an exact way. Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of oil and gas that cannot be directly measured and assumptions concerning future oil and gas prices, production levels and operating and development costs. In estimating our level of oil and gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

•a constant level of future oil and gas prices;

 

•geological conditions and expected reservoir characteristics based on geological, geophysical and engineering assessments;  

 

•production levels;

 

•capital expenditures;

 

•operating and development costs;

 

•the effects of governmental regulations and taxation; and

 

•availability of funds.

 

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. Additionally, there has been increased debate and disagreement over the classification of reserves, with particular focus on proved undeveloped reserves. Changing interpretations of the classification standards or disagreements with our interpretations could cause us to write-down reserves.

 

Our standardized measure is calculated using unhedged oil and gas prices and is determined in accordance with the rules and regulations of the SEC. The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the market value of our estimated proved reserves. The estimated discounted future net cash flows from our estimated proved reserves is based on twelve month average prices and expected costs in effect on the day of estimate. The timing and amount of actual future prices and costs, which affect the present value of the reserves, may be higher or lower than the timing and amounts at the time of the estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities—Oil and Gas, 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 oil and gas industry in general.

 

Drilling for and producing oil and gas is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations.

 

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors, as well as the market price of oil and gas, can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

•high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

 

•adverse weather conditions;

 

•difficulty disposing of water produced as part of our production process;

 

•equipment failures or accidents;

 

•title problems;

 

•pipe or cement failures or casing collapses;

 

•compliance with environmental and other governmental requirements;

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•environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

 

•lost or damaged oilfield drilling and service tools;

 

•loss of drilling fluid circulation;

 

•unexpected operational events and drilling conditions;

•increased risk of wellbore instability due to horizontal drilling;

 

•pressure or irregularities in formations;

 

•unusual or unexpected geological formations;

 

•natural disasters, such as fires and floods;

 

•blowouts, surface craterings and explosions; and

 

•uncontrollable flows of oil, gas or well fluids.

 

A productive well may become uneconomic in the event water or other harmful substances are encountered, which impair or prevent the production of oil or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other harmful substances. We may drill wells that are unproductive or, although productive, do not produce oil or gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, a successful completion of a well does not ensure a profitable return on the investment.

 

Our commodity price risk management activities may prevent us from benefiting fully from price increases and may expose us to other risks.

 

To the extent that we engage in risk management activities to protect ourselves from commodity price fluctuations, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

•our production falls short of the hedged volumes;

 

•a sudden unexpected event materially impacts oil and natural gas prices;

 

•the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; and

 

•there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement.

 

The Dodd-Frank Act and implementing regulations could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

 

In 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”).  Among other things, the Dodd-Frank Act requires the CFTC and the SEC to enact regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.

 

The CFTC and SEC have adopted several regulations implementing the Dodd-Frank Act and are considering several additional proposed regulations.  For example, the CFTC has issued final rules requiring centralized clearing of certain categories of swaps and is considering expanding this requirement to additional swap categories, including commodity swaps.  We could be required either to clear our swap transactions or claim an exemption from clearing for swaps used for hedging purposes.  In addition, the CFTC has proposed regulations implementing position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions. 

 

While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution

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requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy.

 

The Dodd-Frank Act and implementing regulations may significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, restrict our flexibility in conducting trading and hedging activity and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas.  Our revenues could, therefore, be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

 

Because of our lack of asset and geographic diversification, adverse developments in our operating areas would adversely affect our results of operations.

 

A substantial portion of our assets are located in the Cherokee Basin. As a result, our business is disproportionately exposed to adverse developments affecting this region. Potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to the pipelines connected to our wells, curtailment of production, natural disasters or adverse weather conditions in or affecting these regions. Due to our lack of diversification in asset type and location, an adverse development in our business or this operating area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

 

There are a variety of risks inherent in our operations that may generate liabilities, including contingent liabilities, and financial losses to us, such as:

 

•damage to wells, pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

 

•inadvertent damage from construction, farm and utility equipment;

 

•leaks of gas or oil spills as a result of the malfunction of equipment or facilities;

 

•fires and explosions; and

 

•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

 

Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses.

 

We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. We do not have property insurance on any of our underground pipeline systems or wellheads that would cover damage to the pipelines. Pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Premiums and deductibles for certain insurance policies have increased substantially in recent years. Due to these cost increases, we may not be able to obtain the levels or types of insurance we would otherwise have obtained, and the insurance coverage we do obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.

 

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We remain highly leveraged. 

 

At December 31, 2014, we had $93.1 million of contractual commitments outstanding, consisting of debt service requirements, non-cancelable operating leases and purchase obligation commitments. Of such amount, $83.0 million was outstanding under our $200 million secured borrowing base revolving credit facility with a current borrowing base of $115 million. There has been a decline in natural gas and crude oil prices since the borrowing base was last determined. As a result, we currently expect the borrowing base to be reduced in connection with the redetermination at April 30, 2015. We do not currently expect the borrowing base to be reduced below current amount outstanding.

 

Our ability to borrow funds will depend upon a number of factors, including the condition of the financial markets. Under certain circumstances, the use of leverage may create a greater risk of loss to stockholders than if we did not borrow. The risk of loss in such circumstances is increased because we would be obligated to meet fixed payment obligations on specified dates regardless of our cash flow. If we do not make our debt service payments when due, our lenders may foreclose on assets securing such debt.

 

Our future level of debt could have important consequences, including the following:

 

•our ability to obtain additional debt or equity financing, if necessary, for drilling, expansion, working capital and other business needs may be impaired or such financing may not be available on favorable terms;

 

•a substantial decrease in our revenues as a result of lower oil and gas prices, decreased production or other factors could make it difficult for us to pay our liabilities. Any failure by us to meet these obligations could result in litigation, non-performance by contract counterparties or bankruptcy;

 

•our funds available for operations and future business opportunities will be reduced by that portion of our cash flow required to make principal or interest payments on our debt;

 

•we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

•our flexibility in responding to changing business and economic conditions may be limited.

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital. We may not be able to affect any of these remedies on satisfactory terms or at all.

 

Our credit agreement has substantial restrictions and financial covenants that restrict our business and financing activities.

 

The operating and financial restrictions and covenants in our credit agreement restrict our ability to finance future operations or capital needs and to engage, expand or pursue our business activities. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by our results of operations and financial conditions and events or circumstances beyond our control. If market or other economic conditions do not improve, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, our indebtedness may become immediately due and payable, the interest rates on our credit agreement may increase and the lenders’ commitment, if any, to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments in which event we may be forced to file for bankruptcy.

 

For a description of our credit facility, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement” and Note 10 in Part II, Item 8.

 

An increase in market interest rates will cause our debt service obligations to increase.

 

Borrowings under our credit agreement bear interest at floating rates. The rates are subject to adjustment based on fluctuations in market interest rates. An increase in the interest rates associated with our floating-rate debt would increase our debt service costs and affect our results of operations and cash flow. In addition, an increase in our interest expense could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

 

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We may not be able to obtain funding at all, or to obtain funding on acceptable terms, because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

 

In recent years, global financial markets and economic conditions experienced disruptions and volatility, which caused deterioration in the credit and capital markets. A recurrence of similar conditions in the future could make it difficult for us to obtain funding for our ongoing capital needs.

 

In volatile financial markets, the cost of raising money in the debt and equity capital markets can fluctuate widely and the availability of funds from those markets may diminish significantly. Our ability to access certain capital markets, such as, the market for high yield debt may be limited due to our size. The difficult financial environment may also limit the number of prospects for potential joint venture, asset monetization, or other capital raising transactions that we may pursue in the future or reduce the values we are able to realize in those transactions. As a result of these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If we cannot meet our capital needs, we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

 

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.

 

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2015 budget, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover economic or other circumstances may change from those contemplated by our 2015 budget, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

 

Our ability to produce oil and gas could be impaired if we are unable to acquire adequate supplies of water.

 

The recent drought, which began in 2011 and covered 80% of the contiguous United States with at least abnormally dry conditions, may impair our ability to obtain the water required for our drilling operations as government officials ration water supplies crucial to energy exploration. In the hardest-hit areas, water-management districts have warned residents and businesses to curtail usage from rivers, lakes and aquifers. The shortage is forcing exploration and production companies to buy water from farmers, irrigation districts and municipalities and is increasing the cost of the water. Our inability to locate sufficient amounts of water at reasonable prices could adversely impact our operations, particularly with respect to our Central Oklahoma oil producing properties.

 

We may incur losses as a result of title deficiencies in the properties in which we invest.

 

If an examination of the title history of a property reveals that an oil or gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such an instance, the amount paid for such lease or leases or other developed rights would be lost. It is management’s practice, in acquiring leases, or undivided interests in leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we will rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other developed rights in a specific mineral interest.

 

Prior to drilling a well, however, it is the normal practice in the industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. The work might include obtaining affidavits of heirship or causing an estate to be administered. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves.

 

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A change in the jurisdictional characterization of some of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our gathering assets, which may indirectly cause our revenues to decline and operating expenses to increase.

