rexx-10k_20171231.htm

Large Accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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 Section 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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes ☒ No ☐

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2017 was $46,993,210. This amount is based on the closing price of the registrant’s common stock on The Nasdaq Capital Market, the exchange on which the common stock traded as of June 30, 2017, on that date. Shares of common stock beneficially held by executive officers and directors of the registrant are not included in the computation. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

Portions of the registrant’s definitive proxy statement for its 2017 Annual Meeting of Stockholders to be held in May 2018, are incorporated by reference herein in Items 10, 11, 12, 13 and 14 of Part III of this report.

Unless otherwise indicated, all references to “Rex Energy Corporation,” “the Company,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries. Natural gas is converted throughout this report at a rate of six Mcf of gas to one barrel of oil equivalent (“BOE”). Natural Gas Liquids (“NGLs”) are converted throughout this report at a rate of one barrel of NGLs to one BOE. The ratios of six Mcf of gas to one BOE and one barrel of NGLs to one BOE do not assume price equivalency and, given price differentials, the price for a BOE of natural gas or NGLs may differ significantly from the price of a barrel of oil.

If you are not familiar with the oil and gas terms or abbreviations used in this report, please refer to the definitions of these terms and abbreviations under the caption “Glossary” at the end of “Item 15. Exhibits and Financial Statement Schedules” of this report.

Some of the information, including all of the estimates and assumptions, in this report contain forward-looking statements within the meaning of Sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans, objectives of management for future operations, legal strategies, and legal proceedings, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may”, “will”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among others, the following:

Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

The following discussion and the other information provided in this report should be read in conjunction with our audited consolidated financial statements and notes thereto appearing elsewhere in this report, which have been prepared assuming that we will continue as a going concern.

We are an independent natural gas, natural gas liquid (“NGL”) and condensate company operating in the Appalachian Basin. We are focused on drilling and exploration activities in the Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.

We are headquartered in State College, Pennsylvania and have a regional office in Cranberry, Pennsylvania.

We were incorporated in the state of Delaware on March 8, 2007. Our common stock previously traded on The Nasdaq Capital Market under the symbol “REXX”. On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department of Nasdaq indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we requested an appeal before the Nasdaq Hearings Panel. We did not appeal this determination and the time period in which to appeal has lapsed. Following the delisting of our common stock from Nasdaq, our common stock may be eligible for quotation on the OTCBB or OTC Markets Group’s Pink marketplace. Trading on the OTCBB or Pink marketplace may occur only if a market maker applies to quote our common stock and we are current in our reporting obligations under the Securities Exchange Act of 1934. Once our common stock is delisted from Nasdaq, there can be no assurance that a market maker will apply to quote our common stock or that our common stock then will be eligible for quotation on the OTCBB or the Pink marketplace.

The information set forth in this report is exclusive of our discontinued operations related to the DJ Basin, for which the related assets were sold in 2012 and 2013, Water Solutions Holdings, LLC and its subsidiaries (“Water Solutions”), which were sold in July 2015, and the Illinois Basin, for which the related assets were sold in August 2016, unless otherwise noted. These operations are classified as Discontinued Operations on our Consolidated Statements of Operations and Assets Held for Sale on our Consolidated Balance Sheets. Our estimated proved reserves account for the sale of our Illinois Basin assets in August 2016 have not been retroactively restated to remove the associated estimated proved reserves from prior year balances.

At December 31, 2017, our estimated proved reserves had the following characteristics:

At December 31, 2017, we owned an interest in approximately 554.0 condensate, NGL and natural gas wells. For the quarter ended December 31, 2017, we produced an average of 205.3 net MMcfe per day, composed of approximately 60.1% natural gas, 1.9% condensate and 38.0% NGLs.

In the Appalachian Basin during 2017, we averaged net production of approximately 184.5 MMcfe per day of natural gas, NGLs and condensate. As of December 31, 2017, including both developed and undeveloped acreage, we controlled approximately 171,400 gross (117,700 net) acres in Pennsylvania that we believe are prospective for Marcellus Shale exploration and 132,100 gross (105,100 net) acres in Pennsylvania that we believe are prospective for Burkett Shale exploration. In addition, as of December 31, 2017, we controlled approximately 165,300 gross (128,400 net) acres, which includes both developed and undeveloped acreage, in Pennsylvania and Ohio that we believe are prospective for Utica Shale exploration.

Our total revenue from continuing operations for the year ended December 31, 2017 was $205.3 million, which was primarily derived from the sale of natural gas, NGLs and condensate.

For the year ended December 31, 2017 , we drilled 28.0 gross (20.5 net) wells. We placed into sales 26.0 gross (15.2 net) wells and ended the year with 11.0 gross (8.0 net) wells in inventory that are awaiting completion.

The following table sets forth selected data concerning our continuing operations for production, estimated proved reserves and undeveloped acreage for the periods indicated:

We believe our strengths provide us with significant competitive advantages and position us to successfully execute our business and growth strategies.

High Quality Asset Base with Liquids-Weighted Growth. We are focused on developing acreage that we believe to be prospective for three producing zones, the Marcellus Shale, the Burkett Shale and the Utica Shale. A substantial portion of our acreage holdings are in liquids-rich areas that we believe are prospective for NGL and condensate production. As of December 31, 2017, our holdings believed to be prospective for liquids-rich production accounted for approximately 83.2% of our total net acreage.

Track Record of Production Growth. Our management and operations teams have a proven track record of performance and have consistently demonstrated our ability to acquire and develop reserves at attractive costs in the basins in which we operate. Our production has grown at a CAGR of 31.9% between 2010 and 2017. We believe we have competitive finding and development costs as compared to our industry peers.

Significant Operational Control in Our Core Areas. As a result of successfully executing our strategy of acquiring concentrated acreage positions and operating properties with a high working interest, we currently operate and manage approximately 70.0% of our net acreage. Our high percentage of operated properties enables us to exercise a significant level of control with respect to the timing and scope of drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas.

History of Maximizing Operating Efficiencies. Our costs of operations continue to decrease year-over-year as we leverage our increasing production, pricing concessions from service providers and our expertise in the regions in which we operate. Our field level lease operating expense per Mcfe, which excludes the effect of transporting, marketing and processing, has decreased from $0.15 per Mcfe in 2015 to $0.12 per Mcfe in 2016 and $0.11 per Mcfe in 2017. Our general and administrative expense per Mcfe has decreased from $0.40 per Mcfe in 2015 to $0.28 per Mcfe in 2016 and $0.27 per Mcfe in 2017.

Our goal is to build long-term stockholder value by growing reserves and production in a cost-effective manner. Key elements of our strategy include:

Develop Our Existing Properties. Our core leasehold consists entirely of interests in developed and undeveloped natural gas, NGL and condensate resources located in the Appalachian Basin. We pursue an active, technology-driven drilling program to develop and maximize the value of our existing acreage. We actively allocate capital in an effort to maximize value and estimated proved reserve growth based on our assessment of the relative risk of development and the economics of potential projects. Additionally, by concentrating our drilling and producing activities in our core areas, we are able to develop the regional expertise needed to interpret specific geological and operating trends and develop economies of scale in our operations. Our areas of focus include:

Employ Technological Expertise. We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling success rate of approximately 100.0% over the last three years, to improve operations and to enhance field recoveries. We intend to continue to apply this expertise to our proved reserve base and our development projects.

Reduce Per Unit Operating Costs Through Economies of Scale and Efficient Operations. As we continue to increase our production and develop our existing properties, we believe that our per unit production costs can benefit from leveraging our existing infrastructure and expertise over a larger number of wells. Our acreage positions are tightly concentrated, which we believe will enable us to achieve greater cost efficiencies in our drilling and completion operations than those of our competitors who have less consolidated positions. As we continue to develop our acreage positions, we expect to realize increased capital efficiencies through greater utilization of multi-well pads and existing infrastructure and facilities.

Maintain Capital Budgeting Flexibility. Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs.

Manage Commodity Price Exposure Through an Active Hedging Program. We actively hedge our future exposure to commodity price fluctuations by entering into natural gas, NGL and oil derivative contracts. This strategy is designed to provide us with stability in our cash flows to support our on-going capital requirements.

Our budgeted capital spending for 2018 is approximately $78.0 million to $83.0 million. The capital budget contemplates the drilling of approximately seven gross (4.5 net) horizontal Marcellus Shale wells in Butler County, Pennsylvania. We have plans to complete 11.0 gross (8.5 net) horizontal Marcellus Shale wells in Butler County, Pennsylvania and seven gross (five net) horizontal Utica Shale wells in Carroll County, Ohio. In the event our cash flows are materially less than anticipated and/or other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. The following table summarizes our actual 2017 and our budgeted 2018 capital expenditures:

The following table sets forth information regarding condensate, NGL and gas production and revenues from continuing operations for the last three years:

The oil and gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise and our financial resources. We must compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment and services necessary for drilling and completion of wells. Consequently, equipment and services may be in short supply

from time to time. Additionally, it can be difficult to attract and retain employees, particularly those with expertise in high demand areas.

As of December 31, 2017, we had 105 full-time employees, 17 of whom were field personnel. No employees are represented by a labor union or covered by any collective bargaining arrangement. We believe that our relations with our employees are good. We regularly utilize independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field services, oil and gas leasing and on-site production operation services.

Our natural gas producing properties are located near existing pipeline systems and processing infrastructure. We have firm commitments for the sale of approximately 110,000 gross MMBTU per day in our Butler County, Pennsylvania operating area for our working interest and that of our working interest partners as of December 31, 2017. Additionally in Butler County, Pennsylvania, we have firm processing commitments with unaffiliated third parties for our liquids-rich gas totaling 285,000 gross MMBTU per day as of December 31, 2017. In Ohio, we have a marketing agreement in place with BP Energy for 14,000 MMBtu per day. In addition to our marketing and processing agreements, we have several transportation agreements in the Appalachian Basin totaling commitments of approximately 263,000 gross MMBTU per day in 2018; 263,000 gross MMBTU per day in 2019; 245,000 gross MMBTU per day in 2020; 191,000 gross MMBTU per day in 2021; and 191,000 gross MMBTU per day in 2022.

In addition to our natural gas transportation and sales agreements, we also have agreements in place to transport and sell our ethane production. We began selling ethane via the ATEX and Mariner West pipelines during 2014. The initial term of the ATEX pipeline agreement expires 15 years from the date that we began to deliver ethane to the ATEX pipeline, with us retaining a unilateral right to extend the initial term for successive periods of not less than one or more than five years so long as the shippers on the ATEX pipeline continue to ship an aggregate of 50,000 barrels per day of ethane. The initial term of the Mariner West pipeline agreement expires on December 31, 2028, but the agreement will automatically extend for successive one year terms thereafter until such time as either party gives 12 months’ notice of intent to terminate. In December 2015, we executed an additional NGL supply agreement INEOS Europe AG for ethane, propane and butane on the Mariner East pipeline. The ethane sales commenced in April 2016 and the propane and butane sales are expected to begin in the first quarter of 2018. The term of the agreement is 10 years and will extend automatically for one year terms thereafter until such time that either party provides twelve months’ notice of intent to terminate.

Prices for natural gas and oil fluctuate widely based on, among other things, supply and demand. Supply and demand are influenced by a number of factors, including weather, foreign policy, industry practices and the U.S. and worldwide economic climate. Natural gas and oil markets have historically been cyclical and volatile in nature as a result of many factors that are beyond our control. There can be no assurance of any price at which we will be able to sell our natural gas and condensate. Prices may be relatively low when our wells are most productive, thereby reducing overall returns.

We enter into derivative transactions with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas and oil prices. For a more detailed discussion, see the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

Our oil and natural gas exploration, production, and related operations are subject to extensive statutory and regulatory oversight by federal, state, tribal and local authorities. We must, for example, obtain drilling permits; post bonds for drilling; operating, and reclamation; and submit various reports. The following activities are also subject to regulation: the location of wells; the method of drilling; completion and operation of wells; secondary and enhanced oil recovery projects; notice to surface owners and third parties; the surface development, use, and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; temporary storage tank operations; compression and access roads; the impoundment of water; the manner and extent of earth disturbances; air emissions; the disposal of fluids used in connection with operations; and the calculation and distribution of royalty payments and production taxes. We must also comply with statutes and regulations addressing conservation matters, including the size of drilling units, spacing units, or proration units; the number of wells that may be drilled in an area; the unitization or pooling of oil and natural gas properties; and the establishment of maximum rates of production. Failure to comply with any of these requirements can result in substantial monetary penalties or lease cancellation and, in certain cases, criminal prosecution. Finally, if tribal or local authorities have previously imposed moratoria or other restrictions on exploration and production activities those restrictions must be

addressed before activities can proceed. Moreover, most states impose a production, ad valorem, or severance tax with respect to production and sale of oil or natural gas within their jurisdiction.

The increasing regulatory burden on the natural gas and oil industry will most likely increase our cost of doing business and may affect our production rates. However, these burdens generally do not affect us differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities, and locations of production. Additional proposals or proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), and the courts. Implementation of such proposals could increase the regulatory burden and potential for financial sanctions for non-compliance. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. We may be required to make significant expenditures to comply with governmental laws and regulations, which could have a material adverse effect on our business, financial condition, and results of operations.

Historically, the transportation and sale or resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (“NGPA”), and the regulations promulgated thereunder by the FERC. In the past, the federal government has regulated the prices at which natural gas and oil could be sold. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted, removing both price and non-price controls from natural gas sold in “first sales” no later than January 1, 1993. While sales by producers of natural gas, and all sales of natural gas liquids, condensate, and crude oil currently can be made at uncontrolled market prices, Congress could reenact price controls in the future.

The FERC regulates interstate natural gas transportation rates and service conditions. Its regulations affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980s, the FERC has issued a series of orders (collectively, “Order 636”) which significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other services such pipelines previously performed. One of the FERC’s purposes in issuing Order 636 was to increase competition within the natural gas industry. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services, and has substantially increased competition and volatility in natural gas markets.

The price we receive from the sale of oil and NGLs will be affected by the cost of transporting products to markets. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, index such rates to inflation, subject to certain conditions and limitations. We are unable to predict the effect, if any, of these regulations on our intended operations. The regulations may, however, increase transportation costs or reduce well head prices for NGLs and oil.

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, the EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme, or artifice to defraud; to make any untrue statement of material fact or omit any such statement necessary to make the statements not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to the FERC’s jurisdiction, which includes the reporting requirements under Order Nos. 704 and 720. It therefore, reflects a significant expansion of the FERC’s enforcement authority. We have not been affected differently than any other producer of natural gas by this act.

Our operations and properties are subject to extensive and changing federal, state, and local laws and regulations relating to environmental protection. These laws and regulations among other things:

The permits required for our operations may be subject to revocation, modification, and renewal by the issuing authorities. Governmental authorities have the power to enforce environmental laws and regulations, and violations may result in administrative or civil penalties, injunctions, or even criminal penalties. Some states continue to adopt new regulations and permit requirements, which may impede or delay our operations or increase our costs. We believe that we are in substantial compliance with current applicable environmental laws and regulations and, except for those matters described in “Item 3. Legal Proceedings,” have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, the trend in environmental legislation and regulation generally is toward stricter standards, and we expect that this trend will continue. Changes in existing environmental laws and regulations or in interpretations of these laws and regulations could have a significant impact on us and the natural gas and oil industry as a whole.

The following is a summary of the existing laws and regulations that we believe are most likely to have a material impact on our business operations.

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the Federal Environmental Protection Agency (“EPA”), the individual states administer some or all of the provisions of RCRA, as the case may be, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration and production of natural gas and crude oil are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as “hazardous” wastes in the future. Along these lines, on December 28, 2016, a federal trial court issued a consent decree under which the EPA agreed that, by March 15, 2019, it will either sign a notice of proposed rulemaking to revise its RCRA regulations as they pertain to oil and gas wastes (in which case it will take a final action on the proposed rulemaking by July 15, 2021) or sign a determination that no such revision is necessary. If oil and gas wastes were to become classified as “hazardous” under RCRA or comparable state statutes, it could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial condition.

The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended (“CERCLA”), and comparable state statutes impose strict liability on owners and operators of sites where “hazardous substances” have been released into the environment. They likewise impose strict liability on persons who disposed of or arranged for the disposal of “hazardous substances” that have been released into the environment. The definition of “hazardous substances” excludes “petroleum, including crude oil and any fraction thereof.” Nevertheless, non-excluded hazardous substances can be present at sites of oil and gas operations. Liability under CERCLA may be joint and several and includes liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.

We currently own, lease, or operate numerous properties that, for many years, have been used for natural gas and oil exploration and production operations or produced water disposal operations. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been disposed of or released on or under the properties that we own or lease or on or under other locations, including off-site locations, where these substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state

laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination or perform remedial activities to prevent the future spread of contamination.

The Federal Water Pollution Control Act (the “Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. While the Clean Water Act contains an oil and gas “exemption” to its requirement that a National Pollutant Discharge Elimination System permit be obtained for stormwater discharges, the exemption does not apply to certain types of stormwater discharges from oil and gas facilities (including those that have come into contact with wastes or other substances). Moreover, under the laws of some states, including Pennsylvania, operators of oil and gas facilities must obtain permit authorizations for stormwater discharges that emanate from the facilities regardless of whether the discharges are covered by the Clean Water Act’s exemption. The Clean Water Act, in addition, prohibits the unpermitted discharge of dredged or fill material into waters of the United States, including certain wetlands. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Our natural gas and oil exploration and production operations generate produced water as a waste material, Under the Clean Water Act, the EPA has issued rules that prohibit the discharge of oil and gas wastewaters directly to surface waters, or publicly-owned treatment works, unless the wastewaters have been treated to contain zero pollutants. Therefore, a common method of produced water disposal, and one that we use, is subsurface injection into disposal wells. Such disposal wells are permitted under the Underground Injection Control (“UIC”) program, which was established under the Safe Drinking Water Act (“SDWA”). The EPA directly administers the UIC program in some states and, in others, the States administer it on their own. To date, we believe that all necessary disposal well permits have been obtained and that the produced water has been discharged in substantial compliance with such permits and applicable laws and regulations.

The Endangered Species Act and comparable state laws restrict activities that could affect threatened and endangered species and their habitats. They do so through operating restrictions and temporary, seasonal, or permanent bans on certain types of activities in affected areas. We may conduct operations in areas where certain species that are listed as threatened or endangered are known to exist and where other species that might eventually be listed as threatened or endangered may exist. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations could cause us to incur new costs that would arise out of species protection measures. It could also limit our exploration and production activities in a way that could adversely impact our ability to develop and produce gas reserves. The same outcomes could occur if any portion of our gas-reserve acreage is designated as “critical” or “suitable” habitat areas for threatened or endangered species.

The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. The EPA issued New Source Performance Standards in 2012, which it amended in 2013 and 2014, known as “NSPS OOOO.” Among other things, NSPS OOOO requires operators of new and modified hydraulically-fractured gas wells to use special techniques (known as “green completions”) to reduce emissions of Volatile Organic Compounds (“VOCs”) from the wells. NSPS OOOO also revised the National Emission Standards for Hazardous Air Pollutants for glycol dehydration units. On May 12, 2016, the EPA issued additional New Source Performance Standards (effective August 2, 2016), known as “NSPS OOOOa,” which built on the NSPS OOOO standards by directly regulating methane and VOC emissions from various types of new and modified oil and gas sources. Some of those sources were already regulated under NSPS OOOO, while others, like pneumatic pumps, were covered for the first time. The EPA, however, is presently planning to reconsider OOOOa’s requirements for (i) monitoring for fugitive emissions (i.e., leaks), (ii) using professional engineers to certify closed vent systems, and (iii) pneumatic pumps that are used at well sites. It is also planning to stay or postpone the effective dates of those requirements while it reconsiders them. On February 23, 2018, moreover, the EPA amended OOOOa to remove certain requirements for sources of fugitive emissions to be repaired during unscheduled or emergency shutdowns.