 

We believe that the facilities comprising our gathering systems meet the traditional tests used by FERC to distinguish gathering facilities, which are not subject to FERC’s jurisdiction under the NGA, from FERC-jurisdictional transmission facilities. The classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress. If FERC were to determine that the facilities perform primarily a transmission function, these facilities may become subject to regulation as interstate natural gas pipeline facilities and we may be subject to fines. We believe the expenses associated with compliance with FERC regulations, including seeking certificate authority for construction, service and abandonment, establishing rates and tariffs, and meeting FERC’s detailed regulatory accounting and reporting requirements, if such compliance were to become necessary, would substantially increase our operating costs and would adversely affect our profitability.

 

FERC regulation affects our gathering systems and the markets for our natural gas. FERC’s policies and practices concerning, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, could indirectly affect our gathering systems.

 

Although natural gas gathering facilities are exempt from FERC jurisdiction under the NGA, such facilities are subject to regulation by the state in which such facilities are located. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, open access requirements and rate regulation. Our gathering operations are limited to the states of Kansas, Oklahoma and West Virginia. We are licensed as an operator of a natural gas gathering system with the KCC and are required to file periodic information reports with the KCC. We are not required to be licensed as an operator or to file reports in Oklahoma or West Virginia.

 

Our gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. In the future, legislative and regulatory changes could require us to incur additional capital expenditures and increased costs.

 

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental and operational safety regulations or an accidental release of hazardous substances into the environment.

 

We may incur significant costs and liabilities as a result of environmental, health and safety requirements applicable to our oil and gas exploration, development, production, gathering and transportation activities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time.

 

Our operations are subject to stringent and complex environmental laws and regulations. Failure to comply with these or future laws and regulations or may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders limiting or enjoining future operations or imposing additional compliance requirements or operational limitations. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

 

There is inherent risk of environmental costs and liabilities in our business due to our handling of oil and natural gas, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary.

 

We may face unanticipated water and other waste disposal costs. 

 

We may be subject to regulation that restricts our ability to discharge water produced as part of our gas production operations. Productive zones frequently contain water that must be removed in order for the gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce gas in commercial quantities. The produced water must be transported from the lease and injected into disposal wells. The availability of disposal wells with sufficient

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capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

 

In the event (1) water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, (2) our wells produce water in excess of the applicable volumetric permit limits, (3) the disposal wells fail to meet the requirements of all applicable regulatory agencies, or (4) we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

 

•we cannot obtain future permits from applicable regulatory agencies;

 

•water of lesser quality or requiring additional treatment is produced;

 

•our wells produce excess water;

 

•new laws and regulations require water to be managed or disposed in a different manner; or

 

•costs to transport the produced water to the disposal wells increase.

 

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. EPA has delegated the authority to administer RCRA, in whole or in part to individual states, which also can impose their own, more stringent requirements. Our operations generate some ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, which may be regulated as hazardous wastes. The transportation of natural gas in pipelines may also generate some hazardous wastes subject to RCRA or comparable state laws. Drilling fluids, produced waters, and most other wastes associated with the exploration, development, production and transportation of oil and gas are currently excluded from regulation as hazardous wastes under RCRA but may be regulated by EPA or state agencies as non-hazardous solid wastes. Moreover, it is possible that this exclusion could change and cause some or all of such wastes now to be classified as hazardous wastes, which could increase our waste management costs and could have a material adverse effect on our results of operations and financial position.

 

Recent and future environmental laws and regulations may significantly limit, and increase the cost of, our exploration, production and gathering operations.

 

Recent and future environmental laws and regulations, including additional federal and state restrictions on greenhouse gas emissions (“GHG”) in response to climate change concerns, may increase our capital and operating costs and also reduce the demand for the oil and natural gas we produce. The oil and gas industry is a direct source of certain GHG emissions, such as carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. The EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule, which required certain sources and other facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year to begin collecting GHG emissions data under a new reporting system as of January 1, 2010. In November 2010, the EPA issued final regulations requiring the annual reporting of GHG emissions from qualifying facilities in the upstream oil and natural gas sector, including onshore production (Subpart W). Although the Mandatory Reporting Rule does not control GHG emission levels from any facilities, it has caused us to incur monitoring and reporting costs for emissions subject to the rule. In addition, relatively large sources of GHG emission are subject to permitting requirements, which could be expanded in the future to include smaller sources. Further, on January 14, 2015, the Obama Administration announced that, pursuant to the President’s Climate Action Plan, the EPA will propose a rule in the summer of 2015 to set standards for methane and volatile organic compound emissions from new and modified sources in the oil and gas sector. A final rule is expected in 2016. The Administration’s announcement also stated that other federal agencies, including the Bureau of Land Management, the Pipeline and Hazardous Materials Safety Administration, and the Department of Energy will impose new or more stringent regulations on the oil and gas sector that will have the effect of further reducing methane emissions.

 

Federal or state legislative or regulatory initiatives that regulate or restrict emissions of GHGs in areas in which we conduct business, as well as private legal actions brought under common law theories for alleged climate change impacts, could adversely affect the demand for our products and could increase the costs of our operations, including costs to operate and maintain our facilities, obtain and comply with permits, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and/or administer and manage a GHG program. Reductions in our revenues or increases in our expenses as a result of climate legislative and regulatory initiatives or litigation could have a material adverse effect on our business.

 

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Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. We may incur expenditures in the future for air pollution control equipment in connection with obtaining or maintaining permits and approvals for air emissions.

 

The Endangered Species Act (“ESA”), restricts activities that may affect endangered or threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans or limit future development activity in the affected areas. The Migratory Bird Treaty Act (“MBTA”) protects migratory birds. Criminal liability can attach for even an incidental taking of migratory birds, and in recent years the federal government has issued indictments under the MBTA to several oil and gas companies after dead migratory birds were found near reserve pits associated with drilling activities.

 

 

Federal legislation and state legislative and regulatory initiatives relating to oil and gas operations, including hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.

 

Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely employ hydraulic fracturing in our drilling activity. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act “SDWA”. On February 11, 2014, the EPA released guidance and an interpretative memorandum clarifying that SDWA permit requirements apply to hydraulic fracturing activities using diesel fuels and indicating EPA’s intent to make decisions on such permitting on a case-by-case basis. In addition, Congress has considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Moreover,  on May 9, 2014, EPA has issued an advance notice of proposed rulemaking under the Toxic Substances Control Act relating to chemical substances and mixtures used in oil and gas exploration and production. Further, on May 24, 2013 the U.S. Department of the Interior published a proposed rule in the Federal Register that includes disclosure requirements and other mandates for hydraulic fracturing on federal lands.

 

State legislatures and agencies are also enacting legislation and promulgating rules to regulate hydraulic fracturing and require disclosure of hydraulic fracturing chemicals. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

 

There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. These on-going or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.

 

Further, on April 17, 2012, the EPA issued final rules that subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The rules establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment and include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators must capture natural gas not sent to the gathering line during well completion and make it available for use or sale, which can be done through the use of green completions. Since promulgating final rules, the EPA has reconsidered aspects of them, and has indicated that it will make additional changes, and litigation challenging the rules is also ongoing. We are currently evaluating the effect these rules could have on our business and believe that these rules could result in increased operating costs.

 

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

 

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Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

 

The Obama administration's most recent budget proposal and other recently proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. Proposed changes to such tax incentives include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for U.S. production activities and (4) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our consolidated financial position, results of operations or cash flows.

 

Our ability to grow and to increase our profitability may depend in part on our ability to make acquisitions. Acquisitions are subject to a number of risks.

 

Our ability to grow and increase our profitability may depend in part on our ability to make acquisitions that result in an increase in our net income per share and cash flows. We may be unable to make such acquisitions because we are: (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms or (3) outbid by competitors. If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, which will adversely affect our results of operations. Even if we do make acquisitions that we believe will increase our net income per share and cash flows, these acquisitions may perform below our expectations and nevertheless result in a decrease in net income and/or cash flows.

 

Our acquisitions may involve number risks, including:

 

•operating a larger combined organization and adding operations;

 

•difficulties in assimilating and operating the assets and operations of the acquired business, particularly if the assets acquired are in a new geographical area;

 

•risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;

 

•loss of significant key employees from the acquired business; 

 

•diversion of management’s attention from other business concerns;

 

•failure to realize expected profitability or growth;

 

•failure to realize expected synergies and cost savings;

 

•coordinating geographically disparate organizations, systems and facilities; and

 

•coordinating or consolidating corporate and administrative functions.

 

If third-party pipelines and other facilities interconnected to our gas pipelines become unavailable to transport or produce gas, our revenues and cash flows could be adversely affected.

 

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable to transport or produce gas, our revenues and cash flows could be adversely affected.

 

We do not own all of the land on which our pipelines are located or on which we may seek to locate pipelines in the future, which could disrupt our operations and growth.

 

We do not own the land on which our pipelines have been constructed, but we do have right-of-way and easement agreements from landowners and governmental agencies, some of which require annual payments to maintain the agreements and most of which have a perpetual term. New pipeline infrastructure construction may subject us to more onerous terms or to increased costs if the

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design of a pipeline requires redirecting. Such costs could have a material adverse effect on our business, results of operations and financial condition.

 

In addition, the construction of additions to the pipelines may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to expand pipelines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way. If the cost of obtaining new rights-of-way increases, our business and results of operations could be adversely affected.

 

We have identified material weaknesses in our disclosure controls and procedures and our internal control over financial reporting, and we may be unable to develop, implement and maintain appropriate controls in future periods.

The Sarbanes-Oxley Act of 2002 and SEC rules require that management report annually on the effectiveness of our internal control over financial reporting and our disclosure controls and procedures. Among other things, management must conduct an assessment of our internal control over financial reporting to allow management to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. As more fully described in Note 20 of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, we have restated our consolidated financial statements for prior periods to correct certain errors.  Accordingly, based on our management’s assessment, we believe that, as of December 31, 2014, our internal controls over financial reporting were not effective. The specific material weakness is described in Item 9A, “Controls and Procedures” of this Annual Report on Form 10-K in “Management’s Annual Report on Internal Control over Financial Reporting”.  A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements would not be prevented or detected.  We cannot assure you that additional material weaknesses in our internal control over financial reporting will not be identified in the future.  Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could result in additional material weaknesses, or could result in material misstatements in our financial statements.  These misstatements could result in additional restatements of our financial statements, cause us to fail to meet our reporting obligations or cause investors to lose confidence in our reported financial information.

We have developed certain remediation steps to address the material weakness discussed above and to improve our internal control over financial reporting.  If we fail to remediate the material weakness, there will continue to be an increased risk that our future financial statements could contain errors that will be undetected.  Further and continued determinations that there are material weaknesses in the effectiveness of our internal controls could reduce our ability to obtain financing or could increase the cost of any financing we obtain and require additional expenditures of resources to comply with applicable requirements.  For more information relating to our internal control over financial reporting and disclosure controls and procedures, and the remediation plan undertaken by us, see Item 9A, “Controls and Procedures” of this Annual Report on Form 10-K.

 

Risks Related to the Ownership of Our Common Stock

 

The price of our common stock has been experiencing and may continue to experience volatility.

 

The price of our common stock has been and may continue to be volatile. In addition to the risk factors described above, some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community, sales of our common stock by significant stockholders, short-selling of our common stock by investors, issuance of a significant number of shares for equity-based compensation or to raise additional capital to fund our operations, changes in market valuations of similar companies and speculation in the press or investment community about our financial condition or results of operations, as well as any doubt about our ability to continue as a going concern. General market conditions and U.S. or international economic factors and political events unrelated to the performance of us may also affect our stock price. For these reasons, investors should not rely on recent trends in the price of our common stock to predict the future price of our common stock or our financial results.

 

Our common stock may be at risk for delisting from Nasdaq in the future. A delisting of our common stock is likely to reduce the liquidity and market price of our common stock.

 

On November 24, 2014, we received a notice from The Nasdaq Stock Market (“Nasdaq”) that we were not in compliance with Nasdaq’s Listing Rule 5450(a)(1), as the minimum bid price of our common stock had been below $1.00 per share for 30 consecutive business days.  To regain compliance, the minimum bid price of our common stock must meet or exceed $1.00 per share for a minimum of ten consecutive business days during a 180-day grace period.  Due to our ten-to-one reverse split of all outstanding shares of our common stock effective January 2, 2015, we have regained compliance with this listing standard.  Although we have regained

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compliance with the minimum bid price requirement, there can be no assurance that we will be able to maintain continued compliance with that requirement. 

 

On December 23, 2014, we received another notice from Nasdaq that, for the prior 30 consecutive business days, the market value of our publicly held shares was below $15,000,000 and that we therefore are not in compliance with the market value of publicly held shares requirement set forth in Nasdaq Listing Rule 5450(b)(3)(C).  The Nasdaq Listing Rules define “publicly held shares” as total shares outstanding, less any shares held directly or indirectly by officers, directors or a beneficial owner of more than 10% of the total outstanding shares.  We have 180 calendar days from the date of such notification, or until June 22, 2015, to achieve compliance with the market value of publicly held shares requirement.  To regain compliance, the market value of our publicly held shares must close at $15,000,000 or more for a minimum of ten consecutive business days during the 180-day grace period.  Our failure to regain compliance during this period could result in delisting from the Nasdaq Global Market. We would then seek to list our common stock on the Nasdaq Capital Market, which, among other things, requires either at least $2.5 million of stockholders' equity, market value of listed securities of at least $35 million or net income in the last fiscal year (or in two of the last three fiscal years) of at least $500,000.

 

If our common stock is delisted from the Nasdaq Global Market and we do not qualify for listing on the Nasdaq Capital Market, our common stock will no longer be listed on a national securities exchange.  As a result, it could become more difficult to dispose of, or obtain accurate quotations for the price of, our common stock, and the price of our common stock may decline.

 

Our charter and bylaws contain provisions that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of our stockholders’ common stock at a premium to the market price or would otherwise be beneficial to our stockholders.

 

There are provisions in our restated certificate of incorporation and bylaws that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of our stockholders’ common stock at a premium to the market price or would otherwise be beneficial to our stockholders. For example, our restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, provisions of our restated certificate of incorporation and bylaws, including limitations on stockholder actions by written consent and on stockholder proposals and director nominations at meetings of stockholders, could make it more difficult for a third party to acquire control of us. Delaware corporation law may also discourage takeover attempts that have not been approved by our board of directors.

 

White Deer Energy L.P. and its affiliates (“White Deer”) beneficially own approximately 79%, as of March 2, 2015, of our common stock after giving effect to the exercise of their outstanding warrants, giving White Deer control in corporate transactions and other matters, including a sale of our Company, as well as potentially diluting the profits of the Company.

 

At March 2, 2015,  including 4,307,239 common shares owned and 3,301,249 warrants, White Deer beneficially owns 7,608,488 shares, or approximately 79%, of our common stock. By exercising their warrants, White Deer can benefit from their respective percentage of all of our profits and growth. In addition, we have agreed to issue White Deer additional warrants on each quarterly dividend payment date of the Series A Preferred Stock prior to June 30, 2016, on which dividends are not paid in cash but instead accrue. The voting power of the Series B Preferred Stock issued with certain of the warrants is limited to 45% of the votes applicable to all outstanding voting stock. In addition, White Deer may vote any shares of common stock held by it without regard to that limit.

 

As a result of its ownership, White Deer is our controlling stockholder and is able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of certain corporate transactions or other matters submitted to our stockholders for approval, including, for example, potential mergers or acquisitions, asset sales and other significant corporate transactions. The interests of White Deer may not coincide with the interests of other holders of our common stock.

 

Subject to certain restrictions, White Deer may make investments in companies that compete with us. In addition, our interests may conflict with those of White Deer with respect to, among other things, business opportunities that may be presented to White Deer and to our directors associated with White Deer.

 

Substantial sales of our common stock by White Deer could cause our stock price to decline.

 

We are unable to predict whether significant amounts of our common stock will be sold by White Deer. Any sales of substantial amounts of our common stock in the public market by White Deer, or the perception that these sales might occur, could lower the market price of our common stock.

 

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Forward-Looking Statements

 

Various statements in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements include those regarding projections and estimates concerning the timing and success of specific projects; financial position; business strategy; budgets; amount, nature and timing of capital expenditures; drilling of wells and construction of pipeline infrastructure; acquisition and development of oil and gas properties and related pipeline infrastructure; timing and amount of future production of oil and gas; operating costs and other expenses; estimated future net revenues from oil and gas reserves and the present value thereof; cash flow and anticipated liquidity; funding of our capital expenditures; ability to meet our debt service obligations; and other plans and objectives for future operations.

 

When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The factors impacting these risks and uncertainties include, but are not limited to:

 

•current weak economic conditions;

 

•volatility of oil and gas prices;

 

•increases in the cost of drilling, completion and gas gathering or other costs of developing and producing our reserves;

 

•our debt covenants;

 

•access to capital, including debt and equity markets;

 

•results of our hedging activities;

 

•drilling, operational and environmental risks; and

 

•regulatory changes and litigation risks.

 

You should consider carefully the statements in Part I, Item 1A. “Risk Factors” and other sections of this Annual Report on Form 10-K, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

 

We have based these forward-looking statements on our current expectations and assumptions about future events. The forward-looking statements in this report speak only as of the date of this report; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the SEC, which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS 

 

None.

 

ITEM 2.  PROPERTIES

 

We have described our properties, reserves, acreage, wells, production and drilling activity in Part I, Item 1. “Business” of this Annual Report on Form 10-K, which is incorporated by reference herein in response to this Item. A substantial portion of our assets are pledged to collateralize our secured credit facilities. See Note 10 in Part II, Item 8. “Financial Statements and Supplementary Data.”

 

Administrative Facilities

 

Our corporate headquarters office space located at 210 Park Avenue, Oklahoma City, Oklahoma 73102 is leased. The office lease is for 10 years expiring August 31, 2017, and covers approximately 35,000 square feet of which approximately 10,000 square feet is subleased at no cost to the company.

 

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We own two buildings in Chanute, Kansas and one in Lenapah, Oklahoma, for our MidContinent operations.

 

We lease approximately 1,500 square feet of office space on a month-to-month basis for field personnel in Harrisville, West Virginia.

 

ITEM 3. LEGAL PROCEEDINGS 

 

We are subject, from time to time, to certain legal proceedings and claims in the ordinary course of conducting our business. We will record a liability related to our legal proceedings and claims when we have determined that it is probable that we will be obligated to pay and the related amount can be reasonably estimated, and we will disclose the related facts in the notes to our financial statements, if material. If we determine that an obligation is reasonably possible, we will, if material, disclose the nature of the loss contingency and the estimated range of possible loss, or include a statement that no estimate of loss can be made. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. Therefore, it is extremely difficult to reasonably quantify future environmental related expenditures. For further discussion of lawsuits and related contingencies, see Note 14 in Part II, Item 8. “Financial Statements and Supplementary Data.”