Separately, on October 20, 2016, the EPA finalized Control Techniques Guidelines to reduce emissions from a number of existing (as opposed to new or modified) oil and gas sources that are located in certain ozone-sensitive areas, including Pennsylvania. These guidelines will lead to regulations that directly address VOC emissions and have the incidental effect of reducing methane emissions. The implementation deadline for the regulations is January 1, 2021. On March 2, 2018, however, the EPA proposed to withdraw the Control Techniques Guidelines.

Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations.

In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that under the Clean Air Act greenhouse gas emissions may be regulated as an “air pollutant.” In response to findings that emissions of carbon dioxide, methane, and other “greenhouse gases” present an endangerment to human health and the environment, the EPA, under the Clean Air Act, has adopted regulations that restrict emissions of greenhouse gases. The EPA has adopted regulations that, among other things, require a reduction in greenhouse gas emissions from motor vehicles and impose greenhouse gas emissions limitations on certain stationary sources. The EPA has also adopted regulations that require monitoring and reporting on GHG emissions from specified sources, including petroleum refineries and certain onshore oil and natural gas production facilities. As noted above, moreover, the EPA has finalized New Source Performance Standards that address VOC and methane emissions from the oil and gas industry.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly reporting, waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. For example, recent scientific studies have suggested that emissions of greenhouse gases, including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. While the U.S. Congress has, from time to time, considered climate change-related bills to reduce greenhouse gas emissions, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of states have passed laws, adopted regulations, or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although it is not possible at this time to predict whether or when the U.S. Congress may act on climate change legislation or how federal legislation may be reconciled with state and regional requirements, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas, NGLs, and oil that we produce.

In addition to federal laws and regulations, the various states where we operate have enacted their own environmental laws and regulations. As an example, in 2012, Pennsylvania enacted Act 13 (“Act 13”), which represented the first comprehensive legislation regarding the development of the Marcellus Shale in Pennsylvania. Act 13, among other things, (i) set stronger environmental standards, (ii) established impact fees, which are determined based on a multi-year fee schedule and the average sales prices of natural gas, (iii) increased the notice distance for unconventional well permit applications, (iv) extended certain setback distances for unconventional wells, and (v) increased the distance and duration of presumed well-operator liability for water pollution. In addition, Act 13 imposed spill prevention requirements applicable to well site construction, wastewater transportation, and gathering lines.

Act 13 has been the subject of multiple challenges in Pennsylvania courts. In 2013, the Pennsylvania Supreme Court, among other things, invalidated the portions of Act 13 providing for statewide gas and oil zoning and the Pennsylvania Department of Environmental Protection’s (“PaDEP”) issuance of waivers of setbacks from waterbodies. It also enjoined the enforcement of those setbacks. In 2016, the Pennsylvania Supreme Court, among other things, enjoined the enforcement of Act 13’s provisions that authorized the Pennsylvania Public Utility Commission to conduct validity reviews of local oil and gas-siting ordinances and established procedures for mounting court challenges to those ordinances. These decisions had the effect of giving local government in Pennsylvania more authority than they otherwise would have possessed to regulate where oil and gas operations may occur, which could make it more difficult to develop Marcellus Shale acreage in some municipalities. We cannot predict whether the portions of Act 13 that remain effective will be amended or replaced, or how or to what extent any additional rules or regulations adopted under Act 13 will affect our operations in Pennsylvania.

Furthermore, in October 2016, the Pennsylvania Environmental Quality Board issued final rules that are codified in Chapter 78a of Title 25 of the Pennsylvania Code. These rules changed and added requirements for surface activities related to unconventional oil and gas operations. The rules include requirements for permitting, waste handling, water management and restoration, surface reclamation, and abandoned and orphaned wells. In November 2016, the Pennsylvania Commonwealth Court issued an order that enjoins the enforcement of certain portions of the rules while the court considers an industry group’s legal challenges to those and other portions of the rules. These regulations may increase operating costs or cause unanticipated delays.

PaDEP, moreover, stated in an October 2017 regulatory update document that it is developing proposed amendments to the state’s well drilling, casing, cementing, operation, and plugging regulations.

In addition, in 2018, PaDEP is expected to finalize a new general permit (“GP-5A”) for air pollutant emissions from sources at new or modified gas well sites and certain remote pigging stations. Under the permit, methane, VOC, and hazardous air pollutant emissions from certain sources would need to be controlled, using leading technologies, if uncontrolled potential emissions from those sources would exceed certain limits (e.g., 200 tons per year for methane). GP-5A would also include special requirements for well drilling and hydraulic fracturing operations, well completion operations, and wellbore liquids unloading operations. And, it would impose certain leak detection and repair requirements, which would be more stringent than the ones that NSPS OOOOa (discussed above) imposes.

Although it is not possible at this time to predict whether proposed federal or state legislation or regulations will be adopted as currently written, if at all, or how legislation or new regulations that may be adopted to address environmental matters would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions could have a material adverse effect on our business, financial condition, and results of operation. In addition, new environmental laws or regulations could curtail the demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect demand for our products and services, which may in turn adversely affect our future results of operations.

We maintain an internet website under the name “www.rexenergy.com.” We make available, free of charge, on our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the Securities and Exchange Commission (“SEC”). Our Corporate Governance Guidelines, the charters of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee, and the Code of Business Conduct and Ethics for directors, officers, employees and financial officers are also available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 366 Walker Drive, State College, PA 16801. Information contained on or connected to our website is not incorporated by reference into this report and should not be considered part of this report or any other filing that we make with the SEC.

We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Rex Energy Corporation, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov.

In evaluating our company, the risk factors described below should be considered carefully. The occurrence of one or more of these events could significantly and adversely affect our business, prospects, financial condition, results of operations and cash flows. In such a case, you may lose all or part of your investment. The risks described below are not the only ones we face. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially adversely affect our business, financial condition and results of operations. This Annual Report on Form 10-K also contains forward-looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of various factors, including the risks described below.

We have concluded that we need to restructure our balance sheet to continue as a going concern over the long term, and we can provide no assurances of the terms of any such restructuring transaction in which we may engage or how any such transaction will impact our security-holders.

As a result of extremely challenging current market conditions, we believe we will require a significant restructuring of our balance sheet in order to continue as a going concern in the long term. We have based this belief on assumptions and estimates that may prove to be wrong, and we could spend our available financial resources less or more rapidly than currently expected. In September 2017, we entered into confidentiality agreements and commenced discussions with legal and financial advisors for a committee of holders of our outstanding senior notes (the “Noteholders”), who have represented to the Company that they hold a substantial portion of our outstanding senior notes, to explore one or more possible restructuring, financing, refinancing, reorganization, recapitalization, amendment, waiver, forbearance, asset sale and/or similar transactions involving the Company. Subsequent to the date of the execution of those confidentiality agreements, the Noteholder advisors conducted due diligence on the Company and engaged in discussions with us and our advisors. In early January 2018, we entered into confidentiality agreements with the Noteholders to discuss a possible transaction and subsequently engaged in negotiation with the Noteholders with respect to a potential transaction. We have not yet reached agreement on mutually acceptable terms and conditions with the Noteholders regarding a possible transaction.

There can be no assurance that our efforts will result in any agreement or what the terms of any agreement will be. If an agreement is reached and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings. We also may conclude that it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring. In either case, such a proceeding could be commenced in the near term. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment. It is also possible that our other stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.

Our potential for restructuring transactions may impact our business, financial condition and operations.

Due to the potential for a restructuring of our balance sheet, there is risk that, among other things:

The occurrence of certain of these events may have a material adverse effect on our business, results of operations and financial condition.

We have substantial indebtedness and may incur substantially more debt, which could exacerbate the risks associated with our indebtedness.

As of December 31, 2017, we had approximately $799.9 million of debt outstanding, including $600.3 million related to our senior notes, $189.5 million outstanding on our delayed draw term loan credit facility and $10.1 million related to other obligations. We and our subsidiaries may be able to incur substantial additional indebtedness in the future, including under our term loan credit facility. At December 31, 2017, we had additional available borrowing capacity of $78.5 million under our term loan credit facility.

As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, which will reduce the amount we will have available to fund our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our term loan credit facility is at a variable interest rate, so a rise in interest rates will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges. Our aggregate interest expense also increased when the interest rate applicable to our outstanding senior secured second lien notes increased from 1.00% per annum to 8.00% per annum commencing on October 1, 2017 in accordance with the terms of those notes. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indentures governing our senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness as that term is defined in the respective indentures.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors, many of which we are unable to control and our ability to restructure our balance sheet. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets, or issue additional equity on terms that we may not find attractive, if it may be done at all. In the event that we are unable to comply with the financial covenants in our term loan credit facility, there can be no assurance that we will be able to obtain waivers from our lenders. Further, any failure by us to comply with the financial and other restrictive covenants relating to our indebtedness, or to obtain a related waiver from our lenders, could result in a default or event of default under that indebtedness, which could trigger the acceleration of a significant portion of our indebtedness and adversely affect our business, financial condition and results of operations.

Natural gas, NGL and oil prices have been volatile and are currently depressed. If commodity prices remain depressed for a lengthy period of time or experience a further substantial or extended decline, our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments could be materially and adversely affected.

The prices we receive for our condensate, NGL and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Natural gas and oil are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for natural gas and oil have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

Furthermore, natural gas and oil prices continued to be volatile in 2017. For example, the WTI oil spot price in 2017 ranged from a high of $60.42 to a low of $42.53 per Bbl and Henry Hub natural gas spot prices in 2017 ranged from a high of $3.42 to a low of $2.56 per MMBtu.

Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow in the future under our term loan credit facility is subject to our compliance with a ratio of our net senior secured debt to EBITDAX, and our ability to meet that ratio currently and in the future is based in part on current natural gas and oil prices and on changing expectations of future prices.

Lower natural gas, NGL, and oil prices may not only decrease our revenues on a per-unit basis, but also may reduce the amount of oil, NGLs and natural gas that we can produce economically. A sustained decline in natural gas, NGL, or oil prices, or a further increase in our negative differentials, may materially and adversely affect our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures.

Commodity prices have declined substantially from historic highs and may remain depressed for the foreseeable future. If commodity prices continue to remain depressed, we may be required to take additional write-downs of the carrying values of our oil and natural gas properties, some of our undeveloped locations may no longer be economically viable, the value of our estimated proved reserves could be reduced materially, we may need to sell assets or raise capital and we may not be able to pay our expenses or service our indebtedness.

During the nine years prior to December 31, 2017, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.49 per MMBtu in 2016. On December 31, 2017, the Henry Hub spot market price of natural gas was $2.95 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand.

In addition, oil prices have declined significantly since the second half of 2014. The price of WTI crude oil was $60.42 per barrel on December 31, 2017, which, although an increase year-over-year, is a significant decline from $106.70 per barrel on June 30, 2014. This environment could cause the commodity prices for oil and natural gas to remain at currently depressed levels or to fall to lower levels.

There is a risk that we will be required to write down the carrying value of our oil and gas properties. We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes, and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses, and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the book values associated with oil and gas properties.

During 2017, we recorded impairment expense of $21.4 million. Additional write-downs could occur if oil and gas prices continue to decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs, or deterioration in our drilling results, absent other mitigating circumstances. The risk we will be required to write-down the carrying value of our properties increases when oil and gas prices are low or volatile. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could prevent us from being able to comply with the covenants in our term loan credit agreement and to borrow additional amounts thereunder. This could have a material adverse effect on our results of operations for the periods in which such charges are taken.

In addition, we may be required to sell assets or raise capital by issuing additional debt (including additional priority lien debt) or equity in order pay expenses and service indebtedness. Furthermore, the value of our assets, if sold, may not be sufficient to pay our expenses or service our indebtedness. On January 20, 2016, we suspended payment of our quarterly dividend on shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001per share (the “Series A Preferred Stock”). We recommenced paying the quarterly dividend beginning with the dividend paid on May 15, 2017 (which payments were applied t the earliest dividend in arrears at the time of payment), but the dividend remains five quarters in arrears.

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The natural gas and oil industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures in our business and operations for the exploration for, and development, production, and acquisition of, oil and natural gas reserves. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations, public stock offerings, high-yield bond offerings, sales of non-core assets, and joint venture agreements.

We intend to finance our future capital expenditures with proceeds from bank borrowings, the sale of debt or equity securities, asset sales, cash flow from operations, and current and new financing arrangements, such as joint ventures; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock, and in some cases, a substantial dilutive effect. Additional borrowings under our term loan credit facility or the issuance of additional debt securities will require a greater portion of our cash flow from operations to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures, and acquisitions. In addition, our term loan credit facility imposes certain limitations on our ability to incur additional indebtedness other than indebtedness under our term loan credit facility. If we desire to issue additional debt securities other than as expressly permitted under our term loan credit facility, we will be required to seek the consent of the lenders in accordance with the requirements of the term loan credit facility, which consent may be withheld by the lenders at their discretion. If we incur additional indebtedness, we may not be able to comply with our debt covenants under our term loan credit agreement or make additional borrowings thereunder. Also, our term loan credit agreement contains covenants that restrict our ability to, among other things, materially change our business, approve and distribute dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

Our cash on hand, cash flow from operations, ability to borrow funds and access to capital is subject to a number of variables, many of which are beyond our control, including:

If our revenues decrease as a result of lower natural gas, NGL, or oil prices; operating difficulties; declines in reserves; or for any other reason we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may need to seek additional financing in the future. In addition, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.

We are subject to various contractual limitations that may restrict our business and financing activities.

Our term loan credit facility, the indentures governing our outstanding senior notes, and the certificate of designations governing our Series A Preferred Stock contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants and limitations that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

Additionally, if dividends on our Series A Preferred Stock are in arrears and unpaid for six or more quarterly periods, the holders (voting as a single class) of our outstanding Series A Preferred Stock will be entitled to elect two additional directors to our Board of Directors until paid in full. These dividends are currently in arrears for five quarterly periods.

As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of these covenants and restrictions may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with the covenants, ratios or tests in our term loan credit facility, the indentures governing our senior notes, or any future indebtedness could result in an event of default under our term loan credit facility, the indentures governing our senior notes, or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition, and results of operations. If an event of default under our term loan credit facility occurs and remains uncured, the lenders thereunder:

A payment default or an acceleration under our term loan credit facility could result in an event of default and an acceleration under the indentures for our senior notes.

If the indebtedness under the senior notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our term loan credit facility are collateralized by perfected first priority liens and security interests on substantially all of our assets and if we are unable to repay our indebtedness under the term loan credit facility, the lenders could seek to foreclose on our assets.

The value of our proved reserves as of December 31, 2017, calculated using SEC pricing, may be different than the fair market value of our proved reserves calculated using current market prices.

Our estimated proved reserves as of December 31, 2017, Standardized Measure and related PV-10 were calculated under SEC rules using twelve-month trailing average benchmark prices of $47.79 per barrel of oil (WTI) and $2.98 per MMBtu (Henry Hub spot). The spot prices for oil and natural gas on March 29, 2018 were $64.94 per barrel of oil and $2.733 per MMBtu, respectively, higher than the benchmark price for a barrel of oil and lower per MMBtu referenced above. Using these more recent prices in estimating our proved reserves, without giving effect to any acquisitions or development activities we have executed in 2018, would likely result in an increase in proved reserve volumes. If spot prices on March 29, 2018 had been lower than the twelve-month trailing average benchmark prices used to calculate SEC estimated proved reserves, Standardized Measure and related PV-10, then estimates based on the lower spot prices would have resulted in a reduction in proved reserves volumes. As these illustrations demonstrate, volatility in pricing can have a significant impact on the Standardized Measure and PV-10 of our proved reserves.

Although we have hedged a portion of our estimated 2018 production, our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of natural gas and oil.

Our first lien term loan requires us to hedge at certain levels of our estimated proved developed producing reserves. These hedges may be inadequate to protect us from a prolonged decline in the price of natural gas and oil. To the extent that the price of natural gas and oil decline, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.

Drilling for and producing natural gas, NGLs and oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future success will depend on the success of our exploitation, exploration, development, and production activities. Our natural gas, NGL, and oil exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas, NGL, or oil production. Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. Please see below for a discussion of the uncertainties involved in these processes. Our costs of drilling, completing, and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay, or cancel drilling, including the following:

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

We may experience differentials to benchmark prices in the future, which may be material.

A substantial portion of our production is sold to purchasers at prices that reflect a discount to other relevant benchmark prices, such as WTI NYMEX. The difference between a benchmark price and the price we reference in our sales contracts is called a basis differential. Basis differentials result from variances in regional prices compared to benchmark prices as a result of regional supply and demand factors. We may experience differentials to benchmark prices in the future, which may be material.

Our results of operations and cash flow may be adversely affected by risks associated with our natural gas, NGL and oil financial derivative activities, and our natural gas, NGL, and oil financial derivative activities may limit potential gains.

We have entered into, and we expect to enter into in the future, oil and gas financial derivative arrangements corresponding to a significant portion of our natural gas and oil production. Many derivative instruments that we employ require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. We made net payments of $10.1 million related to our commodity derivative instruments for the year ended December 31, 2017.

If our actual production and sales for any period are less than the corresponding volume of derivative contracts for that period (including reductions in production due to operational delays), or if we are unable to perform our activities as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. In addition, our natural gas and oil financial derivative activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable derivative arrangement, the arrangement is imperfect or our derivative policies and procedures are not followed or do not work as planned. Under the terms of our term loan credit facility the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volume.

The standardized measure and PV-10 of our estimated reserves included in this report should not be considered as the current fair value of the estimated oil and natural gas reserves attributable to our properties.

Standardized Measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Our non-GAAP financial measure, PV-10, is a similar reporting convention that we have disclosed in this report. Both measures require the use of operating and development costs prevailing as of the date of computation. Consequently, they will not reflect the prices ordinarily received or that will be received for natural gas and oil production because of varying market conditions, nor may they reflect the actual costs that will be required to produce or develop the natural gas and oil properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the 10 percent discount factor, which is required by the rules and regulations of the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general. Therefore, Standardized Measure or PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves.

Based on December 31, 2017 reserve estimates, we project that a 10% decline in the price per barrel of oil, price per barrel of NGLs and the price per Mcf of gas from average 2017 prices would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2018 by approximately $29.0 million.

Prospects that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities.

Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or completion costs or to be economically viable, particularly in light of the current economic environment. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

We may be required to take additional write-downs of the carrying values of our natural gas and oil properties, potentially causing our inability to comply with the covenants in our term loan credit facility and /or our ability to make additional borrowings thereunder and negatively impacting the trading value of our securities.

There is a risk that we will be required to write down the carrying value of our natural gas and oil properties. We account for our natural gas and oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Natural gas and oil lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for natural gas and oil leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and may have a material adverse effect on our ability to pay interest on our senior notes.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our natural gas and oil properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of natural gas and oil properties is not reversible at a later date even if natural gas or oil prices increase. Given the complexities associated with natural gas and oil reserve estimates and the history of price volatility in the natural gas and oil markets, events may arise that would require us to record an impairment of the book values associated with oil and gas properties.

During 2017, we recorded impairment expense of approximately $21.4 million. Additional write downs could occur if natural gas and oil prices continue to decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results, absent other mitigating circumstances. The risk we will be required to write down the carrying value of our properties increases when natural gas and oil prices are low or volatile. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties may result in our inability to comply with the covenants in our term loan credit agreement or to borrow additional amounts thereunder. This could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

Estimates of natural gas and oil reserves are inherently imprecise. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare our proved reserve estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production, and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as natural gas, NGL, and oil prices; drilling and operating expenses; capital expenditures; taxes; and availability of funds.

Actual future production; natural gas, NGL, and oil prices; revenues; taxes; development expenditures; operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of estimated proved reserves to reflect production history; results of exploration and development; prevailing natural gas, NGL, and oil prices; and other factors, many of which are beyond our control.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated natural gas, NGL, and oil reserves.

We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following:

Risks that we face while completing our wells include, but are not limited to, the following:

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Our identified drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has identified and scheduled drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. All of our drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, availability of drilling services and equipment, lease expirations, gathering system, marketing and pipeline transportation constraints, natural gas and oil prices, drilling and production costs, drilling results, and other factors. Because of these uncertainties, we do not

know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential drilling locations. Pursuant to SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. The SEC rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Unless we replace our natural gas, NGL, and oil reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing natural gas, NGLs, and oil reservoirs generally are characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future natural gas, NGLs, and oil reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find, or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition, and results of operations.