 

On March 31, 2014, PostRock Energy Corporation and its wholly owned subsidiary, Constellation Energy Partners Management, LLC (“CEPM”), entered into a settlement agreement fully resolving all claims associated with the lawsuit filed August 30, 2013 against SPP, SPP’s  Chief Executive Officer, members of SPP’s Board of Managers, Sanchez Oil & Gas Corporation and Sanchez Energy Partners I, LP (“SEPI”). For further discussion see Note 8 in Part II, Item 8. “Financial Statements and Supplementary Data.”

 

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

 

Market Information

Our common stock is listed on the NASDAQ Stock Market LLC under the symbol “PSTR.” On January 2, 2015 our common stock underwent a 1-for-10 reverse stock split. All previously reported common stock, options, warrants, Series B Preferred Stock, and per share amounts within this document have been retroactively adjusted to reflect the reverse stock split. The table below presents the intraday high and low price for each quarter for the prior two fiscal years.

 

 

 

The closing price of our common stock on March 2, 2015 was $3.96 per share. At March 2, 2015, there were 6,372,054 shares of common stock outstanding held of record by approximately 388 stockholders. Warrants to purchase 3,301,249 shares of our common stock at a weighted average exercise price of $13.00 per share were outstanding and held by White Deer.

 

Dividends

 

The payment of dividends on our common stock is within the discretion of the board of directors and is dependent upon many factors. We have not declared any dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future. Our credit facility contains restrictions on our ability to pay dividends.

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Issuer Purchases of Equity Securities 

 

The following table provides information regarding purchases of our common stock that were made by us during the year ended December 31, 2014. PostRock does not have any publicly announced equity securities repurchase plans or programs.

 

 

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(1) Share repurchases represent shares withheld by us from employees for the payment of personal income tax withholding on restricted stock vesting and distributions from the deferred compensation plan.

 

ITEM 6.  SELECTED FINANCIAL DATA 

 

The following information as of and for the years ended December 31, 2010, 2011, 2012 and 2013 has been updated to reflect the restatement to our financial statements as discussed in Note 20 to the Consolidated Financial Statements included in Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report Form 10-K.  You should read the selected consolidated historical financial information set forth below along with our restated audited consolidated financial statements and the notes thereto included in Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

 

We have derived the following selected consolidated financial information as of December 31, 2013 and 2014 and for the years ended December 31, 2012, 2013 and 2014 from the audited consolidated financial statements included in Part II, Item 8. “Financial Statements and Supplementary Data.” We have derived the selected consolidated financial information as of December 31, 2010 and 2011, and for the period from January 1 to March 5, 2010, March 6 to December 31, 2010 and the year ended December 31, 2011, from PostRock’s and the Predecessors’ audited consolidated financial information included in our prior SEC filings.

 

We have not amended our previously filed Annual Reports on Form 10-K or Quarterly Reports on Form 10-Q for the periods affected by the restatement.  The financial information that has been previously filed or otherwise reported for these periods is superseded by the information in this Annual Report on Form 10-K, and the financial statements and related financial information contained in such previously filed reports should no longer be relied upon.  These historical results are not necessarily indicative of results to be expected for any future periods.

 

 

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The information included in this table has been restated where noted to correct the error from the reclassification of redeemable preferred stock from temporary equity to a liability, and the related dividends and accretion from stockholders’ equity to interest expense.

 

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Comparability of information in the above table between years is affected by, among other things, (1) changes in the annual average prices for oil and natural gas, (2) the Recombination in 2010, (3) the sale of some of our Appalachian Basin oil and gas properties in 2010 and 2011, (4) our 2011 investment in SPP, (5) an impairment of producing properties of $5.9 million in 2012, (6) the sale of our KPC pipeline subsidiary in 2012 and (7) increased oil production in 2013 and 2014 related to drilling and development.

 

ITEM 7.MANAGEMENT’S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

The accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with the following discussion.

 

Restatement of Previously Issued Consolidated Financial Statements

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations has been updated to reflect the effects of the restatement described in Note 20 of the Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data.” We have included the restated interest expense discussion from the quarterly comparisons for the three, unaudited quarters of 2013 and 2014 in our year ended Results of Operations, below.

 

Overview of Our Company

 

We are an independent oil and gas company engaged in the acquisition, exploration, development, production and gathering of crude oil and natural gas. Our primary production activity is focused in the Cherokee Basin, a 15-county region in southeastern Kansas and northeastern Oklahoma, and central Oklahoma. We also have minor oil and gas producing properties in the Appalachian Basin. We previously owned an interstate natural gas pipeline which was sold in September 2012, and we report its results as a discontinued operation in our financial statements.

 

Strategy

 

Our strategy is to acquire, develop and efficiently manage long-lived oil and gas properties and undeveloped leases in proven producing regions where we recognize the opportunity to add value through additional development, application of modern technologies and techniques, and efficiencies gained through consolidation. Our plans are to exploit our existing asset base and build regionally from our core operations, primarily in the Cherokee Basin and Central Oklahoma at present.

 

In 2014, we focused on increasing the percentage of oil and liquids in our production and reserves. As of and for the year ended December 31, 2013, our reserves and our production on an energy equivalent basis, included 23% and 7% oil, respectively. As of and for the year ended December 31, 2014, those percentages had changed to 17% and 11%, respectively. As oil and natural gas prices declined toward the end of 2014 and into 2015, our plan is to reduce capital expenditures by approximately 85% to $5.4 million in 2015.  Additionally, in February, 2015, we engaged Evercore Group L.L.C. as an advisor to assist the Board in evaluating strategic alternatives.

 

Key Factors Affecting Our Results of Operations 

 

•Realized natural gas prices were $4.25/Mcf during 2014 compared to $3.55/Mcf during 2013 and $2.68/Mcf in 2012.  

 

•Low natural gas prices have resulted in reduced natural gas development, which has led to a decline in our natural gas production. Our natural gas production was 13.2 Bcf in 2014, 14.5 Bcf in 2013 and 16.4 Bcf in 2012. 

 

•Realized oil prices were $89.23/Bbl during 2014 compared to $94.56/Bbl in 2013 and $90.13/Bbl in 2012.

 

•High oil prices resulted in an increased focus on oil development, which led to an increase in our oil production. Our oil production was 274,919 barrels in 2014, 192,474 barrels in 2013 and 95,863 barrels in 2012. 

 

•We continued to focus on reducing our costs in both our field operations and our Oklahoma City office.

 

•We had 199, 209 and 216 employees, at December 31, 2014, 2013 and 2012, respectively. Additionally, since year-end we have reduced our staffing levels by 17% in both field and administrative personnel.

 

•Lease operating expenses and gathering expenses were $35.2 million in 2014 compared to $35.1 million in 2013 and $37.6 million in 2012.

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•General and administrative expenses were $13.9 million during 2014 compared to $16.0 million in 2013 and $14.8 million in 2012. 

 

•We entered into a Preferred Stock Exchange Agreement with White Deer pursuant to which we issued 3,211,378 shares of our common stock to White Deer in exchange for 2,175 shares of Series A Preferred Stock issued to White Deer on September 21, 2010.  The Series A Preferred Stock had an aggregate liquidation preference of $35.0 million, as calculated pursuant to the certificate of designations for the Series A Preferred Stock.

 

How We Evaluate Our Operations

 

Management uses and expects to continue to use a variety of financial and operational metrics to analyze performance and the health of the business. These metrics focus on rates of return and cost efficiency with an emphasis on cash costs. A few of the metrics we focus on include: (1) volume and mix of production and reserves; (2) reserve life; (3) lease operating expense, gathering expense and general and administrative expense; (4) gathering throughput volumes, fuel consumption by our facilities and crude oil and  natural gas sales volumes; and (5) debt balances.

 

General Trends and Outlook

 

Realized Prices

 

We sell our Cherokee Basin gas production based on the Southern Star index. We sell our Central Oklahoma gas production based on the ONEOK Index Gas Price. We sell the majority of our natural gas in the Appalachian Basin based on the Dominion Southpoint index, with the remainder sold on a local basis. The Southern Star prices typically are at a discount to the NYMEX pricing at Henry Hub, the regional pricing point. The Dominion Southpoint prices have also been at a discount to the NYMEX pricing at Henry Hub. During 2014, the basis discount in the Cherokee Basin ranged from $0.07 to $0.51/MMBtu while the basis discount in the Appalachian Basin ranged from $0.20 to $1.94/MMBtu. According to the U.S. Energy Information Administration (“EIA”), the Henry Hub spot price averaged $4.39 per MMBtu in 2014. NYMEX strip prices at March 2, 2015,  average $2.95/MMBtu, $3.11/MMBtu, and $3.25/MMBtu for the forward 12, 24 and 36 month period, respectively. We sell the majority of our oil production under a contract priced at a fixed discount to NYMEX WTI oil prices. Oil and natural gas prices historically have been very volatile and will likely continue to be so in the future.

 

We utilize our hedging program to attempt to mitigate the risk that variability of commodity pricing creates for our cash flows. See Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” of this Annual Report on Form 10-K for further details on our hedging activity.