If we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules, our ability to produce natural gas, NGLs, and condensate commercially and in commercial quantities could be impaired.

We use approximately 289,000 Bbls of water per well in our well completion operations in the Appalachian Basin. Our inability to locate sufficient amounts of water, or dispose of water after drilling, could adversely impact our operations. Moreover, the adoption and implementation of new environmental regulations could result in restrictions on our ability to conduct certain operations such as hydraulic fracturing or the imposition of new requirements pertaining to the management and disposal of wastes generated by our operations, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas, NGLs and condensate. Furthermore, new environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could adversely affect our financial condition and results of operations.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and drilling and completion services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

We may, from time to time, encounter difficulty in obtaining, or an increase in the cost of securing, drilling rigs, equipment, services, and supplies. In addition, larger producers may be more likely to secure access to such equipment and services by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our financial condition and results of operations.

Federal, state, and local regulation of hydraulic fracturing could result in increased costs and additional restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Increased regulation of hydraulic fracturing may adversely impact our business, financial condition, and results of operations.

The SDWA establishes the underground injection control (“UIC”) program, which governs the underground injection of substances. The hydraulic fracturing process is typically regulated by state agencies; however, under the SDWA’s UIC program, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities that involve the use of diesel fuel. In addition, bills have been introduced in prior sessions of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the hydraulic fracturing process. On November 30, 2017 the Delaware River Basin Commission, a federal-state agency, released draft regulations that would permanently prohibit anyone from using hydraulic fracturing to recover gas in the Delaware River Basin, which includes gas-bearing zones in eastern and northeastern Pennsylvania. In addition, many state governments, including Pennsylvania’s and Ohio’s, have adopted and are considering adopting regulations to impose more stringent permitting, public disclosure, well construction, and operational requirements in relation to hydraulic fracturing activities or otherwise delay or temporarily or permanently prohibit those activities. PaDEP, for example, stated in an October 2017 regulatory update document that it is developing proposed amendments to the state’s well drilling, casing, cementing, operation, and plugging regulations. In addition to state laws, local land use enactments, such as city ordinances, zoning laws, and traffic regulations may restrict where gas well drilling, in general, or hydraulic fracturing in particular, may be conducted.

We believe that, in conducting hydraulic fracturing activities, we follow the applicable legal requirements and standard industry practices groundwater protection. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews, which are either completed, underway, or proposed, are focused on the environmental aspects of hydraulic fracturing practices. In December of 2016, for example, the EPA finalized a study regarding the potential effects of hydraulic fracturing on drinking water and groundwater. In the study, the EPA found, among other things, that injecting hydraulic fracturing fluids into gas wells that are not structurally and mechanically adequate can allow gases or liquids to migrate into groundwater resources. Other government agencies have likewise evaluated or are evaluating various aspects of hydraulic fracturing. These types of studies, depending on the degree to which they are pursued and their results and findings, could spur initiatives to further regulate hydraulic fracturing.

The EPA, in addition, has utilized existing authority under the SDWA, the Clean Water Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), and the Clean Air Act to investigate, order actions, and pursue penalties against operators whose hydraulic fracturing or other gas and Oil activities allegedly impacted the air, soil, or water.

To our knowledge, there have been no citations or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability, excess liability, and pollution insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

If our access to markets is restricted, it could negatively impact our production, our income, and ultimately our ability to retain our leases. Our ability to sell our natural gas, NGLs, and oil (including ethane) and/or receive market prices for our natural gas, NGLs, and oil may be adversely affected by pipeline and gathering system capacity constraints.

Market conditions or the unavailability of satisfactory natural gas, NGL, and oil transportation arrangements may hinder our access to natural gas, NGL, and oil markets or delay our production. The availability of a ready market for our natural gas, NGL, and oil production depends on a number of factors, including the demand for and supply of natural gas, NGLs, and oil and the proximity of reserves to pipelines, and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our natural gas, NGLs, or oil may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

If drilling in the Marcellus Shale and other areas of the Appalachian Basin continues to be successful, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Certain pipeline projects that are planned for these areas may not occur. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might be required to shut in our wells to await a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

A portion of our natural gas, NGL, and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues, or strikes or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.

We do not operate all of the properties in which we own an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

All of the value of our production and reserves is concentrated in the Appalachian Basin. Because of this concentration, any production problems or changes in assumptions affecting our proved reserve estimates or other risks related to this area could have a material adverse impact to our business.

For the year ended December 31, 2017, all of our estimated proved reserves and net production came from the Appalachian Basin. If mechanical problems, weather conditions, or other events impacting the region were to curtail a substantial portion of the production in the Appalachian Basin or otherwise adversely impact regional processing, transportation, governmental regulation, or labor matters, our results of operation would be adversely affected. Also, if ultimate production associated with our properties in the Appalachian Basin is less than our estimated reserves, or changes in pricing, cost, or recovery assumptions in the area results in a downward revision of any estimated reserves in these properties, our business, financial condition, and results of operations could be adversely affected.

Competition in the natural gas, NGL, and oil industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing natural gas, NGLs, and oil and securing trained personnel. Many of our competitors possess and employ financial, technical, and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive natural gas and oil 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. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting, and retaining quality personnel and raising additional capital.

We are a party to several transportation, marketing and processing agreements which commit us to payment obligations over the next five years. We may incur substantial shortfall costs if we are unable to meet our volume commitments or otherwise sell this capacity rights to third parties.

In the normal course of business we enter in to transportation, marketing and processing agreements to ensure future market outlets for our natural gas, NGLs, and oil. These agreements commit us to future obligations to be paid regardless of volumes produced. As of December 31, 2017, we were a party to several transportation, marketing, and processing agreements which commit us to approximately $243.4 million over the next five years. If we are unable to meet our volume commitments or otherwise convey our capacity rights to third parties we may incur substantial costs associated with these contracts without corresponding natural gas, NGLs, and oil sales.

We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas, NGLs, and oil operations, and we may not have enough insurance to cover all of the risks that we face.

We maintain insurance coverage against some, but not all, potential losses to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to insure fully against pollution and environmental risks.

Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, and results of operations. Our natural gas and oil exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, NGLs, and oil, including the possibility of:

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our financial condition, results of operations, and cash flows.

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

The exploration, development, production and sale natural gas, NGLs, and oil are subject to extensive federal, state, and local laws and regulations. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:

Under these laws, we could be subject to claims for personal injury or property damages, including natural resource damages, which may result from the impacts of our operations. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs of compliance. Any such liabilities, penalties, suspensions, terminations, or regulatory changes could have a material adverse effect on our financial condition and results of operations.

We must obtain governmental permits and approvals for our drilling and midstream operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state, or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas or oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Our operations expose us to substantial costs and liabilities with respect to environmental matters.

Our natural gas, NGLs, and oil operations are subject to stringent federal, state and local laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences; impose restrictions on withdrawals from surface water resources; establish

erosion and sediment control requirements for well pads and access roads; restrict the types, quantities, and concentration of substances that can be released into the environment in connection with our drilling and production activities; govern the handling and disposal of waste materials; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including the habitat of threatened and endangered species; and impose substantial liabilities for pollution that may result from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory or remedial obligations or the issuance of injunctions restricting or prohibiting certain activities. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or whether our operations were in compliance with all applicable laws at the time they were performed.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our competitive position, financial condition and results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, NGLs, and oil that we produce.

In December 2009, the EPA published findings that emissions of greenhouse gases (“GHGs”) present a danger to public health and the environment because those emissions are contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA, under the Clean Air Act, has begun adopting regulations to restrict emissions of GHGs. The EPA, for example, adopted a set of rules that requires a reduction in GHG emissions from motor vehicles and another set of rules that regulates GHG emissions from certain large stationary sources. The EPA has also adopted rules that require monitoring and reporting on GHG emissions from specified sources, including petroleum refineries and certain onshore oil and natural gas production facilities. We believe that we are in substantial compliance with these reporting requirements.

The EPA, in addition, issued regulations in 2012, which it amended in 2013 and 2014, known as “NSPS OOOO,” which require operators of new and modified hydraulically-fractured gas wells to use special techniques (known as “green completions”) to reduce emissions of Volatile Organic Compounds (“VOCs”) from the wells. On May 12, 2016, the EPA issued regulations (effective August 2, 2016), known as “NSPS OOOOa,” which built on the NSPS OOOO standards by directly regulating methane and VOC emissions from various types of new and modified oil and gas sources. Some of those sources were already regulated under NSPS OOOO, while others, like pneumatic pumps, were covered for the first time. The EPA, however, is now planning to reconsider OOOOa’s requirements for (i) monitoring for fugitive emissions (i.e., leaks), (ii) using professional engineers to certify closed vent systems, and (iii) pneumatic pumps that are used at well sites. It is also planning to stay or postpone the effective dates of those requirements while it reconsiders them. On February 23, 2018, moreover, the EPA amended OOOOa to remove certain requirements for sources of fugitive emissions to be repaired during unscheduled or emergency shutdowns.

In 2018, moreover, PaDEP is expected to finalize a new general permit (“GP-5A”) for air pollutant emissions from sources at new or modified gas well sites and certain remote pigging stations. Under the permit, methane, VOC, and hazardous air pollutant (“HAP”) emissions from certain sources would need to be controlled, using leading technologies, if uncontrolled potential emissions from those sources would exceed certain limits (e.g., 200 tons per year for methane). GP-5A would also include special requirements for well drilling and hydraulic fracturing operations, well completion operations, and wellbore liquids unloading operations. And, it would impose certain leak detection and repair (“LDAR”) requirements, which would be more stringent than the ones that NSPS OOOOa imposes.

Also, Congress has from time to time considered bills to reduce emissions of GHGs, and almost one-half of the states already have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulation that requires reporting on GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the natural gas, NGLs, and oil we produce. Finally, some scientists have concluded that the increasing concentrations of GHGs in the earth’s atmosphere may produce climate change that could have

significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our assets and operations.

The adoption of derivatives legislation by Congress and related regulations could have an adverse impact on our ability to use derivative instruments, particularly swaps, to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act, was enacted in 2010. The Act provides for new statutory and regulatory requirements for derivative transactions, including certain natural gas and oil transactions involving swaps. In particular, the Act includes general requirements that certain standardized transactions involving swaps be cleared and exchange-traded and, that parties post collateral for non-cleared swap transactions. At this time, the Commodity Futures Trading Commission, or CFTC, has not yet required natural gas and oil swaps to be cleared and exchange-traded, although it has adopted clearing mandates for certain interest rate swaps and credit default swaps on broad-based stock indices. Further, the Act provides for an exception from the clearing and exchange-trading requirement for swap transactions entered into by commercial end-users, a category of non-financial entities that includes Rex Energy, provided such transactions hedge or mitigate commercial risk and the party notifies the CFTC how it generally meets its financial obligations associated with entering into non-cleared swaps. While the CFTC and other federal agencies have adopted, and continue to adopt, numerous regulations pursuant to the Act, certain of the key concepts and defined terms under the Act have not yet been delineated by rules and regulations. In February 2017, President Trump signed an executive order directing the Secretary of the Treasury to meet with various agencies that oversee and implement the Act’s regulations to find areas to be amended. That review has been concluded, but it is unclear what regulations or parts of the Act will be most likely to change, if any. As a consequence, it is difficult to predict the aggregate effect the Act and the regulations promulgated thereunder may have on our hedging activities. Whether we are required to submit our swap transactions for clearing or post collateral with respect to such transaction will depend on the final rules and definitions adopted by the CFTC. Even if the regulators do not require clearing or posting collateral, a counterparty to a particular swap may require posting of collateral. If we are subject to such requirements, significant liquidity issues could result by reducing our ability to use cash or other assets posted as collateral for investment or other corporate purposes. A requirement to post cash or other assets as collateral could also limit our ability to execute strategic hedges, which may result in increased commodity price uncertainty and volatility in our future cash flows. The Act and related regulations currently also require us to comply with certain futures and swaps position limits and new recordkeeping requirements and possibly new reporting requirements, and also could require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and related regulations could also materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Enactment of a Pennsylvania impact fee and severance tax on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.

In February 2012, Pennsylvania implemented an impact fee. The fee is imposed on all unconventional wells that are drilled in the Pennsylvania counties that elected to impose it. The fee, which changes from year to year, is based on the average annual price of natural gas, determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For a given unconventional, horizontal well, the fee is initially imposed in the year after the well is spudded and then imposed annually for 15 years. There can be no assurance that the impact fee will remain as it is currently structured or that new or additional fees of its type will not be imposed.

Historically, Pennsylvania has not imposed a severance tax in connection with the extraction of natural gas. Since 2008, however, in light of deficits in the state’s budget and the increasing exploration of the Marcellus Shale, a number of severance tax bills have been introduced in the Pennsylvania General Assembly. In 2016, 2017, and 2018, moreover, the Pennsylvania governor proposed state budgets that included proposals for a new severance tax that would be imposed in addition to the impact fee (the proposed tax rate was 6.5% in 2016 and 2017 and is variable, based on natural gas market prices, in 2018). Although no such proposal has yet been enacted into law, there can be no assurance that we will not be subject to additional severance or similar taxes in the future.

Changes to the current impact fee, or the imposition of a new severance tax, could negatively affect our future cash flows and financial condition.

Future economic conditions in the U.S. and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.

The U.S. and other world economies continue to experience the after-effects of a global recession and credit market crisis. More volatility may occur before a sustainable growth rate is achieved either domestically or globally. Even if such growth rate is achieved, such a rate may be lower than the U.S. and international economies have experienced in the past. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand for our natural gas, NGLs, and oil production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.

We derive a significant amount of our revenue from sales to a relatively small number of purchasers. Approximately 78.6% of our commodity sales from continuing operations for the year ended December 31, 2017 were to three customers, BP Energy Company, MarkWest Liberty Midstream Resources, LLC, and Shell Trading (US) Company, with BP Energy Company, our largest single customer, accounting for 47.0%. If we were unable to continue to sell our natural gas, NGLs and oil to these key customers, or to offset any reduction in sales to these customers by additional sales to our other customers, it could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. We also are subject to risk from loss resulting from non-performance or non-payment by these significant customers. The loss of all or a significant part of our revenue from our significant customers would adversely affect our financial condition and results of operations.

Our operations depend on the continuing efforts of our executive officers and senior management. Our business or prospects could be adversely affected if any of these persons do not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not carry key person insurance for any of our executive officers or senior management.

Our future acquisitions may yield revenue or production that varies significantly from our projections.

In pursuing potential acquisition of oil and natural gas properties, we will assess the potential recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities, and other factors relating to the properties. Our assessments are necessarily inexact, and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

Changes in tax laws may adversely affect our results of operations and cash flows.

On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted. The Tax Act significantly changed the Internal Revenue Code, reducing the Federal statutory corporate income tax rate from 35% to 21%, allowing for bonus depreciation on certain qualified property, eliminating the alternative minimum tax for corporate taxpayers, adding a new limitation on the deductibility of business interest expense and adding a limitation on the deduction for net operating losses. The Tax Act also authorizes the Treasury Department to issue regulations with respect to the new provisions. We are still in the process of analyzing the Tax Cuts and Jobs Act and its possible effects on the Company. We cannot predict how the changes in the Tax Cuts and Jobs Act, regulations, or other guidance issued under it or conforming or non-conforming state tax rules might affect us or our business. In addition, there can be no assurance that U.S. tax laws, including the corporate income tax rate, will not undergo significant changes in the near future.

New technologies may cause our current exploration and drilling methods to become obsolete.

The natural gas and oil industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a

timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations, and cash flows.

The outcome of litigation in which we have been named as a defendant is unpredictable and an adverse decision in any such matter could have a material adverse effect on our financial position.

We are defendants in a number of litigation matters and are subject to various other claims, demands and investigations. These matters may divert financial and management resources that would otherwise be used to benefit our operations. No assurances can be given that the results of these matters will be favorable to us. An adverse resolution or outcome of any of these lawsuits, claims, demands, or investigations could have a negative impact on our financial condition, results of operations, and liquidity.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The natural gas and oil industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.

Our independent registered public accounting firm has concurred with our determination that there is substantial doubt about our ability to continue as a going concern.

We recently have incurred significant operating and net losses and may continue to incur net operating losses. Without additional sources of capital or a significant restructuring of our balance sheet, these conditions raise substantial doubt about our ability to continue as a going concern, which means that we may be unable to continue operations for the foreseeable future or realize assets and discharge liabilities in the ordinary course of operations. As a result, our independent registered public accounting firm included an explanatory paragraph with respect to this uncertainty in its report that is included with our financial statements in this Annual Report on Form 10-K. Such an opinion may materially and adversely affect the price per share of our common stock and may otherwise limit our ability to raise additional funds through the issuance of debt or equity securities or otherwise. Further, the perception that we may be unable to continue as a going concern may impede our ability to raise additional funds or operate our business due to concerns with respect to our ability to discharge our contractual obligations.

We have prepared our financial statements on a going concern basis, which contemplates that we will be able to realize our assets and discharge our liabilities and commitments in the ordinary course of business. Our financial statements included in this Annual Report on Form 10-K do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty. Without additional capital or a significant restructuring of our balance sheet, however, we may be unable to continue as a viable entity, in which case our stockholders may lose all or some of their investment in us.

Our stock price could be volatile, which could cause you to lose part or all of your investment.

The stock market has from time to time experienced significant price and volume fluctuations that may be unrelated to the operating performance of particular companies. In particular, the market price of our common stock, like that of the securities of other energy companies, has been and may continue to be highly volatile. During 2017, the sales price of our stock ranged from a low of $0.32 per share (on April 21, 2017, prior to our one-for-ten reverse stock split on May 15, 2017) to a high of $4.71 per share (on May 15, 2017, the effective date of our one-for-ten reverse stock split). In 2018, through April 11, 2018, our stock has traded as low as $0.53 per share (on April 11, 2018). Factors such as announcements concerning balance sheet restructuring transactions that we may pursue, our delisting and deregistration from the Nasdaq Capital Market, changes in prices of oil and natural gas, the success of our acquisition, exploration and development activities, the availability of capital, and economic and other external factors, as well as period-to-period fluctuations and our financial results, may have a significant effect on the market price of our common stock.

We are no longer eligible to use registration statements on Form S-3, which could impair our ability to raise capital.

As a result of our historically not declaring and paying regular quarterly dividends on our Series A Preferred Stock, for a period of five quarters, as of the date of this report, we are not eligible to use registration statements on Form S-3. As a result, we cannot use registration statements on Form S-3 to register resales of our securities until we have filed an annual report on Form 10-K including audited financial statements covering the period in which the failure to pay preferred dividends is rectified. In addition, we may be limited in our ability to offer and sell securities while utilizing shelf registration statements on Form S-3 if our public float is below $75 million. As a result, we may not be eligible during any 12-month period to use registration statements on Form S-3 for primary offerings of securities having an aggregate market value of more than one-third of our public float, even though we otherwise would regain the ability to use the form for resale registration statements. Any limitations on our ability to use shelf registration statements may harm our ability to raise the capital we need in an efficient manner or on acceptable terms. Under these circumstances, until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register securities with the SEC or issue such securities in a private placement, which could increase the cost of raising capital in the event that we do so.

We may issue additional common stock in the future, which would dilute our existing stockholders.

In the future, we may issue our previously authorized and unissued securities, including shares of our common stock or securities convertible into or exchangeable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are authorized under our certificate of incorporation to issue up to 100,000,000 shares of common stock and up to 100,000 shares of preferred stock with such designations, preferences, and rights as may be determined by our board of directors. In the future, we may seek stockholder approval to increase our authorized capital. As of April 11, 2018, there were 10,708,287 shares of our common stock issued and outstanding and 3,987 shares of our Series A Preferred Stock, issued and outstanding.

We have issued in the past, and we may continue to issue additional shares of our common stock or securities convertible into or exchangeable for our common stock to pay accrued dividends on our Series A Preferred Stock in accordance with the terms of our Series A Preferred Stock, in connection with public offerings, private placements, the hiring of personnel, acquisitions, for capital raising purposes. For example, we issued shares of our common stock on November 15, 2017 and February 15, 2018 to pay quarterly dividends on our Series A Preferred Stock. Future issuances of our common stock, or the perception that such issuances could occur, could have a material adverse effect on the price of our common stock.

Our certificate of incorporation, bylaws, and Delaware law contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors and the ownership of our common stock by our board of directors, including our Chairman, and our executive officers, who collectively beneficially own approximately 7.2% of the outstanding shares of our common stock as of March 31, 2018, could discourage a potential takeover attempt.

Provisions in our certificate of incorporation and bylaws, as currently in effect, could have the effect of delaying or preventing a change of control of us and changes in our management. These provisions include the following:

In addition, we are subject to the provisions of Section 203 of the Delaware General Corporation Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from engaging in business combinations, such as mergers or consolidations, with us.

As of March 31, 2018, our board of directors, including Lance T. Shaner, our Chairman, and our executive officers collectively own approximately 7.2% of the outstanding shares of our common stock.

The provisions in our certificate of incorporation and bylaws and under Delaware law, and the ownership of our common stock by our Chairman and other executive officers, could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock.

Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation of our common stock to realize a gain on their investments.

We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our term loan credit facility limits the payment of dividends without the prior written consent of the lenders. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment. This appreciation may not occur. In addition, the ability of stockholders to realize any appreciation that may occur is subject to the liquidity of our common stock at a given time.

We are able to issue shares of preferred stock with greater rights than our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, liquidation rights, or voting rights. If we issue additional preferred stock, it may adversely affect the market price of our common stock.

If our stockholders sell a substantial number of shares of our common stock, or the public market perceives that our stockholders might sell shares of our common stock, the market price of our common stock could decline significantly. We cannot

predict the effect that future sales of our common stock or other equity-related securities by our stockholders would have on the market price of our common stock.

We may be unable to list our common stock on Nasdaq, the New York Stock Exchange or on any securities exchange.

Our common stock has been listed on the Nasdaq Capital Market, where it had been listed since December 2016 after previously being listed on the Nasdaq Global Select Market. On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department of Nasdaq indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we requested an appeal before the Nasdaq Hearings Panel. We did not appeal this determination and the time period in which to appeal has lapsed. The delisting of our common stock from Nasdaq could negatively impact us by (i) reducing the liquidity and market price of our common stock; (ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; (iii) preventing or limiting our access to public capital markets; and (iv) impairing our ability to provide equity incentives to effectively attract, motivate and retain our employees.

Following the delisting of our common stock from Nasdaq, our common stock may be eligible for quotation on the OTCBB or OTC Markets Group’s Pink marketplace. Trading on the OTCBB or Pink marketplace may occur only if a market maker applies to quote our common stock and we are current in our reporting obligations under the Securities Exchange Act of 1934. Once our common stock is delisted from Nasdaq, there can be no assurance that a market maker will apply to quote our common stock or that our common stock then will be eligible for quotation on the OTCBB or the Pink marketplace.

Although we may apply to list our common stock on Nasdaq or the New York Stock Exchange in the future, we cannot assure you that we will be able to meet the initial listing standards, including the minimum per share price and minimum capitalization requirements, or that we will be able to maintain a listing of our common stock on either of those or any other trading venue. Until such time as we would qualify for listing on Nasdaq, the New York Stock Exchange or another trading venue, our common stock may trade on quotation on the OTCBB or OTC Markets Group’s Pink marketplace or another over-the-counter quotation system where an investor may find it more difficult to dispose of shares or obtain accurate quotations as to the market value of our common stock. In addition, rules promulgated by the SEC impose various practice requirements on broker-dealers who sell securities that fail to meet certain criteria set forth in those rules to persons other than established customers and accredited investors. Consequently, these rules may deter broker-dealers from recommending or selling our common stock, which may further affect the liquidity of our common stock. It would also make it more difficult for us to raise additional capital. We cannot provide any assurance that an active public market for our common stock will be available or remain sustained in the future.

As of the date of this filing, we have no unresolved comments from the staff of the SEC.

The table below summarizes certain data for our core operating areas at December 31, 2017:

Segment reporting is not applicable to our exploration and production operations, as we have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.

As of December 31, 2017, we owned an interest in approximately 554 producing natural gas wells located predominantly in Pennsylvania and Ohio. In addition to our producing wells, we own one gross location with proved developed non-producing reserves totaling 0.0 Bcfe. At December 31, 2017, we had approximately 204,600 gross (141,000 net) acres under lease, of which 33,700 gross (27,700 net) acres were undeveloped. Of our total acreage holdings, we believe that approximately 132,100 gross (105,100 net) acres are prospective for three producing horizons, including the Marcellus, Utica and Burkett. Reserves at December 31, 2017 increased 385.1 Bcfe, or 59.4%, from 2016 primarily as a result of positive well performance in our Butler, Moraine East and Warrior North assets and an increase in commodity prices in 2017.

Cash capital expenditures in 2017 for drilling and facility development totaled $113.4 million, net of credits from our joint venture partners, which funded the drilling of 28.0 gross (20.5 net) wells. During the year, we placed into service 26.0 gross (15.2 net) wells and had an inventory of 11.0 gross (8.0 net) wells awaiting completion.

As of December 31, 2017, we had interests in approximately 171,400 gross (117,700 net) Marcellus Shale prospective acres in areas of Pennsylvania, and we continue to expand our position by strategically filling in key pieces of acreage to complete drilling units. Our total acreage holdings include approximately 132,100 gross (105,100 net) acres that we believe to be prospective for liquid-rich Marcellus production. During 2017, we drilled, or participated in the drilling of 16.0 gross (11.2 net) Marcellus Shale wells and placed into service 19.0 gross (10.1 net) Marcellus Shale wells. Our estimated proved reserves related to the Marcellus Shale as of December 31, 2017, totaled approximately 824.1 Bcfe, including two proved non-producing locations with estimated proved reserves of 26.1 Bcfe and six proved undeveloped locations with estimated proved reserves of 72.2 Bcfe..

We are a party to three joint ventures in Pennsylvania that represent our primary source for Marcellus production. The first joint venture, for which we serve as the operator, in our Butler County, Pennsylvania operating area is with Summit Discovery Resources II, LLC and Sumitomo Corporation. This joint venture covers an area of mutual interest in Butler, Beaver and Lawrence Counties, Pennsylvania. Our working interest in the area of mutual interest is approximately 70.0%. The second joint venture covers 32 specifically identified wells in our Butler County, Pennsylvania operated area between us and AL Marcellus Holdings, LLC (“ArcLight”). ArcLight is participating in these wells at a 35.0% non-operated working interest and does not participate in any of the acreage in the area. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us. The third joint venture covers 33 specifically identified units in our Butler County, Pennsylvania operated area between us and BSP. BSP is participating in these wells at up to a 65.0% non-operated working interest.

As of December 31, 2017, we had under lease approximately 165,300 gross (128,400 net) acres that we believe are prospective for the Utica Shale in Ohio and Pennsylvania. In Ohio, our holdings comprise approximately 13,500 gross (12,200 net) acres which we believe to be prospective for liquids-rich production. In Pennsylvania, we estimate that much of our acreage in Butler County is prospective for dry gas Utica Shale production as well as acreage in some other non-core areas of the state. As of December 31, 2017, we estimate Utica Shale acreage holdings in Pennsylvania of approximately 151,800 gross (116,200 net) acres. During 2017, we drilled 10.0 gross (8.0 net) Utica Shale wells and placed into service 3.0 gross (3.0 net) Utica Shale wells. Our estimated proved reserves related to the Utica Shale as of December 31, 2017, totaled approximately 136.7 Bcfe, including one proved non-producing location with estimated proved reserves of 2.6 Bcfe and seven proved undeveloped locations with estimated proved reserves of 39.7 Bcfe.

We are a party to one joint venture in Ohio that represents our primary source for Utica Shale production. We serve as the operator for this joint venture, which covers 14 specifically identified wells in our Carroll County, Ohio operated area between us and BSP. BSP is participating in these wells at up to a 65.0% working interest. Our average working interest in Carroll County production is approximately 67%.

In January 2017, we sold our interests in 14.0 gross (nine net) wells and 6,300 gross (4,100 net) acres in Belmont, Guernsey and Noble Counties, Ohio, which were part of our joint venture with MFC Drilling, Inc. and ABARTA Oil & Gas Co., Inc., for an approximately $29.0 million in net proceeds.

As of December 31, 2017, we had under lease approximately 132,100 gross (105,100 Net) acres prospective for the liquids-rich Burkett Shale in Pennsylvania. During 2017, we drilled 2.0 gross (1.3 net) Burkett Shale wells and placed into service 4.0 gross (2.0 net) wells. Our estimated proved reserves related to the Burkett Shale as of December 31, 2017 totaled approximately 71.8 Bcfe.

For estimated proved reserves as of December 31, 2017, proved locations were identified, assessed and justified using the evaluation methods of performance analysis, volumetric analysis and analogy. In addition, reliable technologies were used to support a select number of undeveloped locations in the Marcellus and Utica Shale Regions. Within the Marcellus and Utica Shale Regions, we used both public and proprietary geologic data to establish continuity of the formation and its producing properties. This data included performance data, seismic data, micro-seismic analysis, open hole log information and petro-physical analysis of the log data, mud

logs, log cross-sections, gas sample analysis, drill cutting samples, measurements of total organic content, thermal maturity and statistical analysis. In our development area, this data demonstrated consistent and continuous reservoir characteristics.

The following table sets forth our estimated proved reserves as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K. The information in this table is not intended to represent the current market value of our proved reserves nor does it give any effect to our commodity derivatives or current commodity prices.

All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A.—Risk Factors—Risks Relating to Our Company—our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.” You should also read the notes following the table below and our Consolidated Financial Statements for the year ended December 31, 2017 in conjunction with our reserve estimates.

The following table sets forth our estimated proved reserves at the end of each of the past three years:

Changes in PUDs that occurred during the year were all due to extensions and discoveries. There were no costs related to PUD development in 2017.

The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2017:

In our 2016 reserve report, we did not record any proved undeveloped locations. Our 2017 reserve report includes 13.0 gross proved undeveloped locations. At all times, development plans and changes thereto are based on a comprehensive analysis of what we believe to be the most relevant factors in determining such plans. While we do take into consideration NYMEX strip pricing at year end when scheduling future development, for the December 31, 2017 reserve report, we also evaluated additional factors, including but not limited to, the timing of acreage expirations, the need to hold acreage by production, lease commitments, availability and cost of capital, availability of operational resources such as drilling rigs and other services, costs of drilling and related services, infrastructure and takeaway capacity, firm capacity commitments, and overall projected returns. Based on a comprehensive evaluation of these and other relevant factors, we made decisions about initial scheduling and subsequent rescheduling of our development plans. The ultimate objective for every such evaluation and analysis is to align our development and capital expenditures plans to focus on projects that management believes will provide the greatest returns.

Anticipated capital expenditures related to proved undeveloped locations of approximately $45.4 million are significantly higher than in 2015 and 2016. This increase is largely due to the improved commodity price environment, as compared to 2015 and 2016, and the related impact on the economic viability of our proved undeveloped locations as well as our liquidity position. We generally assess the impact of decreases in commodity prices as it relates to our PUD locations, if applicable. As of March 29, 2018, spot commodity prices for oil and natural gas have increased as compared to the SEC pricing in our 2017 reserve report. Price is only one variable in the estimation of our proved reserves, and other factors could have a significant impact on future reserves and the present value of future cash flows, including, but not limited to, extensions and discoveries, changes in costs, drilling results, well performance and changes in our development plans. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods. Any pro forma estimates should not be construed as indicative of our development plans or future results.

The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Steven W. Jansen and Mr. Edward C. Roy III. Mr. Jansen has been practicing consulting petroleum engineering at NSAI since 2011. Mr. Jansen is a Licensed Professional Engineer in the State of Texas and has over four years of prior industry experience. Mr. Roy has been practicing consulting petroleum geology at NSAI since 2008. Mr. Roy is a Licensed Professional Geoscientist in the State of Texas and has over 11 years of prior industry experience. Both technical principals meet or exceed the qualifications, independence, objectivity and confidentiality requirements set forth in the SPE standards; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our estimated proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include documented process workflows, the verification of input data used by NSAI, as well as management review and approval.

All of our reserve estimates are reviewed and approved by our Chief Operating Officer. Our Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering from Marietta University, as well as a Masters of Business Administration from the University of Denver. He has more than 30 years of experience, most recently with Noble Energy, managing their Appalachian Basin assets. In addition to his extensive working experience, our Chief Operating Officer has served as a board member for the Marcellus Shale Coalition and the West Virginia Oil and Natural Gas Association.

The following table sets forth, for our continuing operations, our gross and net acreage of developed and undeveloped oil and natural gas leases and our gross and net productive oil and natural gas wells as of December 31, 2017:

Substantially all of the undeveloped leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed, we have commenced the necessary operations required by the terms of the lease, or we have obtained actual production from acreage subject to the lease, in which event, the lease will remain in effect until the cessation of production.

The following table sets forth, for our continuing operations, the gross and net acres of undeveloped leases that may expire during the periods indicated:

The expiring acreage set forth in the table above accounts for 16.0% of our total net acreage. As of December 31, 2017, we have not assigned any estimated proved reserves to locations which are currently schedule to be drilled after lease expiration. We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address the expiration of undeveloped acreage that occurs in the normal course of our business.

The following table summarizes our drilling activity for continuing operations for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities are conducted on a contract basis by independent drilling contractors. We do not own any drilling equipment.

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, we often conduct a preliminary investigation of record title and related matters at the time of lease acquisition. We conduct more comprehensive mineral title opinion reviews, detailed topographic evaluations and infrastructure investigations before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

The information set forth in Note 23, Litigation, in the notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” is incorporated herein by reference.

Our common stock has been listed on the Nasdaq Capital Market, where it had been listed since December 2016 after previously being listed on the Nasdaq Global Select Market. On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department of Nasdaq indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we requested an appeal before the Nasdaq Hearings Panel. We did not appeal this determination and the time period in which to appeal has lapsed. Following the delisting of our common stock from Nasdaq, our common stock may be eligible for quotation on the OTCBB or OTC Markets Group’s Pink marketplace. Trading on the OTCBB or Pink marketplace may occur only if a market maker applies to quote our common stock and we are current in our reporting obligations under the Securities Exchange Act of 1934. Once our common stock is delisted from Nasdaq, there can be no assurance that a market maker will apply to quote our common stock or that our common stock then will be eligible for quotation on the OTCBB or the Pink marketplace.

As of April 11, 2018, there were approximately 112 holders of record of our common stock.

On May 12, 2017, we effected a one-for-ten reverse stock split. As a result of the reverse stock split, each ten shares of our common stock automatically combined into and became one share of our common stock. Any fractional shares which would have otherwise been due as a result of the reverse split were rounded up to the nearest whole share. As a result of the reverse stock split, we reduced the issued number of common shares from 99.0 million to 9.9 million. The reverse stock split automatically and proportionately adjusted, based on the one-for-ten split ratio, all issued and outstanding shares of our common stock, as well as common stock underlying stock options, warrants and other derivative securities outstanding at the time of the effectiveness of the reverse stock split. The exercise price on outstanding equity based-grants proportionately increased, while the number of shares available under our equity-based plans also was proportionately reduced. Share and per share data for the periods presented reflect the effects of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

The following table sets forth, for the periods indicated, the range of the daily high and low sale prices for our common stock as reported by Nasdaq.

We have not paid cash dividends on our common stock since our inception in March 2007. We do not anticipate paying any dividends on the shares of our common stock in the foreseeable future. We currently intend to retain all future earnings to finance the development of our business. In addition, the terms of our term loan credit facility and the indentures governing our senior notes generally prohibit the payment of cash dividends to holders of our common stock.

The following graph presents a comparison of the yearly percentage change in the cumulative total return on our common stock over the period from January 1, 2013 to December 31, 2017, with the cumulative total return of the S&P 500 index and the Dow Jones U.S. Oil and Gas Exploration and Production Index over the same period. The graph assumes that $100 was invested on January 1, 2012 in our common stock at the closing market price at the beginning of this period and in each of the other two indices, and the reinvestment of all dividends, if any. This historic stock price performance is not necessarily indicative of future stock performance.

The following table shows selected consolidated financial data of Rex Energy Corporation. The historical consolidated financial data has been prepared for Rex Energy Corporation for the years ended December 31, 2017, 2016, 2015, 2014 and 2013. The historical consolidated financial statements for all years presented are derived from the historical audited financial data of Rex Energy Corporation. All material intercompany balances and transactions have been eliminated. This information should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our Consolidated Financial Statements and related notes as of December 31, 2017 and 2016 and for each of the years ended December 31, 2017, 2016 and 2015, included elsewhere in this report. These selected combined historical financial results may not be indicative of our future financial or operating results.

The following tables include the non-GAAP financial measure of EBITDAX. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures.”

	Rex Energy Corporation Consolidated
	Year Ended December 31, ($ in Thousands, Except per Share Data)
	2017			2016			2015			2014			2013
Statement of Operations Data:
Operating Revenue:
Natural Gas, NGL and Condensate Sales	$	205,246		$	139,000		$	138,707		$	225,511		$	139,542
Other Revenue		20			17			42			118			200
Total Operating Revenue		205,266			139,017			138,749			225,629			139,742
Operating Expenses:
Production and Lease Operating Expense		120,794			104,699			93,892			69,547			36,649
General and Administrative Expense		17,858			20,621			26,694			31,917			27,237
(Gain) Loss on Disposal of Assets		(1,428	)		(4,121	)		(540	)		218			104
Impairment Expense		21,383			74,619			283,244			20,225			2,798
Exploration Expense		527			2,178			2,617			6,813			5,915
Depreciation, Depletion, Amortization & Accretion		59,028			62,874			85,844			65,817			38,170
Other Operating Expense		611			10,754			5,603			312			65
Total Operating Expenses		218,773			271,624			497,354			194,849			110,938
Income (Loss) from Operations		(13,507	)		(132,607	)		(358,605	)		30,780			28,804
Other Income (Expense):
Interest Expense		(48,826	)		(43,519	)		(47,783	)		(36,945	)		(22,626	)
Gain (Loss) on Derivatives, Net		(1,347	)		(32,515	)		60,176			38,876			(2,908	)
Other Income (Expense)		(261	)		(2,124	)		(129	)		73			6,694
Debt Exchange Expense		—			(9,063	)		—			—			—
Gain (Loss) on Extinguishments of Debt		(3,029	)		24,627			—			—			—
Loss on Equity Method Investments		—			—			(411	)		(813	)		(763	)
Total Other Income (Expense)		(53,463	)		(62,594	)		11,853			1,191			(19,603	)
Income (Loss) from Continuing Operations Before Income Tax		(66,970	)		(195,201	)		(346,752	)		31,971			9,201
Income Tax Benefit (Expense)		2,728			(2,436	)		(6,030	)		(15,460	)		(2,012	)
Income (Loss) from Continuing Operations		(64,242	)		(197,637	)		(352,782	)		16,511			7,189
Income (Loss) from Discontinued Operations, Net of Income Taxes		—			20,922			(8,251	)		(59,161	)		(7,762	)
Net Loss		(64,242	)		(176,715	)		(361,033	)		(42,650	)		(573	)
Net Income Attributable to Noncontrolling Interests		—			—			2,245			4,039			1,557
Net Loss Attributable to Rex Energy		(64,242	)		(176,715	)		(363,278	)		(46,689	)		(2,130	)
Preferred Stock Dividends		(2,392	)		(5,091	)		(9,660	)		(2,335	)		—
Effect of Preferred Stock Conversions		—			72,984			—			—			—
Net Loss Attributable to Common Shareholders	$	(66,634	)	$	(108,822	)	$	(372,938	)	$	(49,024	)	$	(2,130	)
Earnings per Common Share
Basic - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(16.37	)	$	(66.64	)	$	2.67		$	1.37
Basic - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		—			2.64			(1.93	)		(11.89	)		(1.77	)
Basic - Net Loss Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(13.73	)	$	(68.57	)	$	(9.22	)	$	(0.41	)
Basic - Weighted Average Shares of Common Stock Outstanding		9,902			7,926			5,439			5,315			5,257
Diluted - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(16.37	)	$	(66.64	)	$	2.67		$	1.37
Diluted - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		—			2.64			(1.93	)		(11.89	)		(1.77	)
Diluted - Net Loss Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(13.73	)	$	(68.57	)	$	(9.22	)	$	(0.41	)
Diluted - Weighted Average Shares of Common Stock Outstanding		9,902			7,926			5,439			5,315			5,257

	Year Ended December 31,
	($ in Thousands)
	2017			2016			2015			2014			2013
Cash Flow Data:
Cash provided (used) by operating activities	$	38,488		$	(4,404	)	$	30,885		$	162,706		$	108,316
Cash (used) provided in investing activities		(85,512	)		4,651			(155,446	)		(560,036	)		(313,518	)
Cash provided by financing activities		58,574			2,359			107,556			413,526			163,127
Balance Sheet Data:
Cash and Cash Equivalents		15,247			3,697			1,091			17,978			1,307
Property and Equipment (net of Accumulated Depreciation)		884,352			855,444			951,043			1,108,217			689,659
Total Assets		942,137			893,923			1,071,931			1,378,772			978,579
Current Liabilities, including current portion of long-term debt		834,325			103,708			116,601			170,180			121,026
Long-Term Liabilities		161,374			779,989			795,099			677,219			440,628
Total Liabilities		995,699			883,697			911,700			847,399			561,654
Non-controlling Interests		—			—			—			4,241			2,042
Stockholders' Equity		(53,562	)		10,226			160,231			531,373			416,925
Other Financial Data:
EBITDAX from Continuing Operations¹	$	58,123		$	45,272		$	78,787		$	136,422		$	87,784

The following table summarizes our operating and reserve data as of and for each of the periods indicated for continuing operations. The table includes the non-GAAP financial measure of PV-10. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flow, it’s most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” below.