 

Supply and Demand of Oil and Gas

 

As seen in the recent decline in crude oil and natural gas prices, North American oil and gas prices are and have historically been volatile based on supply and demand dynamics. We expect this volatility to continue throughout 2015. Although natural gas prices improved in 2014 compared to 2013, natural gas continues to be challenged due to an imbalance between supply and demand across North America. Natural gas prices finished 2014 lower than 2013 and have since declined further reflecting both lower-than-expected space heating demand and higher natural gas production in the 2014 winter. Looking to 2015, we expect natural gas prices will remain below 2014 levels.

 

While crude oil remained more valuable than natural gas on a relative energy equivalent basis, we and other oil and natural gas producers increased focus on oil development in 2013 and 2014.  With this increased focus on oil development coupled with the use of horizontal drilling technologies throughout the United States, producers were able to more efficiently produce higher volumes of oil into the market while demand did not follow suit. As crude oil supply grows, transportation capacity to downstream markets is increasingly important. Bottlenecks and other transportation limitations also add volatility among U.S. grades of oil. Crude oil prices remained consistent with 2013 if not slightly up until July 2014 when prices started to drop dramatically through the remainder of 2014 and into 2015. Global crude oil supply is expected to remain more than demand in 2015 thus causing lower expected crude oil prices. We expect 2015 oil prices to remain below 2014 levels throughout the year.

 

Drilling Programs

 

Our 2014 exploration and development capital expenditures totaled $32.2 million with the majority of capital spent in Central Oklahoma.  We also spent $4.6 million finishing our compressor project in Cherokee Basin during 2014. We have described our projects and drilling activity in Part I, Item 1. “Business” of this Annual Report on Form 10-K.

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Our focus for 2015 will be decreasing capital expenditures and reducing costs. We have budgeted approximately $5.4 million in capital projects, of which $3.6 million will be spent on completing 2014 projects in Central Oklahoma. If attractive opportunities arise, additional capital may be directed towards further oil development in Central Oklahoma. We intend to fund our 2015 capital expenditures with cash flow from operations and availability under our credit facility.

Results of Operations

 

Year ended December 31, 2013 compared to the year ended December 31, 2014

 

The following table presents financial and operating data for the fiscal years ended December 31, 2013 and 2014.

 

 

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*   Not meaningful.

 

Natural gas sales increased $4.8 million, or 9.3%, from $51.5 million for the year ended December 31, 2013, to $56.3 million for the year ended December 31, 2014. Higher realized natural gas prices increased revenues by $9.4 million while lower volumes decreased revenues by $4.6 million. Natural gas volumes decreased 1.3 Bcf due to continued suspension of our gas development throughout 2014 as oil development remained more economic. Crude oil revenues increased $6.3 million, or 34.8%, from $18.2 million for the year ended December 31, 2013 to $24.5 million for the year ended December 31, 2014. Increased oil volumes contributed $7.8 million of the increase while lower realized prices decreased revenues by $1.5 million. The increase in oil volumes was due to our continued focus on oil development in 2014. Average realized natural gas prices increased from $3.55 per Mcf in 2013 to $4.25 per Mcf in 2014 while average oil prices decreased from $94.56 per barrel in 2013 to $89.23 per barrel in 2014. Oil and gas sales exclude realized gains and losses from our derivative financial instruments.

 

Gathering revenue increased $89,000, or 3.4%, from $2.6 million for the year ended December 31, 2013, to $2.7 million for the year ended December 31, 2014. The increase was due to higher gas prices in 2014.

 

Production expense consisting of lease operating expenses, severance and ad valorem taxes and gathering expense increased $0.8 million, or 2.0%, from $40.1 million for the year ended December 31, 2013, to $40.9 million for the year ended December 31, 2014. The increase was due to higher operating costs in Central Oklahoma of $2.3 million due to increased production activity along with higher severance and ad valorem taxes of $703,000 offset by decrease in lower operating costs in Cherokee Basin of $2.2 million mainly due to lower gathering costs resulting from the compressor project discussed in Part I, Item 1. “Business” of this Annual Report on Form 10-K. As a result of lower production volume, production expense per Mcfe increased from $2.56 per Mcfe for the year ended December 31, 2013, to $2.75 per Mcfe for the year ended December 31, 2014.

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Depreciation, depletion and amortization increased $1.5 million or 5.6% from $27.4 million for the year ended December 31, 2013, to $28.9 million for the year ended December 31, 2014. On a per unit basis, we had an increase of $0.19 per Mcfe from $1.75 per Mcfe for the year ended December 31, 2013, to $1.94 per Mcfe for the year ended December 31, 2014.

 

General and administrative expenses decreased $2.1 million, or 13.1%, from $16.0 million for the year ended December 31, 2013, to $13.9 million for the year ended December 31, 2014. The decrease was due to lower legal fees of $1.6 million which was related to the litigation with CEP/SPP and Sanchez Energy in 2013 along with lower benefits of $1.6 million due to less non-cash compensation. The decrease was primarily offset by higher wages and bonuses of $1.0 million.

 

Other income and expense consists primarily of realized and unrealized gains or losses from derivative instruments, gain or loss from our investment in SPP, and net interest expense. We recorded realized losses of $2.3 million and $3.9 million on our derivative contracts for the years ended December 31, 2013 and 2014, respectively. We recorded unrealized gains of $1.7 million and $20.3 million on our derivative contracts for the years ended December 31, 2013 and 2014, respectively. We recorded mark-to-market gains of $6.8 million and $1.8 million on our investment in SPP for the years ended December 31, 2013 and 2014, respectively. We also recorded a realized gain on our investment in SPP of $5.4 million in 2014; see further discussion on our investment in Note 8 in Part II, Item 8 “Financial Statements and Supplementary Data.”  Interest expense, net was $18.1 million and $19.7 million for the years ended December 31, 2013 and 2014, respectively. Interest expense was higher in 2014 as a result of increased accretion and paid-in-kind dividends associated with our mandatorily redeemable preferred stock.

 

Restated quarterly comparisons

 

Interest expense, net, was $4.2 million and $4.8 million during the three months ended March 31, 2013 and 2014, respectively. Excluding non-cash interest of $3.9 million related to our Series A Preferred Stock, interest expense, net, was $965,000 during the three months ended March 31, 2014 and was higher compared to the prior period as a result of higher debt in the current period.

 

Interest expense, net, was $4.4 million during the three months ended June 30, 2013, and $4.9 million during the three months ended June 30, 2014. Excluding non-cash interest of $4.0 million related to our Series A Preferred Stock, interest expense, net was $915,000 in the 2014 period.

 

Interest expense, net, was $4.7 million during the three months ended September 30, 2013, and $5.1 million during the three months ended September 30, 2014. Excluding non-cash interest of $4.2 million related to our Series A Preferred Stock, interest expense, net was $867,000 in the 2014 period.

 

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Year ended December 31, 2012 compared to the year ended December 31, 2013

 

The following table presents financial and operating data for the fiscal years ended December 31, 2012 and 2013.

 

 

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*   Not meaningful.

 

Natural gas sales increased $7.6 million, or 17.3%, from $43.9 million for the year ended December 31, 2012, to $51.5 million for the year ended December 31, 2013. Higher realized natural gas prices increased revenues by $12.6 million while lower volumes decreased revenues by $5.0 million. Natural gas volumes decreased 1.9 Bcf due to continued suspension of our gas development throughout 2013 as oil development remained more attractive economically. Crude oil revenues increased $9.6 million, or 110.6%, from $8.6 million for the year ended December 31, 2012 to $18.2 million for the year ended December 31, 2013. Increased oil volumes contributed $8.7 million of the increase in oil revenues. Average realized natural gas prices increased from $2.68 per Mcf in 2012 to $3.55 per Mcf in 2013 while average oil prices increased from $90.13 per barrel in 2012 to $94.56 per barrel in 2013. Oil and gas sales exclude realized gains or losses from our derivative financial instruments.

 

Gathering revenue increased $167,000, or 6.8%, from $2.4 million for the year ended December 31, 2012, to $2.6 million for the year ended December 31, 2013. The increase was due to higher gas prices during 2013.

 

Production expense consists of lease operating expenses, severance and ad valorem taxes and gathering expense. Production expense decreased $2.1 million, or 5.0%, from $42.2 million for the year ended December 31, 2012, to $40.1 million for the year ended December 31, 2013. Expense in 2012 included a $368,000 charge related to field reorganization. When this charge is excluded, production costs decreased $1.8 million, or 4.2%, from the prior year adjusted cost of $41.8 million. Lower compressor rental costs of $1.1 million, lower repairs and maintenance of $635,000, lower workover costs of $486,000, lower ad valorem taxes of $271,000, and reductions in other operational areas were partially offset by higher production taxes of $614,000 and higher electricity costs of $263,000. As a result of lower production volume, production expense per Mcfe increased from $2.49, or an adjusted $2.47, per Mcfe for the year ended December 31, 2012, to $2.56 per Mcfe for the year ended December 31, 2013.

 

Depreciation, depletion and amortization remained relatively consistent from the prior year as it decreased $300,000 from $27.7 million for the year ended December 31, 2012, to $27.4 million for the year ended December 31, 2013. On a per unit basis, we had an increase of $0.12 per Mcfe from $1.63 per Mcfe for the year ended December 31, 2012, to $1.75 per Mcfe for the year ended December 31, 2013.