	2017			2016			2015
Production
Condensate (Bbls)		267,585			360,384			402,867
Natural Gas (Mcf)		41,456,680			44,684,571			44,606,753
C3+ NGLs (Bbls)		1,851,414			1,996,075			2,026,321
Ethane (Bbls)		2,196,050			2,111,321			1,319,582
Mcf Equivalent (Mcfe)		67,346,974			71,491,251			67,099,373
Condensate, NGL and Natural Gas Sales (thousands)
Condensate Sales	$	12,012		$	13,364		$	14,068
Natural Gas Sales	$	113,575		$	73,275		$	83,140
C3+ NGL Sales	$	57,780		$	35,877		$	32,789
Ethane Sales	$	21,879		$	16,484		$	8,710
Total	$	205,246		$	139,000		$	138,707
Average Sales Price (a)
Condensate ($ per Bbl)		44.89		$	37.08		$	34.92
Natural Gas ($ per Mcf)	$	2.74		$	1.64		$	1.86
C3+ NGLs ($ per Bbl)	$	31.21		$	17.97		$	16.18
Ethane ($ per Bbl)	$	9.96		$	7.81		$	6.60
Mcf Equivalent ($ per Mcfe)	$	3.05		$	1.94		$	2.07
Average Production Cost
Mcf Equivalent ($ per Mcfe)		1.79		$	1.46		$	1.40
Estimated Proved Reserves (b)
Bcf Equivalent (Bcfe)		1,032.9			647.8			680.4
% Condensate and NGL		44	%		43	%		40	%
% Proved Producing		86	%		100	%		80	%
Standardized Measure (millions)	$	507.0		$	165.6		$	255.6
PV-10 (millions)	$	541.0		$	175.5		$	300.7

We include in this report our calculations of EBITDAX and PV-10, which are non-GAAP financial measures. Below, we provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure as calculated and presented in accordance with GAAP.

“EBITDAX” means, for any period, the sum of net income (loss) for such period plus the following expenses, charges or income to the extent deducted from or added to net income (loss) in such period: interest, income taxes, gain (loss) on asset sales, depreciation, depletion, amortization, unrealized losses from financial derivatives, the retroactive portion of the Pennsylvania Impact Fee, exploration expenses and other non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income (loss). EBITDAX, as defined above, is used as a financial measure by our management team and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring our performance, nor used as an exclusive measure of cash flow, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and we believe this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.

We believe EBITDAX assists our lenders and investors in comparing a company’s performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Additionally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net income (loss) determined under GAAP and EBITDAX to evaluate our performance.

The following table presents a reconciliation of our net income (loss) to our EBITDAX for each of the periods presented. For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX.

	Year Ended December 31,
	(in thousands)
	2017			2016			2015			2014			2013
Net Income (Loss) from Continuing Operations	$	(64,242	)	$	(197,637	)	$	(352,782	)	$	16,511		$	7,189
Add Back (Less) Non-Recurring Costs (Income)¹		4,257			(6,760	)		4,774			—			—
Add Back Depletion, Depreciation, Amortization and Accretion		59,028			62,874			85,844			65,817			38,170
Add Back Non-Cash Compensation Expense		1,231			3,078			5,791			5,223			4,988
Add Back Interest Expense		48,847			43,519			47,783			36,945			22,626
Add Back Impairment Expense		21,383			74,619			283,244			20,225			2,798
Add Back Exploration Expense		528			2,178			2,617			6,813			5,915
Add Back (Less) (Gain) Loss on Disposal of Asset²		(1,428	)		(4,121	)		(537	)		218			(6,702	)
Add Back (Less) (Gain) Loss on Financial Derivatives		1,347			32,515			(60,176	)		(38,876	)		2,908
Add Back (Less) Cash Settlement of Derivatives		(10,100	)		32,571			55,793			7,281			7,128
Add Back Non-Cash Portion of Equity Method Investments		—			—			406			805			752
Add Back (Less) Income Tax (Benefit) Expense		(2,728	)		2,436			6,030			15,460			2,012
EBITDAX from Continuing Operations	$	58,123		$	45,272		$	78,787		$	136,422		$	87,784
Income (Loss) from Discontinued Operations	$	—		$	20,922		$	(8,251	)	$	(59,161	)	$	(7,762	)
Net Income Attributable to Noncontrolling Interests		—			—			(2,245	)		(4,039	)		(1,557	)
Income (Loss) From Discontinued Operations Attributable to Rex Energy		—			20,922			(10,496	)		(63,200	)		(9,319	)
Add Back Depletion, Depreciation, Amortization and Accretion		—			5,101			18,978			32,353			25,774
Add Back (Less) Non-Cash Compensation Expense (Income)		—			(159	)		659			449			396
Add Back Interest Expense		—			4			510			661			156
Add Back Impairment Expense		—			3,543			62,531			112,460			29,274
Add Back Exploration Expense		—			143			394			2,633			5,590
Add Back (Less) (Gain) Loss on Disposal of Asset³		—			(30,530	)		(57,748	)		371			574
Less Non-Cash Portion of Noncontrolling Interests		—			—			(208	)		(1,738	)		(631	)
Less Income Tax Expense (Benefit)		—			—			(6,030	)		(41,607	)		(4,792	)
EBITDAX from Discontinued Operations	$	—		$	(976	)	$	8,590		$	42,382		$	47,022
EBITDAX	$	58,123		$	44,296		$	87,377		$	178,804		$	134,806

The following table shows the reconciliation of PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 represents our estimate of the present value, discounted at 10% per annum, of estimated future cash flows of our estimated proved reserves before income tax and asset retirement obligations. Our estimated future cash flows as of December 31, 2017, 2016 and 2015, were determined by using reserve quantities of estimated proved reserves and the periods in which they are expected to be developed and produced based on the prevailing economic conditions. The estimated future production for the years ended December 31, 2017, 2016 and 2015, was priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December, without escalation, using $45.62 per Bbl, $36.68 per Bbl and $44.45 per Bbl of oil and condensate, respectively, and $2.793 per MMBtu, $2.264 per MMBtu and $2.401 per MMBtu of natural gas, respectively, as adjusted by lease for transportation fees and regional price differentials. Unadjusted prices for oil and condensate for the years ended December 31, 2017, 2016 and 2015, were $47.79 per Bbl, $39.25 per Bbl and $46.79, respectively. Unadjusted prices for natural gas for the years ended December 31, 2017, 2016 and 2015,

were $2.976 per MMBtu, $2.481 per MMBtu and $2.587 per MMBtu, respectively. NGLs were priced at $16.31 per Bbl, $10.50 per Bbl and $12.48 per Bbl for the years ended December 31, 2017, 2016 and 2015, respectively, as adjusted by lease for transportation fees and regional price differentials. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. PV-10 should not be considered to be a superior measure to the standardized measure of discounted future net cash flows as computed under GAAP.

The following discussion and analysis should be read in conjunction with “Item 6. Selected Financial Data” and the Consolidated Financial Statements and related notes included elsewhere in this report. This discussion contains forward-looking statements reflecting our current expectations and estimates, and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” appearing elsewhere in this report. All financial and operating data presented are the results of continuing operations unless otherwise noted.

We are an independent natural gas, NGL and condensate company operating in the Appalachian Basin. We are focused on our Marcellus Shale, Utica Shale and Burkett Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.

We are headquartered in State College, Pennsylvania and have a regional office in Cranberry, Pennsylvania.

As a result of extremely challenging current market conditions, we believe we will require a significant restructuring of our balance sheet in order to continue as a going concern in the long term. In September 2017, we entered into confidentiality agreements and commenced discussions with legal and financial advisors for the Noteholders, who have represented to the Company that they hold a substantial portion of our outstanding senior notes, to explore one or more possible restructuring, financing, refinancing, reorganization, recapitalization, amendment, waiver, forbearance, asset sale and/or similar transactions involving the Company. Subsequent to the date of the execution of those confidentiality agreements, the Noteholder advisors conducted due diligence on the Company and engaged in discussions with us and our advisors. In early January 2018, we entered into confidentiality agreements with the Noteholders to discuss a possible transaction and subsequently engaged in negotiation with the Noteholders with respect to a potential transaction. We have not yet reached agreement on mutually acceptable terms and conditions with the Noteholders regarding a possible transaction.

The report of the Company’s independent registered public accounting firm that accompanies its audited consolidated financial statements in this Annual Report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

We believe the outlook for our business is favorable despite the continued uncertainty of gas and oil prices and our need for a significant restructuring of our balance sheet. Our resource base, risk management, including an active hedging program, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating areas. We continue to focus on maintaining financial flexibility while pursuing an active, technology-driven drilling program to develop and maximize the value of our existing acreage as market conditions continue to evolve. However, a continued prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserves, and may result in write-downs of the carrying values of our oil and natural gas properties and revisions to our capital budget

or development program. We discuss these matters in further detail under, among other places, “Capital Resources and Liquidity,” and “Volatility of Natural Gas, NGL, and Oil Prices” below as well as in Note 16, Impairment Expense, to our Consolidated Financial Statements.

We have historically divided our operations into two principal business segments, exploration and production and field services. During the third quarter of 2015, we sold Water Solutions and its related subsidiaries, which accounted for the majority of our field services segment. We view the activities of Water Solutions as non-core to our exploration and production operations and used the proceeds from the sale to fund development within our exploration and production operations. Unless otherwise noted, information presented herein is for continuing operations. Our estimated proved reserves account for the sale of our Illinois Basin assets in August 2016 and have not been retroactively restated to remove the associated estimated proved reserves from prior year balances.

Our financial results from exploration and production depend upon many factors, particularly the price of natural gas, NGLs, and condensate. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, refinery or pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of condensate, natural gas and NGLs reserves at economical costs are critical to our long-term success.

In 2017, our daily production decreased by 5.5% year-over-year to 184.5 Mmcfe/day. The decrease in production is primarily due to the sale of our Warrior South assets during the first quarter of 2017. During 2017, we drilled 28.0 gross (20.5 net) wells, placed into service 26.0 gross (15.2 net) wells and ended the year with 11.0 gross (8.0 net) wells in inventory that are awaiting completion. Our development activities included the drilling of 16.0 gross (11.2 net) Marcellus Shale wells, two gross (1.3 net) Burkett Shale wells and 10 gross (8.0 net) Utica Shale wells. During the year, we placed into service 19.0 gross (10.1 net) Marcellus Shale wells, four gross (2.0 net) Burkett Shale wells and three gross (3`.0 net) Utica Shale wells. During 2017, we had a drilling success rate of 100.0%. Our estimated proved reserves increased in 2017 by 59.4% to 1,032.9 Bcfe primarily a result of positive well performance in our Butler, Moraine East and Warrior North assets and an increase in commodity prices during 2017.

In 2016, we grew our daily production by 6.3% year-over-year to 195.3 Mmcfe/day. The increase in production is primarily due to our successes in the Appalachian Basin, particularly the expansion of our core acreage in Butler County, Pennsylvania, where we acquired approximately 208,000 gross (207,000 net) acres from Shell in 2014. Also contributing to our strong production results was further development of our Utica Shale holdings in Ohio. During 2016, we drilled 20.0 gross (8.4 net) wells, placed into service 34.0 gross (16.2 net) wells and ended the year with nine gross (3.8 net) wells in inventory that are awaiting completion. Our development activities included the drilling of 10.0 gross (4.9 net) Marcellus Shale wells, three gross (1.1 net) Burkett Shale wells and seven gross (2.5 net) Utica Shale wells. During the year, we placed into service 20.0 gross (10.8 net) Marcellus Shale wells, one gross (0.4 net) Burkett Shale wells and 13.0 gross (5.1 net) Utica Shale wells. During 2016, we had a drilling success rate of 100.0%. Our estimated proved reserves decreased in 2016 by 4.8% to 647.8 Bcfe primarily as a result of the sale of our Illinois Basin assets and the continued depressed commodity price environment.

In 2015, we grew our daily production by 30.3% year-over-year to 183.8 Mmcfe/day. The increase in production is primarily due to our successes in the Appalachian Basin, particularly our Marcellus Shale exploration and development in Butler County, Pennsylvania and our Utica Shale exploration and development in Ohio. We drilled 34.0 gross (23.0 net) operated wells within the Appalachian Basin, targeting primarily the Marcellus and Utica Shales, including 28.0 gross (17.0 net) operated wells in Butler County, Pennsylvania and six gross (six net) operated wells in Ohio. During 2015, we had a drilling success rate of 100.0%. Our estimated proved reserves decreased in 2015 by 49.1% from 1,336.8 Bcfe at December 31, 2014 to 680.4 Bcfe at December 31, 2015, primarily as a result of the deterioration of the commodity price environment. As of December 31, 2015, we had approximately 383,500 gross (319,700 net) acres in the Appalachian Basin, of which 299,000 gross (272,200 net) acres we believe to be prospective for the liquids-rich portion of the Marcellus and Utica Shales.

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of BSP to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have already been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised their option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million with approximately $134.0 million committed as of December 31,

2017. BSP has paid for their interest in elected wells as of December 31, 2017. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units in which it participates. As of December 31, 2017, 45 of the 45 committed wells were in line and producing.

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our Second Lien Notes and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the Second Lien Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. See Note 11, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of our 1.00/8.00% Senior Secured Second Lien Notes (the “Second Lien Notes’) and (ii) 0.8 million shares of our Common Stock (“Shares”), which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of Second Lien Notes were issued to holders who were ineligible to accept Shares. In addition, upon closing we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The Second Lien Notes bore interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and have borne interest at a rate of 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending on October 1, 2020. In connection with the Exchange, we incurred approximately $9.1 million in third party debt issuance costs during the year ended December 31, 2016. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations.

Following the completion of the Exchange, we entered into debt-for equity exchanges during the remainder of 2016 with certain holders of our Existing Notes, as well as holders of our Second Lien Notes, in which such Existing Notes and Second Lien Notes were exchanged for unrestricted shares of our common stock. These exchanges resulted in the retirement of $27.7 million in aggregate principal amount of our remaining Existing Notes and $45.7 million in aggregate principal amount of our outstanding Second Lien Notes, in exchange for the issuance of a total of approximately 2.3 million shares of unrestricted common stock during the year ended December 31, 2016. In the nine months ended September 30, 2017, we completed debt-for equity exchanges with certain holders of our Existing Notes. These exchanges resulted in the retirement of approximately $0.9 million in aggregate principal amount of our remaining Existing Notes, in exchange for approximately 0.1 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain for the year ended December 31, 2017 of approximately $0.4 million, presented as Gain on Extinguishments of Debt in our Consolidated Statements of Operations.

During 2017, we entered into privately negotiated debt-to-equity exchanges with certain holders of our Existing Notes and Second Lien Notes (together, the “Senior Notes”) in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of approximately $0.9 million in the aggregate of our outstanding Senior Notes, in exchange for the issuance of 83,626 shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain for the year ended December 31, 2017 of approximately $0.4 million, included as a component of Gain (Loss) on Extinguishments of Debt in our Consolidated Statement of Operations for the year ended December 31, 2017.

On April 28, 2017, we entered into a term loan credit agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent, AGES, as collateral agent, Macquarie Bank Limited, as issuing bank, and the lenders from time to time party thereto. The Term Loan replaced our prior amended and restated senior secured revolving credit agreement with Royal Bank of Canada, as Administrative Agent, and the lenders from time to time party thereto (the “Prior Credit Agreement”). The Term Loan provides for a $143,500,000 secured term loan facility (the “Term Facility”) and a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit sub-facility (the “Letter of Credit Sub-facility”). The proceeds of the initial loans under the Term Loan were used to refinance the loans then outstanding under the Prior Credit Agreement and payment of fees and expenses related thereto. The proceeds of future loans under the Delayed Draw Term Facility may be used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes. The maximum commitments of the lenders under the Term Loan are currently limited to $300,000,000. Amounts borrowed under the Term Loan and repaid may not be re-borrowed. The maturity date for the loans under the Term Facility and the loans drawn under the Delayed Draw Term Facility is the earlier of (a) April 28, 2021 and (b) the date that is six months prior to the maturity of our Second Lien Notes

unless less than $25,000,000 in aggregate principal amount of Second Lien Notes are then outstanding and no Event of Default (as defined in the Term Loan) exists on such date. The commitments under the Delayed Draw Term Facility expire if not drawn prior to the earlier of (a) April 28, 2018 (which date may be extended for one year with lender consent) and (b) the date upon which we terminate such commitments. As of December 31, 2017, we had $189.5 million in borrowings outstanding and approximately $32.0 million in outstanding undrawn letters of credit. We incurred approximately $3.5 million in debt issuance costs and $4.3 million in original issue discount (“OID”) related to the initial Term Loan borrowing. We incurred an additional $1.4 million in OID related to the Delayed Draw Term Facility. From April 28, 2017 through December 31, 2017, we amortized $0.7 million of debt issuance costs and $1.0 million of OID. The amortization of debt issuance costs and OID are reported as Interest Expense in our Consolidated Statement of Operations.

On May 20, 2016, we entered into a Purchase and Sale Agreement (“PSA”) with Diversified Oil and Gas, LLC (“DOG”). Pursuant to the PSA, DOG purchased all of our conventional operated oil and gas-related properties and related pipeline assets located in Pennsylvania and assumed all future abandonment liability associated with the assets. Closing occurred on May 20, 2016, with an effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $0.1 million. Included in the sale were approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016, due to the elimination of our future abandonment liability associated with wells and pipelines sold to DOG. The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale.

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell agreed to purchase all of Rex’s oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June 2016 and received additional proceeds of approximately $38.5 million at closing in August 2016. An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up to $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of December 31, 2017, the first five of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds related to those measurement periods. As of December 31, 2017, we have the potential to receive up to $5.4 million of additional proceeds if the WTI exceeds the price per Bbl as specified in the agreement. Proceeds earned for any quarter are payable to us within one year and fifteen days following the end of the quarter in which additional proceeds are earned. For additional information, see Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

Included in the sale were approximately 76,000 net acres in Illinois, Indiana and Kentucky and production of approximately 1,700 net barrels per day. The sale transaction resulted in a full divestiture of our Illinois Basin assets, and an exit from our Illinois Basin operations. As of June 14, 2016, the Illinois Basin assets became classified as “Held for Sale”, and our assets and operations in the Illinois Basin are reported as Discontinued Operations.

On January 11, 2017, we, together with MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc. sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation. These interests comprised our Warrior South development area. The effective date for the transaction is October 1, 2016. The sales agreement includes representations, warranties, covenants and agreements as well as various provisions for purchase price and post-closing adjustments customary for transactions of this type. Total consideration for the transaction was approximately $50.0 million, with approximately $29.1 million net to us, subject to customary closing and post-closing adjustments. We received approximately $24.1 million of proceeds on January 11, 2017. Approximately $5.0 million of the total proceeds due to us was held in escrow, to be released in January 2018 net of post-closing adjustments. The proceeds held in escrow were released to us in December 2017 in the

amount of $5.0 million, net of post-closing adjustments. The sale of assets resulted in a gain on disposal of assets of approximately $1.8 million in January 2017. This gain includes the proceeds initially held in escrow. The sale of assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to us, and approximately 6,200 gross acres, with 4,100 acres net to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down amounts outstanding under our Prior Credit Agreement and for general corporate purposes.

During 2016, 12,013 shares of Series A Preferred Stock were converted into approximately 0.9 million shares of common stock pursuant to the terms of the Series A Preferred Stock and through negotiated exchanges with certain holders of the Series A Preferred Shares. These exchanges are recorded within equity, and do not affect our Net Loss from Continuing Operations. See Note 12, Earnings Per Common Share, to our Consolidated Financial Statements, for additional information regarding the effect of the preferred stock conversions on Net Income (Loss) Attributable to Common Shareholders.

In July 2015, we sold Water Solutions, an entity of which we owned a 60% interest, to American Water Works Company, Inc. for total consideration of approximately $130.0 million, inclusive of cash and debt. We received net proceeds of approximately $66.8 million, resulting in a gain of approximately $57.8 million. We utilized the proceeds from this transaction to help fund development within our core exploration and production areas. In March 2015, we entered into a joint venture agreement with an affiliate of ArcLight to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing. As of December 31, 2015, ArcLight had paid approximately $42.9 million for their interest in wells that have been drilled or are in the process of being drilled.

We generate our revenue primarily from the sale of natural gas, NGLs and condensate. Our operating revenue before the effects of financial derivatives from these operations, and their relative percentages of our total revenue, consisted of the following:

We have identified the impact of generally volatile commodity prices in the last several years as an important trend that we expect to affect our business in the future. If commodity prices increase, we would expect not only an increase in revenue, but also in the competitive environment for quality drilling prospects, qualified geological and technical personnel and oil field services, including rig availability. Increasing competition in these areas would likely result in higher costs in these areas, and could result in unavailability of drilling rigs, thus affecting the profitability of our future operations. We may not be able to compete successfully in the future with larger competitors in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. In the event of a further or extended decline in the commodity price environment, our revenues would decrease and we would anticipate that the cost of materials and services would decrease as well, although at a slower rate. Decreasing oil or natural gas prices may also make some of our prospects uneconomical to drill and some of our producing properties uneconomic to continue to operate.

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include EBITDAX (a non-GAAP measure), lease operating expense per Mcf equivalent (“Mcfe”), growth in our proved reserve base, and general and administrative expense per Mcfe. The following table presents these metrics for continuing operations for each of the three years ended December 31, 2017, 2016 and 2015.

“EBITDAX,” a non-GAAP measure, means, for any period, the sum of net income (loss) for such period plus the following expenses, charges or income (loss) to the extent deducted from or added to net income (loss) in such period: interest, income taxes, gain (loss) on sale of assets, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income (loss). EBITDAX, as defined above, is used as a financial measure by our management team and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:

For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data-Non-GAAP Financial Measures.”

The increase in our EBITDAX from 2016 to 2017 can be primarily attributable to higher commodity prices then in the previous year and a decrease in general and administrative expenses (“G&A”), which has been partially offset by a net cash outflow for the cash settlements of our derivative contracts in 2017, compared to a net cash inflow from the cash settlement of our derivative contracts in 2016. Fluctuations in our EBITDAX are largely predicated by the level of our production and the prevailing commodity prices. Historically, our EBITDAX growth has been commensurate with the growth of our Appalachian Basin operations, where we have been successful in our exploration and development of three producing horizons: the Marcellus, Utica and Burkett Shales. The

majority of our holdings in the Appalachian Basin have a liquids-producing component which, when combined with low operating costs, has enabled us to consistently improve our results.

Production cost per Mcfe measures the average cost of extracting natural gas, NGLs and condensate from our reserves during the period. This measurement is also commonly referred to in the industry as our “lifting cost”. It represents the average cost of extracting one Mcf of natural gas equivalent from our natural gas, condensate and NGL reserves in the ground. Production cost per Mcfe produced in 2017 was $1.79, as compared to $1.46 in 2016 and $1.40 in 2015. Our production costs are largely comprised of variable type costs such as transportation, marketing, processing and gathering. In 2017, transportation, capacity and processing fees accounted for approximately 88.9% of our total Production and Lease Operating Expense, as compared to 87.6% during 2016 and 84.7% during 2015. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. Various agreements that we have entered include firm capacity rights, for which we may incur a fee for unused capacity. As we continue to grow our operations, we expect our lifting cost to decrease as we gain additional efficiencies of scale and utilize all of our firm capacity and transportation commitments.

We measure our ability to grow our estimated proved reserves over the amount of our total annual production. As we produce natural gas, NGLs and condensate attributable to our estimated proved reserves, our estimated proved reserves decrease each year by that amount of production. We attempt to replace these produced estimated proved reserves each year through the addition of new estimated proved reserves through our drilling and other property improvement projects and through acquisitions. Our reserve replacement ratio for year end 2015 was approximately 200% based on total production for the year of 71.5 Bcfe and extensions, discoveries and other additions of 143.0 Bcfe. Our reserve replacement ratio for year end 2016 was approximately 37% based on total production for the year of 71.5 Bcfe, and extensions, discoveries and other additions of 26.4 Bcfe. Our reserve replacement ratio for year end 2017 was approximately 455% based on total production for the year of 68.0 Bcfe, and extensions, discoveries and other additions of 310.0 Bcfe. For 2017, our proved reserve base increased by approximately 59.4%. The increase in our estimated proved reserves is primarily a result of positive well performance in our Butler, Moraine East and Warrior North assets and an increase in commodity prices during 2017. .

Our general and administrative expenses include fees for well operating services, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our production because these expenses have a direct impact on our profitability. In 2017, our general and administrative expenses per Mcfe produced decreased to $0.27 from $0.28 in 2016 and $0.40 in 2015. The decreases are predominately due to further cost control measures and headcount reductions, along with a decrease in legal costs.

In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional natural gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. The fee for each unconventional natural gas well is determined using the following matrix, with vertical unconventional natural gas wells being charged 20% of the applicable rates:

For the years ended December 31, 2017, 2016 and 2015, we incurred approximately $3.6 million, $3.0 million and $3.0 million, respectively, in fees related to the natural gas impact fee. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.

Operating revenue increased 47.7% in 2017 over 2016. This increase was primarily driven by an increase in the average sales price for natural gas, offset partially by a decrease in production. For 2017, total production decreased 5.8% to 67,347 MMcfe from 71,491 MMcfe in 2016. Our average sales price for natural gas, before the effects of derivatives, increased approximately 67.1%, from $1.64 per mcf to $2.74 per mcf.

Operating expenses decreased $52.9 million in 2017, or 19.5%, as compared to 2016. Operating expenses are primarily composed of production expenses, G&A, loss on disposal of assets, exploration expenses, impairment of oil and gas properties and depreciation, depletion, amortization and accretion expenses (“DD&A”). Approximately $53.2 million of this decrease is due to 2016 impairment expense, which is primarily due to the write down of proved and unproved properties as a result of the depressed commodity price environment. As the future outlook for commodity prices became more favorable throughout 2017, the estimated fair value of our assets increased, thus decreasing the effects of impairment. Also contributing to the decrease in operating expenses were lower DD&A Expenses. These decreases were partially offset by an increase in production and lease operating expenses that are commensurate with the increase in producing wells and related production.

Comparison of the Year Ended December 31, 2017 to the Year Ended December 31, 2016

Condensate, NGL and gas revenue for the years ended December 31, 2017 and 2016 is summarized in the following table:

	For the Year Ended December 31,
($ in Thousands, except total Mcfe production and price per Mcfe)	2017			2016			Change			%
Condensate, NGL and Gas Revenue:
Condensate sales revenue	$	12,012		$	13,364		$	(1,352	)		-10.1	%
Oil and condensate derivatives realized (a)		278			1,644			(1,366	)		-83.1	%
Total condensate revenue and derivatives realized		12,290			15,008			(2,718	)		-18.1	%
Gas sales revenue		113,575			73,275			40,300			55.0	%
Gas derivatives realized (a)		1,360			26,348			(24,988	)		-94.8	%
Total gas revenue and derivatives realized		114,935			99,623			15,312			15.4	%
C3+ NGL sales revenue		57,780			35,877			21,903			61.1	%
C3+ NGL derivatives realized (a)		(11,783	)		4,914			(16,697	)		-339.8	%
Total C3+ NGL revenue and derivatives realized		45,997			40,791			5,206			12.8	%
Ethane sales revenue		21,879			16,484			5,395			32.7	%
Ethane derivatives realized (a)		45			(14	)		59			-421.4	%
Total ethane revenue and derivatives realized		21,924			16,470			5,454			33.1	%
Consolidated sales		205,246			139,000			66,246			47.7	%
Consolidated derivatives realized (a)		(10,100	)		32,892			(42,992	)		-130.7	%
Total condensate, NGL and gas revenue and derivatives realized	$	195,146		$	171,892		$	23,254			13.5	%
Total Mcfe Production		67,346,974			71,491,251			(4,144,277	)		-5.8	%
Average Realized Price per Mcfe, including the effects of derivatives	$	2.90		$	2.40		$	0.49			20.5	%

Average realized price received for natural gas, condensate and NGLs during 2017, after the effect of derivative activities, was $2.90 per Mcfe, an increase of 20.5%, or $0.50 per Mcfe, from 2016. This increase was primarily due to an increase in natural gas prices offset partially by a decrease in derivative settlements during the year. The average price for natural gas, after the effect of derivative activities, increased 24.4%, or $0.54 per Mcf, to $2.77 per Mcf. The average price for condensate, after the effect of derivative activities, increased 10.3%, or $4.29 per barrel, to $45.93 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, increased 21.6%, or $4.40 per barrel, to $24.84 per barrel. The average price for ethane, after the effect of derivative activities, increased 28.0% or $2.18 per barrel, to $9.98 per barrel. Our derivative activities effectively decreased net realized prices by $0.15 per Mcfe in 2017 and increased net realized prices $0.46 per Mcfe in 2016.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.22 per Mcf during 2017, primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Gulf Coast, which receive Henry Hub NYMEX pricing. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast, including transportation of 100,000 Mcf per day to the Gulf Coast that began during the fourth quarter of 2016.

Production volumes for 2017 decreased 5.8%, or 4.1 Bcfe, from 2016 primarily due to the sale of our Warrior South assets during the first quarter of 2017. Natural gas production was down 7.2%, while our ethane production increased approximately 4.0%.

Our condensate and C3+ NGL production were down 25.8% and 7.2%, respectively, year-over-year. The product blend is optimized for pricing and demand conditions.

Overall, our production for 2017 averaged approximately 184.5 Mmcfe per day, of which 61.6% was attributable to natural gas, 2.4% was attributable to condensate, 16.5% was attributable to C3+ NGLs and 19.6% was a result of ethane production.

Statements of Operations for the years ended December 31, 2017 and 2016 are as follows:

	For the Year Ended December 31,
($ in Thousands)	2017			2016			Change			%
Statement of Operations Data:
Operating Revenue:
Natural Gas, NGL and Condensate Sales	$	205,246		$	139,000		$	66,246			47.7	%
Other Revenue		20			17			3			17.6	%
Total Operating Revenue		205,266			139,017			66,249			47.7	%
Operating Expenses:
Production and Lease Operating Expense		120,794			104,699			16,095			15.4	%
General and Administrative Expense		17,858			20,621			(2,763	)		-13.4	%
Gain on Disposal of Assets		(1,428	)		(4,121	)		2,693			-65.3	%
Impairment Expense		21,383			74,619			(53,236	)		-71.3	%
Exploration Expense		527			2,178			(1,651	)		-75.8	%
Depreciation, Depletion, Amortization & Accretion		59,028			62,874			(3,846	)		-6.1	%
Other Operating Expense		611			10,754			(10,143	)		-94.3	%
Total Operating Expenses		218,773			271,624			(52,851	)		-19.5	%
Loss from Operations		(13,507	)		(132,607	)		119,100			-89.8	%
Other Income (Expense):
Interest Expense		(48,826	)		(43,519	)		(5,307	)		12.2	%
Loss on Derivatives, Net		(1,347	)		(32,515	)		31,168			-95.9	%
Other Expense		(261	)		(2,124	)		1,863			-87.7	%
Debt Exchange Expense		—			(9,063	)		9,063			-100.0	%
Gain (Loss) on Extinguishment of Debt		(3,029	)		24,627			(27,656	)		-112.3	%
Total Other Expense		(53,463	)		(62,594	)		9,131			-14.6	%
Loss from Continuing Operations Before Income Tax		(66,970	)		(195,201	)		128,231			-65.7	%
Income Tax Benefit (Expense)		2,728			(2,436	)		5,164			-212.0	%
Loss from Continuing Operations		(64,242	)		(197,637	)		133,395			-67.5	%
Income from Discontinued Operations, Net of Income Taxes		—			20,922			(20,922	)		-100.0	%
Net Loss		(64,242	)		(176,715	)		112,473			-63.6	%
Preferred Stock Dividends		(2,392	)		(5,091	)		2,699			-53.0	%
Effect of Preferred Stock Conversions		—			72,984			(72,984	)		-100.0	%
Net Loss Attributable to Common Shareholders	$	(66,634	)	$	(108,822	)	$	42,188			-38.8	%

Production and Lease Operating Expense increased approximately $16.1 million, or 15.4%, in 2017 from 2016. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 88.9% of our total Production and Lease Operating Expense in 2017, as compared to 87.6% from 2016. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs increased to $1.79 per Mcfe in 2017 from $1.46 per Mcfe in 2016. The increase on a per unit basis is related to the commencement of our Gulf Coast transportation agreement, which carries a higher transportation cost to access pricing that is premium to the northeast markets.

General and Administrative Expense of approximately $17.9 million for 2017 decreased approximately $2.8 million, or 13.4%, from 2016. The decrease was mostly due to a decrease in transactional fees associated with BSP transaction of $0.4 million during 2017 as compared to $1.4 million during 2016. Also contributing to the decrease in G&A was the forfeiture of restricted stock, which reduced expense by approximately $1.8 million. We do not expect any significant changes to our G&A expenditures in 2018.

Gain on Disposal of Assets decreased approximately $2.7 million in 2017 from 2016. The gain was generated primarily by the sale of our Warrior South assets in the Appalachian Basin.

Impairment Expense decreased to $21.4 million in 2017 from $74.6 million in 2016, a decrease of 71.3%. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). Approximately $9.9 million of the impairment incurred during 2017 was attributable to unconventional proved properties in the Appalachian Basin. In addition, we also incurred approximately $11.5 million in unproved property impairments for leases that expired or are expected to expire without being developed, of which approximately $7.8 million was related to leases in Butler County, Pennsylvania and Ohio and approximately $3.2 million was attributable to non-operated Marcellus leases. The impairments were identified through an analysis of market conditions and future development plans that were in existence throughout 2017, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. The primary reason for the decrease in the estimated future cash flows of our assets is attributable to the depressed estimated future commodity prices during 2017. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices were to decline, which may result in our incurrence of additional impairment expense. As of December 31, 2017, we continued to carry the costs of unproved properties of approximately $186.5 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

To quantify the impact of continued low commodity prices or further declines in future prices, as of December 31, 2017, approximately 81.7% of the carrying value of our evaluated oil and natural gas properties were located in Butler County, Pennsylvania. As of December 31, 2017, estimated future cash flows for these properties were such that substantial further decreases in commodity prices, combined with a lack of access to capital or detrimental changes to costs or operating efficiencies, would need to occur for us to experience a write-down with respect to these properties. The remaining evaluated properties that are outside of Butler County, Pennsylvania are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated properties total approximately $117.3 million.

Approximately $28.3 million of the impairment incurred during 2016 was attributable to unconventional proved properties and other fixed assets, of which approximately $25.8 million was attributable to assets acquired from Shell in 2014. In addition, we also incurred approximately $46.3 million in unproved property impairments related to leases that will not be developed.

Exploration Expense for 2017 was approximately $0.5 million, as compared to $2.2 million from 2016. Approximately $0.4 million of the expense incurred in 2017 was due to geological and geophysical type expenditures, $0.1 million was due to payment of delay rentals. Approximately $1.1 million of the expense incurred in 2016 was due to geological and geophysical type expenditures, $0.2 million was due to payment of delay rentals, and $0.9 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. As a result of the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

Depletion, Depreciation, Amortization and Accretion Expense for 2017 decreased approximately $3.8 million, or 6.1%, from $62.9 million in 2016. Contributing to the decrease in DD&A expense was an overall decrease in production, including the sale of our Warrior South assets in the first quarter of 2016.

Other Operating Expense for 2017 decreased to approximately $0.6 million from $10.8 million in 2016. The expense in 2016 was primarily related to a firm transportation contract associated with an area west of our core assets in Butler County, Pennsylvania. During the third quarter of 2016, we elected to cease all future development activities in the area associated with this contract and recorded $8.3 million to Other Operating Expense, representing the expense equal to the present value of our full future obligations under the contract.

Interest Expense for 2017 was approximately $48.8 million as compared to $43.5 million from 2016. The increase in interest expense is primarily due to interest charges incurred on the term loan and fees charged on available but undrawn borrowing base of the Term Loan Delayed Draws established in April 2017 and a decrease in interest expense capitalized to evaluated properties in 2017, offset partially by the reduced bond interest expense as a result of the Senior Notes exchange completed on March 31, 2016. We discuss our Senior Notes and Term Loan facility in Note 9, Long-Term Debt, to our Consolidated Financial Statements.

Gain (Loss) on Derivatives, net included a loss of approximately $1.3 million for 2017 as compared to a loss of approximately $32.5 million from 2016. The loss recorded for 2017 included cash payments for commodity derivatives of $10.1 million while the loss incurred in 2016 included cash receipts for commodity derivatives of approximately $32.5 million. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and natural gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of condensate, NGL and gas production volumes given the highly volatile oil, NGL and gas commodities market.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for 2018, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Debt Exchange Expense for 2017 were zero as compared to $9.1 million for 2016. These charges relate to our exchange of Existing Notes for Second Lien Notes completed on March 31, 2016. We accounted for the exchange as a troubled debt restructuring, which mandates that current third-party expenses be charged against income in the current period.

Gain (Loss) on Extinguishment of Debt for 2017 totaled a loss of approximately $3.0 million. The loss in 2017 reflects the write-off of approximately $3.4 million of unamortized debt issuance costs related to the Prior Credit Facility retired in April 2017, offset by approximately $0.4 million in gains from debt to equity exchanges completed in the nine months ended September 30, 2017. Gain on extinguishments of debt for 2016 totaled approximately $24.1 million, resulting from debt to equity exchanges with certain holders of our Senior Notes. We discuss the debt to equity exchanges in Note 9, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Benefit (Expense) for 2017 was a benefit of approximately $2.7 million as compared to an expense of $2.4 million in 2016. A full valuation allowance has been recorded against net deferred tax assets at December 31, 2017. However, the tax benefit is being recorded to reverse the $2.0 million in Federal and $0.6 million in state taxes accrued in 2016 and to expose a $0.1 million deferred asset to account for changes to the U.S. tax code. Refer to Note 11, Income Taxes, to our Consolidated Financial Statements for additional information regarding income taxes.

Preferred Stock Dividends for 2017 totaled approximately $1.8 million of dividends paid as compared to $5.1 million of dividends in arrears in 2016. During 2016, 12,113 shares of Series A Preferred Stock were converted to shares of our common stock in accordance with the terms of the Series A Preferred Stock, resulting in a reduction in the amount of dividends due. On January 20, 2016, we announced that we had suspended payment of our quarterly dividend on shares of our Series A Preferred Stock. During 2017 we resumed payment of the quarterly dividends on the Series A Preferred Stock.