 

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General and administrative expenses increased $1.2 million, or 8.0%, from $14.8 million for the year ended December 31, 2012, to $16.0 million for the year ended December 31, 2013. The 2012 period included a $503,000 charge related to reorganization of our Oklahoma City office and $2.2 million of non-cash compensation. Expense in 2013 included $1.6 million of legal fees related to the litigation with CEP/SPP and Sanchez Energy, a $454,000 workman’s compensation charge, and $4.3 million of non-cash compensation. Excluding these charges, general and administrative expenses totaled $9.7 million, or 20.1%, lower than the prior year. The decrease was due primarily to reduced wages, benefits and bonuses of $601,000, higher capitalized labor of $434,000, and lower contract labor and other services of $299,000.

 

Other income (expense) consists primarily of realized and unrealized gains or losses from derivative instruments, gain or loss from equity investment, and net interest expense. We recorded a realized gain of $73.2 million and loss of $2.3 million on our derivative contracts for the years ended December 31, 2012 and 2013, respectively. We recorded a $66.7 million unrealized loss and a $1.7 million unrealized gain on our derivative contracts for the years ended December 31, 2012 and 2013, respectively. During 2012, we exited our above-market natural gas swap contracts, originally scheduled to settle in 2013, for proceeds of $30.2 million. These proceeds are included in the 2012 realized gains disclosed above. We recorded a mark-to-market loss of $5.2 million and a mark-to-market gain of $6.8 million on our equity investment in SPP for the years ended December 31, 2012 and 2013, respectively. The gain in 2013 was the result of an increase in the market price of SPP’s publicly traded equity, which consequently increased the value of our investment. Interest expense, net, was $21.8 million and $18.1 million for the years ended December 31, 2012 and 2013, respectively. Interest expense was lower as a result of reduced debt. We recorded a gain on forgiveness of debt of $255,000 for the year ended December 31, 2012 as a result of the restructuring of the QER Loan, discussed in Note 10 in Part II, Item 8. “Financial Statements and Supplementary Data.” There was no gain on forgiveness of debt for the year ended December 31, 2013.

 

We recorded a loss from discontinued operations of $2.9 million for the year ended December 31, 2012. The loss was related to the operations and subsequent sale of our interstate natural gas pipeline. There were no discontinued operations for the year ended December 31, 2013.

 

Liquidity and Capital Resources

 

Debt Borrowings

 

Our total debt decreased  from $92.0 million at December 31, 2013 to $83.0 million at December 31, 2014.  

 

Historical Cash Flows and Liquidity

 

Our primary sources of liquidity for 2014 were cash from operations, proceeds from our settlement of the SPP lawsuit and the subsequent sale of SPP Class B units.

 

Cash flows from operating activities have historically been driven by the quantities of our production and the prices received from the sale of this production. Prices of oil and gas have historically been very volatile and can significantly impact the cash from the sale of our production. Use of derivative financial instruments help mitigate this price volatility. Proceeds from or payments for derivative settlements are included in cash flows from operations. Cash expenses also impact our operating cash flow and consist primarily of production operating costs, production taxes, interest on our indebtedness and general and administrative expenses. Our primary sources of liquidity for 2014, were cash from operations, proceeds from our settlement of the SPP lawsuit and the subsequent sale of SPP Class B units.

 

Cash flows from operations totaled $69.1 million, $11.2 million and $19.6 million for the years ended December 31, 2012, 2013 and 2014, respectively. The increase from 2013 to 2014 is due to higher revenues, realized gains on our SPP investment, and non-cash interest on the mandatorily redeemable preferred stock.  These increases were offset by higher unrealized gains on derivative contracts compared to 2013. The decrease from 2012 to 2013 is mainly due to the significant reduction in realized cash from derivative contracts in 2013 compared to 2012.

 

Cash flows from investing activities have historically been driven by exploration and development costs, leasehold acquisitions, acquisitions of businesses and sales of oil and gas properties. Net cash used in investing activities was $49.7 million and $10.5 million for the years ended December 31, 2013 and 2014, respectively, compared to net cash received of $35.6 million for the year ended December 31, 2012. Cash used in investing activities in 2014 was primarily $33.0 million in capital expenditures offset by proceeds from the sale of our SPP investment of $21.8 million. Cash used in investing activities in 2013 was largely a result of $52.3 million of capital expenditures. Cash from investing activities in 2012 was the result of $53.4 million in gross proceeds from the KPC sale partially offset by $16.8 million of capital expenditures and $1.5 million set aside as restricted cash prior to our transitioning outstanding letters of credit to our new credit facility.

 

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The following table sets forth our capital expenditures, including costs we have incurred but not paid for the periods presented:

 

 

 

Cash flows from financing activities have historically been driven by borrowing and repayments on debt instruments, issuances of equity and the costs associated with these activities. Cash used in financing activities was $104.6 million and $9.1 million for the years ended December 31, 2012 and 2014, respectively, while cash from financing activities was $37.9 million for the year ended December 31, 2013. The cash used in financing activities in 2014 was primarily due to $9.0 million in net repayments of debt. The cash from financing activities in 2013 was from borrowings from our Borrowing Base Facility and from issuance of $4.1 million of our common stock under our at-the-market sales agreement.  The cash used in 2012 was primarily for debt repayments of $193.0 million to settle our prior credit facilities along with debt and equity issuance costs of $2.3 million. These outflows were partially offset by $57.5 million in proceeds from our Borrowing Base Facility, $32.5 million in proceeds from the issuance of common stock, preferred stock and warrants to White Deer, and $724,000 in proceeds from the issuance of common stock under our at-the-market program described below. 

 

KPC Sale

 

On September 28, 2012, we sold our interstate pipeline subsidiary KPC to MV for $53.5 million in cash, $53.4 million net of a working capital adjustment.

 

White Deer Investment

 

At December 31, 2014, White Deer holds $79.8 million in liquidation preference of our Series A Cumulative Redeemable Preferred Stock (the “Series A Preferred Stock”) along with warrants to purchase 3,301,249 shares of our common stock at a weighted average exercise price of $13.00 per share. In addition, White Deer also holds 23,098 shares of our Series B Voting Preferred Stock (the “Series B Preferred Stock”), each share entitled to 100 votes, and 4,307,238 shares of our common stock. Our issuance of equity to White Deer occurred in six transactions as disclosed below. The number of shares of common stock, warrants and exercise prices have been adjusted to reflect the reverse stock split.

 

•On September 21, 2010, we issued to White Deer $60 million initial liquidation preference of our Series A Preferred Stock along with 7 1/2 year warrants to purchase 1,904,762 shares of our common stock at an exercise price of $31.50 per share.

•On February 9, 2012, we issued to White Deer 218,024  shares of our common stock at $34.40 per share for an aggregate purchase price of $7.5 million.

 

•On August 1, 2012, we issued to White Deer 307,693  shares of our common stock at $19.50 per share, $6.0 million initial liquidation preference of our Series A Preferred Stock and warrants to purchase 307,693 shares of common stock at an exercise price of $19.50 per share. Total proceeds from the issuance were $12.0 million.

 

•On December 20, 2012, we issued to White Deer 457,746  shares of our common stock at $14.20 per share, $6.5 million initial liquidation preference of our Series A Preferred Stock and warrants to purchase 457,746 shares of common stock at an exercise price of $14.20 per share. Total proceeds from the issuance were $13.0 million.

 

•On December 13, 2013, we issued to White Deer 112,398 shares of our common stock with a fair value of $1.5 million in exchange for the retirement of warrants exercisable for 2,224,135 shares of our common stock together with a like number of one one-hundredths of a share of Series B Voting preferred Stock that were issued as a unit with the warrants.

 

•    On October 9, 2014, we issued to White Deer 3,211,378 shares of our common stock in exchange for 2,175 shares of our Series A Cumulative Redeemable Preferred Stock with a liquidation preference of approximately $35.0 million.

 

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•    For additional details, see Note 12 in Part II, Item 8. “Financial Statements and Supplementary Data.”

 

The Series A Preferred Stock is entitled to a cumulative dividend of 12% per year on its liquidation preference, compounded quarterly. Prior to June 30, 2016, we can elect to pay dividends on the Series A Preferred Stock in cash. During this period, if such dividends are not paid in cash, the liquidation preference of the Series A Preferred Stock will increase by the amount of the dividend and we will issue additional warrants exercisable for a number of shares of our common stock equal to the amount of the dividend divided by, with respect to the Series A Preferred Stock issued in September 2010, the closing price of the common stock on the trading day prior to the dividend payment date or, with respect to the Series A Preferred Stock issued in August and December 2012, $19.50 and $14.20, respectively, with the exercise price of such warrants equal to such applicable price.

 

We have not paid cash dividends since White Deer’s initial investment in September 2010, but instead have chosen to increase the liquidation preference on the Series A Preferred Stock by $42.3 million, the cumulative amount of accrued dividends through December 31, 2014. Excluding the warrants retired in the Warrant Exchange, as a result of paying dividends in kind since the initial investment, we have also issued warrants to purchase 2,535,810 shares of our common stock at a weighted average exercise price of $11.99 per share. We are required to redeem the Series A Preferred Stock on March 21, 2018, at 100% of the liquidation preference. See Note 12 in Part II, Item 8 of this Annual Report for further details on the securities issued as a result of White Deer’s investment.