Net Loss Attributable to Rex Energy Common Shareholders for the year ended December 31, 2017 was approximately $66.6 million, as compared to a loss of $108.8 million for 2016 as a result of factors discussed above.

Comparison of the Year Ended December 31, 2016 to the Year Ended December 31, 2015

Condensate, NGL and gas revenue for the years ended December 31, 2016 and 2015 is summarized in the following table:

	For the Year Ended December 31,
($ in Thousands, except total Mcfe production and price per Mcfe)	2016			2015		Change			%
Condensate, NGL and Gas Revenue:
Condensate sales revenue	$	13,364		$	14,068	$	(704	)		-5.0	%
Oil derivatives realized (a)		1,644			11,860		(10,216	)		-86.1	%
Total condensate revenue and derivatives realized		15,008			25,928		(10,920	)		-42.1	%
Gas sales revenue		73,275			83,140		(9,865	)		-11.9	%
Gas derivatives realized (a)		26,348			32,573		(6,225	)		-19.1	%
Total gas revenue and derivatives realized		99,623			115,713		(16,090	)		-13.9	%
C3+ NGL sales revenue		35,877			32,789		3,088			9.4	%
C3+ NGL derivatives realized (a)		4,914			10,384		(5,470	)		-52.7	%
Total C3+ NGL revenue and derivatives realized		40,791			43,173		(2,382	)		-5.5	%
Ethane sales revenue		16,484			8,710		7,774			89.3	%
Ethane derivatives realized (a)		(14	)		42		(56	)		-133.3	%
Total ethane revenue and derivatives realized		16,470			8,752		7,718			88.2	%
Consolidated sales		139,000			138,707		293			0.2	%
Consolidated derivatives realized (a)		32,892			54,859		(21,967	)		-40.0	%
Total condensate, NGL and gas revenue and derivatives realized	$	171,892		$	193,566	$	(21,674	)		-11.2	%
Total Mcfe Production		71,491,251			67,099,373		4,391,878			6.5	%
Average Realized Price per Mcfe, including the effects of derivatives	$	2.40		$	2.88	$	(0.48	)		-16.7	%

Average realized price received for natural gas, condensate and NGLs during 2016, after the effect of derivative activities, was $2.40 per Mcfe, a decrease of 16.7%, or $0.48 per Mcfe, from 2015. This decrease was primarily due to a decrease in natural gas prices and a decrease in derivative settlements during the year. The average price for natural gas, after the effect of derivative activities, decreased 14.1%, or $0.36 per Mcf, to $2.23 per Mcf. The average price for condensate, after the effect of derivative activities, decreased 35.3%, or $22.71 per barrel, to $41.64 per barrel. The average price for C3+ NGLs, after the effect of derivative activities, decreased 4.1%, or $0.87 per barrel, to $20.44 per barrel. The average price for ethane, after the effect of derivative activities, increased 17.6% or $1.17 per barrel, to $7.80 per barrel. Our derivative activities effectively increased net realized prices by $0.46 per Mcfe in 2016 and $0.82 per Mcfe in 2015.

Our realized sales price for natural gas differed from the average Henry Hub NYMEX pricing by approximately $0.91 per Mcf during 2016 primarily due to basis differentials in the northeastern United States, which were partially offset by sales on the Texas Eastern pipeline receiving M3 pricing, a New York area index. We have been able to stabilize the impact of basis differentials to an extent by utilizing basis swaps in our derivatives program. In addition, we have been targeting sales points outside of the northeastern United States and have executed capacity agreements to transport natural gas volumes to the Midwest and the Gulf Coast. Transportation of 100,000 Mcf per day to the Gulf Coast began during the fourth quarter of 2016. The volumes to the Gulf Coast are expected to increase to 130,000 Mcf per day beginning in the second quarter of 2017.

Production volumes for 2016 increased 6.5%, or 4.4 Bcfe, from 2015 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities in the liquids-rich portions of our acreage holdings. Natural gas production was relatively flat while our ethane production increased approximately 60.0%. Our condensate and C3+ NGL production were down 10.5% and 1.5%, respectively, year-over-year. Natural gas production only slightly increased due to related increases in ethane production volumes, as the amount of ethane extraction from produced natural gas is controlled at the processing plant. The product blend is optimized for pricing and demand conditions.

Overall, our production for 2016 averaged approximately 195.9 Mmcfe per day, of which 62.5% was attributable to natural gas, 3.0% was attributable to condensate, 16.8% was attributable to C3+ NGLs and 17.7% was a result of ethane production.

Statements of Operations for the years ended December 31, 2016 and 2015 are as follows:

	For the Year Ended December 31,
($ in Thousands)	2016			2015			Change			%
Statement of Operations Data:
Operating Revenue:
Natural Gas, NGL and Condensate Sales	$	139,000		$	138,707		$	293			0.2	%
Other Revenue		17			42			(25	)		-59.5	%
Total Operating Revenue		139,017			138,749			268			0.2	%
Operating Expenses:
Production and Lease Operating Expense		104,699			93,892			10,807			11.5	%
General and Administrative Expense		20,621			26,694			(6,073	)		-22.8	%
Gain on Disposal of Assets		(4,121	)		(540	)		(3,581	)		663.1	%
Impairment Expense		74,619			283,244			(208,625	)		-73.7	%
Exploration Expense		2,178			2,617			(439	)		-16.8	%
Depreciation, Depletion, Amortization & Accretion		62,874			85,844			(22,970	)		-26.8	%
Other Operating Expense		10,754			5,603			5,151			91.9	%
Total Operating Expenses		271,624			497,354			(225,730	)		-45.4	%
Loss from Operations		(132,607	)		(358,605	)		225,998			-63.0	%
Other Income (Expense):
Interest Expense		(43,519	)		(47,783	)		4,264			-8.9	%
Gain (Loss) on Derivatives, Net		(32,515	)		60,176			(92,691	)		-154.0	%
Other Expense		(2,124	)		(129	)		(1,995	)		1546.5	%
Debt Exchange Expense		(9,063	)		—			(9,063	)		100.0	%
Gain on Extinguishment of Debt		24,627			—			24,627			100.0	%
Loss on Equity Method Investments		—			(411	)		411			-100.0	%
Total Other Income (Expense)		(62,594	)		11,853			(74,447	)		-628.1	%
Loss from Continuing Operations Before Income Tax		(195,201	)		(346,752	)		151,551			-43.7	%
Income Tax Expense		(2,436	)		(6,030	)		3,594			-59.6	%
Loss from Continuing Operations		(197,637	)		(352,782	)		155,145			-44.0	%
Income (Loss) from Discontinued Operations, Net of Income Taxes		20,922			(8,251	)		29,173			-353.6	%
Net Loss		(176,715	)		(361,033	)		184,318			-51.1	%
Net Income Attributable to Noncontrolling Interests		-			2,245			(2,245	)		-100.0	%
Net Loss Attributable to Rex Energy		(176,715	)		(363,278	)		186,563			-51.4	%
Preferred Stock Dividends		(5,091	)		(9,660	)		4,569			-47.3	%
Effect of Preferred Stock Conversions		72,984			—			72,984			100.0	%
Net Loss Attributable to Common Shareholders	$	(108,822	)	$	(372,938	)	$	264,116			-70.8	%

Production and Lease Operating Expense increased approximately $10.8 million, or 11.5%, in 2016 from 2015. We experienced Production and Lease Operating Expense increases that are commensurate with the increase in producing wells and related production as they relate to variable type costs such as transportation, marketing, processing and gathering. Transportation, marketing, processing and gathering fees accounted for approximately 87.6% of our total Production and Lease Operating Expense in 2016, as compared to 84.7% from 2015. As we continue to develop our core areas of operation we expect that fees incurred from unutilized commitments will decrease. These types of agreements typically have a term of several years and we expect fees associated with these agreements to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per-unit of production basis, our lifting costs increased to $1.46 per Mcfe in 2016 from $1.40 per Mcfe in 2015. Contributing to this increase was the commencement of our Gulf Coast transportation in November which carries a heavier transportation cost but receives improved pricing over the local northeastern markets. We expect that if commodity prices continue to increase the cost of field services will increase as well.

General and Administrative Expense of approximately $20.3 million for 2016 decreased approximately $6.4 million, or 23.9%, from 2015. We implemented several cost control measures during 2016, including reductions in bonus compensation, reductions in head count, a decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers. During the first quarter of 2016, the board of directors approved certain performance factors for restricted stock that vested in March 2016. These performance factors resulted in reduced expense due to forfeitures on performance-based restricted stock awards of approximately $1.6 million. We do not expect any significant changes to our G&A expenditures in 2017.

Gain on Disposal of Assets increased approximately $3.6 million in 2016 from 2015. The gain was generated primarily by elimination of our future abandonment liability associated with the sale of our operated conventional gas wells and pipelines in the Appalachian Basin.

Impairment Expense decreased to $74.6 million in 2016 from $283.2 million in 2015, a decrease of 73.7%. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). Approximately $28.3 million of the impairment incurred during 2016 was attributable to proved properties and other fixed assets, of which approximately $25.8 million was attributable to assets acquired from Shell in 2014. These assets, which are primarily comprised of wells in various stages of drilling, are no longer being contemplated in our future plans. In addition, we also incurred approximately $46.3 million in unproved property impairments, all of which was related to leases in the Appalachian Basin and consists of leases that have expired, or will expire, prior to development. The impairments were identified through an analysis of market conditions and future development plans that were in existence various stages throughout 2016, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. The primary reason for the decrease in the estimated future cash flows of our assets is attributable to the continued depression of current and estimated future commodity prices at the date when the impairments were identified. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices continue to decline, which may result in our incurrence of additional impairment expense. As of December 31, 2016, we continued to carry the costs of unproved properties of approximately $215.8 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

To quantify the impact of continued low commodity prices or further declines in future prices, as of December 31, 2016, approximately 81% of the carrying value of our evaluated oil and natural gas properties were located in Butler County, Pennsylvania. As of December 31, 2016, estimated future cash flows for these properties were such that substantial further decreases in commodity prices, combined with a lack of access to capital or detrimental changes to costs or operating efficiencies, would need to occur for us to experience a write-down with respect to these properties. The remaining evaluated properties that are outside of Butler County, Pennsylvania are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated properties total approximately $115.5 million.

Approximately $223.6 million of the impairment incurred during 2015 was attributable to proved properties and other fixed assets, of which approximately $204.6 million was attributable to unconventional assets in the Appalachian Basin and $17.5 million was attributable to our equity method investment in RW Gathering. The remaining proved property impairment expense was related to out conventional dry gas assets and salt water disposal well in the Appalachian Basin. In addition, we also incurred approximately $59.6 million in unproved property impairments related to leases that will not be developed.

Exploration Expense for 2016 was approximately $2.2 million, as compared to $2.6 million from 2015. Approximately $1.1 million of the expense incurred in 2016 was due to geological and geophysical type expenditures, $0.2 million was due to payment of delay rentals and $0.9 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. Approximately $1.0 million of the expense incurred in 2015 was due to geological and geophysical type expenditures, $1.4 million was due to payment of delay rentals, and $0.2 million was due to costs associated with exploratory wells that were abandoned at various stages, resulting in dry hole expense. As a result of the decrease in commodity prices, we have decreased our levels of spending with regards to geological and geophysical activities.

Depletion, Depreciation, Amortization and Accretion Expense for 2016 decreased approximately $23.0 million, or 26.8%, from $85.8 million from 2015. Contributing to the decrease in DD&A expense were lower first quarter depreciable asset values from the impact of 2015 impairments, partially offset by lower 2015 year end reserves, which were triggered by the ongoing lower commodity pricing environment and the related effect on our estimated proved reserves, when compared to 2015.

Other Operating Expense for 2016 increased to approximately $10.8 million from $5.6 million in 2015. The expense in 2016 is primarily related to a firm transportation contract associated with an area west of our core assets in Butler County, Pennsylvania. During the third quarter of 2016, we elected to cease all future development activities in the area associated with this contract and recorded $8.3 million to Other Operating Expense, representing the expense equal to the present value of our full future obligations under the contract. During 2015, in addition to $0.5 million in unutilized firm capacity commitments, we incurred rig termination charges of approximately $4.8 million for the cancellation of drilling rig contracts before expiration of their original term.

Interest Expense for 2016 was approximately $43.5 million as compared to $47.8 million from 2015. The decrease in interest expense is primarily due to several debt for equity exchanges completed during the year. The decrease is partially offset by increased amortization of bond costs as a result of the Senior Notes exchange, and increased interest expense due to increased borrowing on our prior revolving credit facility. We discuss our Senior Notes and prior revolving credit facility in Note 9, Long-Term Debt, to our Consolidated Financial Statements.

Gain (Loss) on Derivatives, net included a loss of approximately $32.5 million for 2016 as compared to a gain of approximately $60.2 million from 2015. The loss recorded for 2016 included cash receipts for commodity derivatives of $32.5 million while the gain incurred in 2015 included cash receipts of approximately $55.8 million for commodity and interest rate derivatives. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices along with changes in our portfolio of outstanding derivatives. Losses from derivative activities generally reflect higher oil, NGL and natural gas prices in the marketplace than were in effect at the end of the last period while gains generally reflect the opposite. Our derivative program is designed to provide us with greater reliability of future cash flows at expected levels of condensate, NGL and gas production volumes given the highly volatile oil, NGL and gas commodities market.

We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for 2016 and 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Debt Exchange Expense for 2016 totaled approximately $9.1 million. These charges relate to our exchange of Existing Notes for Second Lien Notes completed on March 31, 2016. We accounted for the exchange as a troubled debt restructuring, which mandates that current third-party expenses be charged against income in the current period.

Gain on Extinguishment of Debt for 2016 totaled approximately $24.6 million. The gain resulted from debt to equity exchanges under troubled debt restructuring rules with certain holders of our outstanding Existing Notes, wherein approximately $30.9 million of outstanding Existing Notes were reacquired by the company in exchange for an aggregate of approximately 6.7 million shares of our common stock. We discuss the debt to equity exchanges in Note 9, Long-Term Debt, to our Consolidated Financial Statements.

Income Tax Expense for 2016 was approximately $2.4 million as compared to $6.0 million in 2015. Though a full valuation allowance has been recorded against net deferred tax assets at December 31, 2016, tax expense is being recorded in continuing operations due to a charge for alternative minimum tax with no corresponding deferred tax benefit on minimum tax credit carryforwards due to the full valuation allowance, and state taxes in certain tax paying jurisdictions. Our alternative minimum tax expected to be due for 2016 is primarily driven by cancellation of debt income of $543.2 million related to the Senior Note exchange discussed in Note 9, Long-Term Debt, to our Consolidated Financial Statements. Refer to Note 11, Income Taxes, to our Consolidated Financial Statements for additional information regarding income taxes.

Preferred Stock Dividends for 2016 totaled approximately $5.1 million of dividends in arrears as compared to $9.7 million of dividends paid in 2015. During 2016, 12,113 shares of Series A Preferred Stock were converted to shares of our common stock in accordance with the terms of the Series A Preferred Stock, resulting in a reduction in the amount of dividends due. On January 20, 2016, we announced that we had suspended payment of our quarterly dividend on shares of our Series A Preferred Stock; we have not paid a quarterly dividend since that date. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment or suspension of the dividend on a quarterly basis.

Net Loss Attributable to Rex Energy Common Shareholders for the year ended December 31, 2016 was approximately $108.8 million, as compared to a loss of $372.9 million for 2015 as a result of factors discussed above.

On April 28, 2017, we entered into the Term Loan and subsequently terminated and repaid amounts outstanding under our Prior Credit Agreement (for additional information, see Note 9, Long Term Debt, to our Consolidated Financial Statements).

Our primary financial resource is our base of natural gas, NGLs and condensate reserves. During 2017, we spent approximately $117.2 million of capital on drilling projects, facilities and related equipment and acquisitions of acreage. Our 2017 capital program was funded with net cash flow from operations, borrowings under our Term Loan, and the sale of our Warrior South assets. Offsetting some of the cost associated with our capital expenditure program in 2017 were our joint ventures with ArcLight and BSP. Our 2018 capital expenditure plan of between $78.0 million and $83.0 million is expected to be funded primarily by cash flow from operations, joint venture proceeds, non-core asset sales and borrowings under our term loan credit facility.

Our cash flows from operations are driven by commodity prices and production volumes. Prices for natural gas, NGLs and condensate are driven by, among other things, seasonal influences of weather, national and international economic and political environments and, increasingly, from national and global supply and demand for hydrocarbons. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, we have funded our capital program with cash flows from operations, borrowings under our Term Loan and net proceeds from debt and equity offerings have been used to fund exploration and development of our oil and gas interests. As of December 31, 2017, we had approximately $15.2 million of cash on hand. As of December 31, 2017, outstanding borrowings under our Term Loan were $189.5 million with an additional $32.2 million of undrawn letters of credit. As of December 31, 2017, we had approximately $78.3 million of undrawn availability on the Term Loan.

Our ability to fund our capital expenditures is dependent upon the level of commodity prices and the success of our exploration program in replacing existing natural gas, NGL and condensate reserves. If commodity prices decrease, operating cash flows may decrease, which could reduce funds available to fund our capital expenditure program. The effects of commodity prices on cash flows can be mitigated through the use of commodity derivatives. If we are unable to replace our natural gas, NGL and condensate reserves through acquisition, and our development and exploration programs, we may also suffer a reduction in operating cash flows and access to funds under our Term Loan. We expect to be in compliance with all required debt covenants for at least the twelve month period following the filing date of our Form 10-K report for the year ended December 31, 2017.

Due to the depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Preferred Stock. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. In April and July 2017, we declared a quarterly dividend of $0.6 million, based on $150.00 per share on our Series A Preferred Stock ($1.50 per depositary share, each representing 1/100 interest in a share of Preferred Stock) payable on May 15, 2017 and August 15, 2017, respectively; each dividend payment was applied to the earliest dividend in arrears at the time of payment. In October 2017, we declared a quarterly dividend in the same amount; this dividend was paid in stock on November 15, 2017, and was applied to the earliest dividend still in arrears at the time of payment. Any subsequent quarterly dividends declared and paid will be applied to the earliest dividend then in arrears until the arrearage is satisfied and dividends are current. As a result of having dividends in arrears on our Series A Preferred Stock, we are not currently eligible to use Form S-3 registration statements. Until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register public offerings of securities with the SEC (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital.

We have outstanding Senior Notes that are governed by indentures with substantially similar terms and provisions (the “Indentures”). The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on the ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or sell substantially all of its assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including the ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25:1. As of December 31, 2017, the Company’s Fixed Charge Coverage Ratio was 1.10:1. We expect our Fixed Charge Coverage Ratio to be in compliance for the foreseeable future. As of December 31, 2017, we were limited to incurring an additional $161.5 million in additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the Trustee or the holders of our outstanding senior notes may declare all such outstanding senior notes to be due and payable immediately.

In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay fees in connection with these agreements of $243.5 million over the next five years, depending on our levels of production. Also in connection with certain of these agreements, we have guaranteed the payment of obligations up to a maximum of $377.2 million over the life of the agreements, which range from two to 20 years. As the commitments are satisfied, these guarantees will decrease over time. For additional information on our commitments and guarantees, see Note 7, Commitments and Contingencies, to our Consolidated Financial Statements.