 

Credit Agreement

 

On December 20, 2012, we completed a refinancing of our existing revolving credit facility with a new group of banks. The refinancing was structured as an amendment to the existing facility to minimize costs. At refinancing, the existing facility was amended and restated by the Third Amended and Restated Credit Agreement (the “Borrowing Base Facility”). The Borrowing Base Facility, which is currently our sole credit facility, is a $200 million senior secured revolving facility secured by a first lien on substantially all of our assets except the assets of Constellation Energy Partners Management, LLC, one of our consolidated subsidiaries. See Note 10 in Part II, Item 8. in this Annual Report on Form 10-K for a summary of the material terms of this facility.

 

At December 31, 2014, the borrowing base under the Borrowing Base Facility was $115.0 million with outstanding borrowings of $83.0 million and $1.4 million in outstanding letters of credit. We had $30.6 million available under the Borrowing Base Facility at that date.

 

Sources of Liquidity in 2014 and Capital Requirements

 

We rely on our cash flows from operating activities as a source of internally generated liquidity. In 2014 we were able to fund the majority of our capital expenditures through the sale of our investment in SPP and operating cash flows as we were able to pay down debt by $9.0 million during 2014. Our long-term ability to generate liquidity internally depends in part on our ability to hedge future production at attractive prices as well as our ability to control operating expenses. We generated cash of $73.6 million from settlements of our oil and gas derivatives during 2012 while we owed cash of $2.3 million and $3.9 million in 2013 and 2014, respectively. The cash we generated in 2012 includes $30.2 million from the early exit of above market natural gas swap contracts originally scheduled to settle in 2013. These contracts were settled early in connection with our debt refinancing in 2012. Our natural gas contracts that settled in 2010 through 2012 were entered into prior to 2010 and were priced in the range of $6.26 to $7.28 per MMBtu. We have natural gas and crude oil swap contracts covering a portion of our production in 2015 and 2016. At March 2, 2015, our outstanding natural gas swaps have a weighted average price of $4.01 per MMBtu while our open crude oil swaps have a weighted average price between $92.73 per barrel. Our outstanding contracts are disclosed below under Commodity Price Risk.

 

From time to time, we may issue equity to fund certain transactions, such as our SPP investment, to repay outstanding debt and for working capital purposes. As discussed above, we issued additional equity to White Deer on three separate occasions in 2012 for gross proceeds of $32.5 million. Additionally, in February 2015 we sold 224,850 Class B units of SPP for approximately $290,000.

 

We have an effective $100 million universal shelf registration statement on Form S-3. We are initially limited to selling debt or equity securities under the shelf registration statement in one or more offerings over a 12 consecutive month period for a total initial public offering price not exceeding one third of our public equity float. The registration statement is intended to give us the flexibility to sell securities if and when market conditions and circumstances warrant, to provide funding for growth or other strategic initiatives, for debt reduction or refinancing and for other general corporate purposes. The actual amount and type of securities or combination of securities and the terms of those securities will be determined at the time of sale, if such sale occurs. If and when a particular series of securities is offered, the prospectus supplement relating to that offering will set forth our intended use of the net proceeds. In addition, we have entered into an at-the-market issuance sales agreement with a sales agent relating to the offering from time to time of shares of our common stock under the shelf registration statement. Sales of shares of our common stock, if any, may be made directly on the NASDAQ Global Market, on any other existing trading market for the common stock or through a market maker, or in privately negotiated transactions, subject to our approval. Our sales agreement is limited to the sale of up to a number of shares of common

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stock with an initial offering price not to exceed the amount that can be sold under the registration statement. In 2013, we sold 259,232 shares of common stock under the program for $4.0 million, net of $115,000 in agent commissions. There were no sales of common stock in 2014. On February 10, 2015 we filed a prospectus supplement relating to the issuance and sale of shares of our common stock from time to time having an aggregate offering price of up to $3.8 million. As of early March 2015, we sold an additional 28,416 shares of our common stock for approximately $133,000 net proceeds.

 

We rely on our Borrowing Base Facility as an external source of long and short-term liquidity. At March 2, 2015, we had $83.5 million of outstanding borrowings and $31.5 million of availability under this facility. The borrowing base under our Borrowing Base Facility will be redetermined April 30, 2015, based on reserves at December 31, 2014. The borrowing base under that facility is determined based on the value of our oil and natural gas reserves at our lenders’ forward price forecasts, which are generally derived from futures prices. As a result of declining natural gas and crude oil prices we expect a decrease in our current borrowing base which will be redetermined April 30, 2015. We do not expect our borrowing base reduction to be below debt outstanding. With the current availability under our Borrowing Base Facility and expected cash flows from operations, we believe that we have sufficient liquidity to fund our capital expenditures and financial obligations through 2015. 

 

Contractual Obligations

 

We have certain contractual commitments in the ordinary course of business, including debt service requirements, purchase obligations and operating lease commitments. The following table summarizes these commitments at December 31, 2014:

 

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(1) Interest due by period is an estimate as the credit facility has variable interest rate.

 

Off-Balance Sheet Arrangements

 

At December 31, 2014, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not exposed to any financing, liquidity, market, or credit risk that could arise if we had engaged in such activities.

 

Critical Accounting Policies

 

The preparation of our consolidated financial statements requires us to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and various other assumptions that we believe are reasonable; however, actual results may differ. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements.

 

Oil and Gas Reserves

 

Our most significant financial estimates are based on estimates of proved oil and gas reserves. Proved reserves represent estimated quantities of oil and gas 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. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production, and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering, and production data and, the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geologic interpretation, and judgment. In addition, as a result of changing market conditions, commodity prices and future development costs will change from year to year, causing estimates of proved

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reserves to also change. Estimates of proved reserves are key components of our most significant financial estimates involving our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. Our reserves are estimated on an annual basis by independent petroleum engineers.

 

Oil and Natural Gas Properties

 

The method of accounting for oil and gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for oil and natural gas properties. Under the full cost method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our oil and gas properties are capitalized.

 

Oil and gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved oil and gas reserves. Estimation of proved oil and gas reserves relies on professional judgment and the use of factors that cannot be precisely determined. Holding all other factors constant, if proved oil and gas reserves were revised upward or downward, earnings would increase or decrease, respectively. Subsequent proved reserve estimates that are materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of oil and gas properties unless the sale or disposition would have a significant impact on the depreciation, depletion, and amortization rate.

 

Under the full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). Future net revenues used to calculate the ceiling do not include cash outflows associated with settling asset retirement obligations. We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion, and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of our full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion, and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases during a period when oil or gas prices are depressed. In addition, a write-down may occur if estimates of proved reserves are substantially reduced or estimates of future development costs increase significantly.

 

Because of the volatile nature of oil and gas prices, it generally is not possible to predict the timing or magnitude of full cost ceiling write-downs. In addition, due to the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.

 

Although the uncertainty of future prices impact the ability to predict future full cost ceiling write-downs, we do currently expect to recognize such full cost write-downs in the first half of 2015. This expectation is based on the lower prices for the last half of 2014 and the short-term pricing outlook. Although we can predict with relative certainty we will recognize full cost ceiling write-downs in 2015, we are not able to reasonably estimate the amounts. However, the amounts may be material to our net earnings but will have no impact on our cash flow or liquidity.

 

Unevaluated Properties

 

The costs directly associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the amortization base.

 

Future Abandonment Costs

 

We have significant legal obligations to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed, or developed. Liabilities for asset retirement obligations are recorded at fair value in the period incurred. Upon initial

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recognition of the asset retirement liability, the asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. Asset retirement costs included in the carrying amount of the related asset are subsequently allocated to expense as part of our depletion calculation. Additionally, increases in the discounted asset retirement liability resulting from the passage of time are recorded as depreciation expense.

 

Estimating the future asset retirement liability requires us to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. We use the present value of estimated cash flows related to our asset retirement obligations to determine the fair value. Present value calculations inherently incorporate numerous assumptions and judgments. These include the ultimate retirement and restoration costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement liability, a corresponding adjustment will be made to the carrying cost of the related asset. There were no significant revisions for the years ended December 31, 2013 and 2014.

 

We have not recorded any asset retirement obligations relating to our gathering systems at December 31, 2013 and 2014 because we do not have any legal or constructive obligations relative to asset retirements of the gathering systems (see discussion in Note 9—Asset Retirement Obligations to the consolidated financial statements included in this Annual Report on Form 10-K).

 

Derivative Instruments

 

Due to the historical volatility of oil and gas prices, we have implemented a hedging strategy aimed at reducing the variability of prices we receive for our production. Currently, we may use collars, fixed-price swaps and fixed price sales contracts as our mechanism for hedging commodity prices. Our current derivative instruments are not accounted for as hedges for accounting purposes in accordance with FASB ASC 815 Derivatives and Hedging. As a result, we account for our derivative instruments on a mark-to-market basis, and changes in the fair value of derivative instruments are recognized as gains and losses which are included in other income and expense in the period of change. While we believe that the stabilization of prices and production afforded us by providing a revenue floor for our production is beneficial, this strategy may result in lower revenues than we would have if we were not a party to derivative instruments in times of rising natural gas prices. For the year ended December 31, 2014, we recognized a total gain on derivative financial instruments in the amount of $16.3 million, consisting of a $3.9 million realized loss and a $20.3 million unrealized gain. We currently estimate the fair value of our commodity swaps with a discounted cash flow model utilizing, when possible, published forward commodity price curves and credit adjusted discount rates.

 

Income Taxes

 

We record our income taxes using an asset and liability approach in accordance with the provisions of FASB ASC 740 Income Taxes. We recognize deferred tax assets and liabilities for the expected future tax consequences of temporary differences (primarily property and equipment and the net operating loss carry forward) between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under FASB ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. At December 31, 2013 and 2014, a full valuation allowance was recorded against our deferred tax assets. 

We have net operating loss (“NOL”) carryforwards that are available to reduce our U.S. taxable future income. Our ability to utilize NOL carryforwards to reduce our future federal taxable income and federal income tax is subject to various limitations under Internal Revenue Code (“IRC”) Section 382. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of our stock during any three year period resulting in an aggregate change of more than 50% in the beneficial ownership of our Company. We experienced ownership changes within the meaning of IRC Section 382 on November 14, 2005, March 5, 2010, and September 21, 2010 and are therefore subject to IRC Section 382 limitations on our NOL carryforwards. See Note 11 in Part II, Item 8. of this Annual Report on Form 10-K for further discussion of these limitations.

 

FASB ASC 740 provides guidance on the measurement of the income tax benefit associated with uncertain tax positions, derecognition, classification, interest and penalties and financial statement disclosure. We regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold condition prescribed under FASB ASC 740. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. We accrue interest and penalties related to uncertain tax positions as income tax expense.

 

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Recent Accounting Pronouncements Not Yet Adopted

 

Recent accounting pronouncements relevant to us are discussed within Note 2 in Part II, Item 8. of this Annual Report on Form 10-K. There have been no recent accounting pronouncements that have had a material impact on our consolidated financial statements in the current year. There are two new accounting standards we will be required to adopt in the future that will have a impact on our consolidated financial statements, Accounting Standards Update “ASU” No. 2014-09, Revenue from Contracts with Customers and ASU No. 2014-15 Financial Presentation – Going concern, both updates are effective on January 1, 2017.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. 

 

The discussion in this section provides information about the financial instruments we use to manage commodity price and interest rate volatility. All contracts are financial contracts, which are settled in cash and do not require the actual delivery of a commodity quantity to satisfy settlement.

 

Commodity Price Risk

 

Our most significant market risk relates to the prices we receive for our oil and natural gas production. For example, NYMEX-WTI oil prices during 2014 ranged from a high of $107.26 per barrel to a low of $53.27 per barrel. Meanwhile, NYMEX natural gas futures prices during 2014 ranged from a high of $6.15 per MMBtu to a low of $2.89 per MMBtu. In light of the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements aimed at reducing the variability of the prices we receive for our production.

 

We have used, and may continue to use, a variety of commodity-based derivative financial instruments, including collars, fixed-price swaps and basis protection swaps. Our fixed price swap transactions are settled based upon NYMEX pricing. Natural gas prices at our primary delivery point in the Cherokee Basin are based on the Southern Star index, which is typically at a discount to the NYMEX pricing at Henry Hub. Settlement for our gas derivative contracts typically occurs in advance of our purchaser receipts.

 

While we believe that the oil and gas price derivative arrangements we enter into are important to our program to manage price variability for our production, we have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in prices. Both realized and unrealized gains and losses from settlements of or changes in fair values of our derivative contracts are currently recognized in other income (expense) as they occur. As a result, our current period earnings may be significantly affected by changes in fair value of our commodity derivative contracts. Changes in fair value are principally measured based on period-end forward prices compared to the contract price.

 

Gains and losses associated with derivative financial instruments related to gas and oil production were as follows for the years indicated.

 

 

The following table summarizes the estimated volumes, fixed prices and fair value attributable to all oil and natural gas derivative contracts at December 31, 2014.

 

 

Interest Rate Risk

 

Although none are currently outstanding, from time to time we may enter into interest rate derivatives to mitigate our exposure to fluctuations in interest rates on variable-rate debt. At December 31, 2014, we had outstanding $83.0  million of variable-rate debt. A 1% increase in our interest rates would increase gross interest expense approximately $830,000 per year.

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. 

 

Please see the accompanying consolidated financial statements and related notes thereto beginning on page F-1.

 

ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 

 

Not applicable.

 

ITEM 9A. CONTROLS AND PROCEDURES 

 

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

 

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and that such information is accumulated and communicated to management, including the principal executive officer and the principal financial officer, to allow timely decisions regarding required disclosures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

 

In connection with the preparation of this Annual Report on Form 10-K, our management, under the supervision and with the participation of our principal executive officer (who also currently serves as our principal financial officer), conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2014. Based on that evaluation, such officer concluded that, as of December 31, 2014, our disclosure controls and procedures were not effective due to the material weakness described in "Management's Report on Internal Control Over Financial Reporting."

 

Management’s Annual Report on Internal Control over Financial Reporting 

 

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes those policies and procedures that (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets, (b) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, (c) provide reasonable assurance that receipts and expenditures are being made only in accordance with appropriate authorization of management and the board of directors, and (d) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.

 

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Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of these limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

 

Our management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on the evaluation performed, we concluded that our internal control over financial reporting as of December 31, 2014, was not effective based on the material weakness described in the paragraph below.

 

Management has concluded that, as of December 31, 2014, our controls over the accounting for non-routine transactions of a complex nature did not operate effectively. Specifically, during the operation of controls designed to properly account for non-routine, complex transactions, we failed to timely detect the misinterpretation of generally accepted accounting principles surrounding the classification of mandatorily redeemable preferred stock. Accordingly, we did not appropriately classify such financial instrument in our consolidated balance sheet from its issuance in September 2010 through September 2014. This control deficiency resulted in a material understatement of our long-term liabilities and interest expense in our consolidated financial statements and related consolidated financial information for such periods. Accordingly, management has determined that this control deficiency constitutes a material weakness in our internal controls over financial reporting.

 

This error was subsequently identified and corrected with restated consolidated financial statements and related consolidated financial information in this Annual Report on Form 10-K, including (i) audited restated consolidated financial statements as of December 31, 2013 and for the years ended December 31, 2012 and 2013, (ii) unaudited restated condensed financial information for each of the quarterly periods in the year ended December 31, 2013, and for the quarterly periods ended March 31, 2014, June 30, 2014 and September 30, 2014, (iii) restated selected financial data as of December 31, 2010, 2011 and 2012 and for the years ended December 31, 2010 and 2011; (iv) footnotes reconciling previously filed annual and quarterly financial information to the restated financial information and (v) MD&A based on the restated annual financial statements specified in (i).

 

Remedial Actions

 

We have developed certain remediation steps to address the material weakness discussed above and to improve our internal control over financial reporting. We and our Board of Directors take the controls and integrity of our financial statements seriously and believe that the remediation steps described below are essential to addressing the material weakness and maintaining a strong internal control environment:

 

 

We believe the foregoing efforts, once fully implemented, will remediate the material weakness identified above and will enhance the overall effectiveness of our internal control over financial reporting, as well as our disclosure controls and procedures. Upon completion of our testing of the design and operating effectiveness of these newly implemented control procedures, management believes it will remediate such material weakness in 2015. Management remains committed to the rigorous enforcement of an effective control environment.

 

Changes in Internal Control over Financial Reporting

 

There was no change in our internal control over financial reporting that occurred during the fourth quarter of 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. As discussed in the “Remedial Actions” section above, during the first quarter of 2015, we have begun implementing new controls designed to remediate the material weakness described above.

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Auditor Attestation Report

 

This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting due to an exemption provided by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) enacted into law in July 2010. The Dodd-Frank Act provides smaller public companies and debt-only issuers with a permanent exemption from the requirement to obtain an external audit on the effectiveness of internal financial reporting controls provided in Section 404(b) of the Sarbanes-Oxley Act. PostRock is a smaller reporting company and is eligible for this exemption under the Dodd-Frank Act.

 

ITEM 9B. OTHER INFORMATION 

 

None.

PART III

 

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

 

Information required by Part III, Item 10. is incorporated by reference to our definitive proxy statement which is to be filed with the Securities Exchange Commission no later than 120 days after the end of our fiscal year pursuant to the Securities Exchange Act of 1934, as amended.

 

ITEM 11.EXECUTIVE COMPENSATION 

 

Information required by Part III, Item 11. is incorporated by reference to our definitive proxy statement which is to be filed with the Securities Exchange Commission no later than 120 days after the end of our fiscal year pursuant to the Securities Exchange Act of 1934, as amended.

 

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

 

Information required by Part III, Item 12. is incorporated by reference to our definitive proxy statement which is to be filed with the Securities Exchange Commission no later than 120 days after the end of our fiscal year pursuant to the Securities Exchange Act of 1934, as amended.

 

 

 

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 

Information required by Part III, Item 13. is incorporated by reference to our definitive proxy statement which is to be filed with the Securities Exchange Commission no later than 120 days after the end of our fiscal year pursuant to the Securities Exchange Act of 1934, as amended.

 

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES 

 

Information required by Part III, Item 14. is incorporated by reference to our definitive proxy statement which is to be filed with the Securities Exchange Commission no later than 120 days after the end of our fiscal year pursuant to the Securities Exchange Act of 1934, as amended.

 

PART IV

 

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES 

 

(a)(1) and (2) Financial Statements See “Index to Financial Statements” set forth on page F-1 of this Annual Report on Form 10-K.

 

(a)(3) Index to Exhibits Exhibits requiring attachment pursuant to Item 601 of Regulation S-K are listed in the Index to Exhibits to this Annual Report on Form 10-K that is incorporated herein by reference.