Our Term Loan contains a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. Our financial covenants require us to maintain a maximum “Ratio of Net Senior Secured Debt to EBITDAX” of 3.25 to 1.0, a minimum “Ratio of EBITDAX to Interest Expense” of 1.0 to 1.0, increasing to 1.3 to 1.0 for quarterly periods ending on or after March 31, 2018 and a minimum “PDP Coverage Ratio” of 1.65 to 1.00. Failure to comply with these covenants could have a material adverse effect on our business because it would restrict our ability to make additional delayed draw term loan borrowings and could cause an event of default under our Term Loan. As of December 31, 2017, our Net Senior Secured Debt to EBITDAX Ratio was 3.00 to 1.00, our ratio of EBITDAX to Cash Interest Expense was 2.60 to 1.00, and our PDP Coverage Ratio was 2.63 to 1.00. If an event of default under our Term Loan occurs and remains uncured, among other things, the lenders thereunder:

In order to improve our liquidity positions to meet the financial requirements under our Term Loan and to meet other outstanding obligations, we are currently pursuing a restructuring of our balance sheet. We continue to consider a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, including (i) debt-for-debt or debt-for-equity exchanges, (ii) joint venture opportunities, (iii) minimizing capital expenditures, (iv) improving cash flows from operations, (v) effectively managing working capital, (vi) adding hedging positions, (vii) asset sales, and (viii) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from any one or more of these transactions or that these transactions can be consummated within the period needed to meet our obligations.

The significant risks and uncertainties described under “Overview of Our Business” raise substantial doubt about the Company’s ability to continue as a going concern. The report of the Company’s independent registered public accounting firm that accompanies its audited consolidated financial statements in this Annual Report on Form 10-K contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern.

As of April 13, 2018, we had not yet made the semi-annual interest payment to the holders of our Second Lien Notes that was due April 2, 2018. If such interest payment is not made prior to expiration of the 30-day grace period, the maturity date of the Second Lien Notes will be, upon requisite notice, subject to acceleration. This nonpayment of the semi-annual interest payment on the Second Lien Notes is an event of default under our Term Loan, which upon requisite notice would result in an acceleration of the Term Loan maturity date as well. We entered into a forbearance agreement with the requisite lenders under the Term Loan on April 3, 2018. The forbearance agreement does not constitute a waiver of the event of default related to the nonpayment of the semi-annual interest payment and other non-financial covenants. The forbearance agreement specifies that the lenders will forbear from taking any enforcement actions during the forbearance period, which extends through April 16, 2018, unless earlier terminated, but does not prevent the administrative agent under the Term Loan from accelerating amounts owed under the Term Loan. If we are unsuccessful in negotiating a restructuring transaction prior to the April 16, 2018 expiration of the forbearance period, or are otherwise unable to further negotiate or extend the forbearance period, the agreement of the lenders to forbear from taking any enforcement actions with respect to the events of default will immediately and automatically cease. Both the nature and terms of a restructuring transaction and an extension of the forbearance are not within our control, and may directly affect our liquidity and capital resources.

Financial Condition and Cash Flows for the years ended December 31, 2017, 2016 and 2015

The following table summarizes our sources and uses of funds for the periods noted:

Net cash provided by (used in) operating activities increased by approximately $42.9 million in 2017 when compared to 2016. This was primarily due to increases in realized prices of our natural gas, condensate and C3+ NGL sales, and decreased cash interest outflow of approximately $8.4 million as a result of our debt restructuring events in 2016, partially offset by decreased production and settlement of derivatives. Net cash provided by operating activities decreased by approximately $35.3 million in 2016 when compared to 2015, to cash used of $4.4 million. This was primarily due to a reduction in oil, natural gas and NGL prices, increased lease operating expenses and payments related to our early termination of two drilling rig contracts. These decreases in cash flow were partially offset by increases in production and lower G&A expenses.

Net cash (used in) provided by investing activities increased by approximately $90.2 million in 2017 from net cash provided by investing activities during 2016, to cash used in investing activities of $85.5 million. This was due to capital development expenditures for 2017 that were approximately $64.4 million higher than in 2016, coupled with the effect of joint venture capital reimbursements of approximately $19.5 million we received in 2016, reducing our net capital expenditure outflow in 2016. These factors account for a net increase in cash used in investing activities of $83.8 million for 2017 compared to 2016. Net cash provided by (used in) investing activities increased by approximately $160.1 million in 2016 when compared to 2015, to cash provided of $4.7 million. This increase in cash was primarily attributed to lower capital activity levels, proceeds from the sale of our Illinois Basin assets and proceeds from our joint ventures. This was partially offset by the $66.8 million in proceeds received from the sale of Water Solutions and $24.9 million in proceeds received from our joint venture with ArcLight in 2015.

Net cash provided by financing activities increased by approximately $56.2 million in 2017 when compared to 2016, to $58.6 million. The increase in cash provided by financing activities in 2017 is primarily due to borrowings made on our new Term Loan, this was partially offset by debt issuance costs and preferred stock dividends. Net cash provided by financing activities decreased by approximately $105.2 million in 2016 when compared to 2015, to $2.4 million. The decrease in cash provided by financing activities in 2016 is primarily due a net decrease in borrowings under our Prior Credit Agreement which was partially offset by the suspension of our preferred stock dividend payments.

As market conditions warrant and subject to our contractual restrictions in the Term Loan, our Indentures or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, repurchases of outstanding equity securities or outstanding debt, including our Senior Notes, by tender offer, exchange or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.

Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases or decreases, there could be a corresponding increase or decrease in our operating costs, as well as an increase or decrease in revenues. Inflation has had a minimal effect on our results.

The preparation of financial statements in conformity with United States generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include proved oil, NGL and natural gas reserve volumes used in calculating depletion, depreciation and amortization expense, future cash flows, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectability of outstanding accounts receivable, fair values of financial derivative instruments, contingencies and the results of

current and future litigation. Oil and natural gas estimates, which are the basis for units-of-production depletion, have numerous inherent uncertainties. The certainty of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. These prices have been volatile in the past and are expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially affected by changes in future economic conditions such as the market prices received for sales of oil and natural gas, interest rates, and our ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.

Our trade accounts receivable, which are primarily from condensate, NGLs and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We assess the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2017 and 2016 were $0.1 million and $0.1 million, respectively.

To the extent actual quantities and values of condensate, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets.

We account for natural gas, NGLs, and condensate exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of condensate, NGLs and natural gas, are capitalized.

Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.

We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future natural gas, NGLs, and oil prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future natural gas, NGLs, and oil prices are based on forward strip prices for Henry Hub natural gas and NYMEX oil and other related indices. For unproved natural gas and oil properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved oil and gas properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved natural gas, NGLs, and oil properties, we analyze the level and success of current development, future development plans and changes in market value. Performing the impairment evaluations requires use of judgments and

estimates since the results are dependent on future events, including estimates of future proved and unproved reserves, future commodity prices, the timing of future production, capital expenditures and the intent to develop properties, among others.

We recognized approximately $21.4 million, $74.6 million and $283.2 million of impairment from continuing operations on certain natural gas, NGLs, and oil properties for the years ended December 31, 2017, 2016 and 2015, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense, to our Consolidated Financial Statements.

Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.

Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated DD&A are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

Our estimate of proved reserves is based on the quantities of natural gas, NGLs and condensate that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2017 and 2016, NSAI prepared a reserve and economic evaluation of our proved natural gas and oil reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, NGL and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineers estimate reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.

Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.

Natural gas, NGLs, and condensate revenue is recognized when the natural gas, NGLs, or condensate is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of condensate sales, title is transferred to the purchaser when the condensate leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, wellhead gas volumes are first processed through various third-party gas processing facilities to separate the raw (“wet”) gas into NGL products and natural gas. Title to NGLs and natural gas products transfers to the purchaser when the separated product volumes are metered for sale either at the exit flange of a processing facility, or the inlet flange of a purchaser’s designated delivery point. Sales prices for purchased volumes are defined in sales contracts and are readily determinable based on certain publicly available indices. Our commodity purchasers have historically made payment for natural gas, NGLs, and condensate purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible.

To the extent actual quantities and values of natural gas, NGLs and condensate are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in our Consolidated Balance Sheets, and as natural gas, NGLs, and condensate Sales in our Consolidated Statements of Operations.

Effective January 1, 2018, we adopted ASC 606, Revenue from Contracts with Customers. Our evaluation of the impacts to our revenue recognition process from the adoption and implementation of ASC 606 are discussed in Note 2, Summary of Significant Accounting Policies, Recently Issued Accounting Pronouncements – Revenue Recognition in the notes to our Consolidated Financial Statements.

We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We also, from time to time, use interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2017, 2016 and 2015 we did not have any derivative instruments designated for hedge accounting.

For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity and interest rates, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information.

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to other temporary differences.

Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rate. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.

which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.

The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets.

We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 11, Income Taxes, to our Consolidated Financial Statements). Our policy is to recognize interest and penalties on any unrecognized tax benefits in interest expense and general and administrative expense, respectively.

From May 2014 through September 2017, the Financial Accounting Standards Board (“FASB”) issued several Accounting Standards Updates (“ASUs”) revising certain revenue accounting standards, codified together as Accounting Standards Codification (“ASC”) 606 – Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 is effective for interim and annual periods beginning after December 15, 2017. The permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented and any cumulative effect of applying the standard recognized in the earliest period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized as an adjustment to opening equity balances at the date of initial application. We have adopted ASC 606 as of January 1, 2018 using the modified retrospective method. This method allows us to apply the standard to new contracts entered into after January 1, 2018, and to our existing contracts for which revenue earned through December 31, 2017 has been recognized under the guidance in effect prior to the effective date of ASC 606. The revenue recognition processes we have applied prior to adoption of ASC 606 align closely with the recognition and measurement guidance of the new standard, therefore adoption of the standard did not require a cumulative adjustment to opening equity. We do not expect the standard to have a significant impact on our results of operations, financial position, or liquidity following adoption. We have implemented the necessary changes to our business processes, systems, and controls to support recognition and disclosure of ASC 606 upon adoption. Beginning the first quarter of 2018, revenue related disclosures will be expanded to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers and remaining performance obligations.

ASC 606 requires evaluation of contracts with customers to determine whether the selling party in a contract for goods or services is acting in the capacity of the Principal or as an Agent, as defined in the standard. This determination is then applied to evaluate whether revenues earned from sales to a customer are to be reported in the statement of operations as gross revenue receipts (in our instance commodity volumes sold multiplied by the contract specified sales price), or reported net of various costs incurred by the seller to fulfill the performance obligation. To produce the various saleable commodities that we supply to our customers from our wellhead wet gas and to transport products to the physical points of sale, we incur expenses including gas plant processing fees, gathering and compressions fees, transportation charges, and fees for pipeline capacity commitments. We have determined that we are the principal in all our current commodity sales contracts, and accordingly we record sales revenue at the gross sales price received. Our expense associated with processing and delivering the products to our buyers are reported as components of Production

and Lease Operating Expense in our Consolidated Statement of Operations. The key determinants in our evaluation of the principal versus agent considerations are control of the goods (title to the commodity volumes) and risk of loss, both of which remain with us until the point of sale for our population of active contracts.

In February 2016, the FASB issued ASU 2016-02, Leases. Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date:

Public business entities are required to apply the amendment of this update for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. We are currently evaluating the potential impact of this standard on our results of operations and internal control environment. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues:

Public business entities are required to apply the amendments of this update for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The amendments should be applied using a retrospective transition method to each period presented. We are currently evaluating this guidance to assess its impact on our current cash flow reporting processes.

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of natural gas and oil.

To mitigate some of our commodity price risk we engage periodically in certain other limited derivative activities, including price swaps and costless collars, to establish some price floor protection. For the years ended December 31, 2017 , the net realized loss on oil, natural gas and NGL derivatives was approximately $10.1 million. For the years ended December 31, 2016 , the net realized gain on oil, natural gas and NGL derivatives was approximately $32.9 million. For the years ended December 31, 2017 , our total net loss on oil, natural gas and NGL derivatives was approximately $1.4 million, as compared to a net loss of approximately $34.3 million on oil, NGL and natural gas derivatives for 2016. Derivative gains and losses are reported as Gain (Loss) on Derivatives, net in the Consolidated Statements of Operations.

While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil, NGLs and natural gas. We enter into the majority of our derivative transactions with five counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have

additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivative arrangements generally do not apply to all of our production, and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.

For a summary of our current natural gas, NGLs and oil derivative positions at December 31, 2017, refer to Note 10, Fair Value of Financial Instruments and Derivative Instruments, of our Consolidated Financial Statements.

In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. As of December 31, 2017, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2017.

The following summarizes our contractual financial obligations for continuing operations at December 31, 2017 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities.

At December 31, 2017, we had $189.5 million in borrowings outstanding under our Term Loan. The interest rates on outstanding balances during 2017 on our Term Loan averaged 10.2%. At December 31, 2017, we had $7.3 million in aggregate principal amount of 2020 Notes outstanding, bearing interest at 8.875% annually, $5.4 million in aggregate principal amount of 2022 Notes outstanding bearing interest at 6.25% annually, and $587.6 million in aggregate principal amount of Second Lien Notes outstanding, which bore interest at 1% annually through September 30, 2017 and which have borne interest at 8% annually thereafter through October 1, 2020.

We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.

We are exposed to various risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, natural gas, NGLs and condensate. Conversely, increases in the market prices for natural gas, NGLs and condensate can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2017 reserve estimates, we project that a 10% decline in the price per barrel of condensate, price per barrel of NGLs and the price per Mcf of natural gas from average 2017 prices would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2018 by approximately $26.0 million.

We have designed our hedging policy to reduce the risk of price volatility for our production in the natural gas, NGL and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include fixed rate swap contracts, puts, collars, basis swaps and three-way collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in commodity prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of natural gas, NGLs and condensate. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.

We account for our commodity derivatives at fair value on a recurring basis. The fair value of our derivatives contemplate the impact of assumed counterparty credit risk, which are based on published credit ratings, public bond yield spreads and credit default swap spreads, as applicable. A 1% increase in counterparty credit risk would result in a negligible decrease in net income based on our derivative assets as of December 31, 2017 of $9.7 million.

At December 31, 2017, the following commodity derivative contracts were outstanding:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		95,000	Bbls	$	—	$	—	$	—	$	53.93		$	(518	)
2018 - Collars		18,000	Bbls		—		53.00		60.00		—			(31	)
2018 - Three-Way Collars		72,000	Bbls		42.29		51.46		61.38		—			(92	)
2019 - Swaps		31,500	Bbls		—		—		—		51.00			(90	)
2019 - Collars		60,250	Bbls		—		45.00		55.07		—			(100	)
2019 - Three-Way Collars		50,250	Bbls		38.81		48.81		58.35		—			(94	)
2020 - Swaps		24,000	Bbls		—		—		—		51.00			(90	)
2020 - Collars		71,750	Bbls				45.00		55.10					(133	)
2020 - Three-Way Collars		29,600	Bbls		39.24		49.24		56.99		—			(52	)
2021 - Swaps		6,000	Bbls		—		—		—		51.00			(22	)
2021 - Collars		63,750	Bbls		—		45.00		55.02		—			(123	)
2021 - Three-Way Collars		24,000	Bbls		37.50		47.50		60.25		—			(12	)
2022 - Collars		36,000	Bbls		—		45.00		54.75		—			(69	)
2022 - Three-Way Collars		6,000	Bbls		37.50		47.50		60.25		—			(3	)
		588,100	Bbls										$	(1,429	)
Natural Gas
2018 - Swaps		15,335,000	Mcf	$	—	$	—	$	—	$	3.10		$	3,733
2018 - Three-Way Collars		10,600,000	Mcf		2.33		2.90		3.52		—			1,672
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(154	)
2018 - Collars		4,415,000	Mcf		—		2.66		3.10		—			37
2018 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.83	)		(3,604	)
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		173
2019 - Swaps		10,470,000	Mcf		—		—		—		2.84			154
2019 - Three-Way Collars		8,205,000	Mcf		2.27		2.77		3.40		—			132
2019 - Collars		7,520,500	Mcf		—		2.54		3.04		—			(295	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(3,570	)
2020 - Swaps		4,560,000	Mcf		—		—		—		2.87			13
2020 - Three-Way Collars		4,555,000	Mcf		2.23		2.73		3.30		—			113
2020 - Collars		4,720,000	Mcf		—		2.51		3.05		—			(183	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(1,945	)
2021 - Swaps		3,875,000	Mcf		—		—		—		2.77			(87	)
2021 - Three-Way Collars		3,037,500	Mcf		2.17		2.67		3.15		—			(30	)
2021 - Collars		2,737,500	Mcf		—		2.50		3.05		—			(134	)
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
2022 - Swaps		2,730,000	Mcf		—		—		—		2.73			(91	)
2022 - Three-Way Collars		2,047,500	Mcf		2.15		2.65		3.10		—			(58	)
2022 - Collars		2,047,500	Mcf		—		2.50		3.05		—			(101	)
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
		154,735,500	Mcf										$	(5,829	)
NGLs
2018 - C3+ NGL Swaps		1,367,572	Bbls	$	—	$	—	$	—	$	33.30		$	(10,254	)
2018 - Ethane Swaps		1,247,500	Bbls		—		—		—		12.92			900
2019 - C3+ NGL Swaps		705,922	Bbls		—		—		—		30.65			(2,750	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(308	)
2019 - Ethane Swaps		727,500	Bbls		—		—		—		12.98			306
2019 - C5 Three-Way Collars		8,472	Bbls		—		32.31		50.00		55.75			(17	)
2020 - C3+ NGL Swaps		271,276	Bbls		—		—		—		37.63			(1,157	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(77	)
2020 - Ethane Swaps		448,500	Bbls		—		—		—		12.83			(9	)
2020 - C5 Three-Way Collars		28,134	Bbls		—		32.31		50.00		55.75			(49	)
2021 - C3+ NGL Swap		158,112	Bbls		—		—		—		45.62			(376	)
2021 - Ethane Swaps		251,000	Bbls		—		—		—		12.77			(3	)
2022 - C3+ NGL Swap		48,984	Bbls		—		—		—		50.56			(74	)
2022 - Ethane Swaps		111,500	Bbls		—		—		—		12.69			(9	)
		5,515,772	Bbls										$	(13,877	)

Item 305(a) of Regulation S-K requires that tabular information relating to contract terms allow readers of the table to determine expected cash flows from the market risk sensitive instruments for each of the next five years. At December 31, 2017, we had commodity derivative contracts relating to production through 2022.

We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of December 31, 2017, we had approximately $189.5 million outstanding under our Term Loan, which is subject to variable rates of interest, and had $600.3 million aggregate principal amount of senior notes outstanding subject to a fixed interest rate. See Note 9, Long-Term Debt, to our Consolidated Financial Statements for additional information on our senior credit facility and our outstanding senior notes. Based on our total debt as of December 31, 2017 of approximately $842.5 million, a 1.0% change in interest rates would impact our interest expense by approximately $8.4 million.

We entered into fixed-to-variable interest rate swaps during 2015; however, there were no arrangements in place as of December 31, 2017 and 2016. We utilize the mark-to-market accounting method to account for our interest rate swaps. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Income (Expense). During the year ended December 31, 2015, we received cash payments of approximately $0.9 million related to our interest rate swaps.

We have audited the accompanying consolidated balance sheets of Rex Energy Corporation and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in noncontrolling interests and stockholders’ equity (deficit), and cash flows for each of the years in the three‑year period ended December 31, 2017 and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated April 13, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company is in violation of restrictive covenants and expects to be in violation of restrictive covenants contained in its credit facilities that, subject to requisite notice, would accelerate the maturity of the outstanding indebtedness making it immediately due and payable. The Company does not have sufficient liquidity to meet the accelerated debt service requirements. These issues raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

	December 31, 2017			December 31, 2016
ASSETS
Current Assets
Cash and Cash Equivalents	$	15,247		$	3,697
Accounts Receivable		25,974			25,448
Taxes Receivable		2,049			211
Short-Term Derivative Instruments		8,008			1,873
Inventory, Prepaid Expenses and Other		4,614			2,546
Total Current Assets		55,892			33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,086,625			1,053,461
Unevaluated Oil and Gas Properties		186,523			215,794
Other Property and Equipment		19,640			21,401
Wells and Facilities in Progress		38,660			21,964
Pipelines		16,803			18,029
Total Property and Equipment		1,348,251			1,330,649
Less: Accumulated Depreciation, Depletion and Amortization		(463,899	)		(475,205	)
Net Property and Equipment		884,352			855,444
Other Assets		44			2,492
Long-Term Derivative Instruments		1,719			2,212
Deferred Tax Assets - Long Term		130			—
Total Assets	$	942,137		$	893,923
LIABILITIES AND EQUITY (DEFICIT)
Current Liabilities
Accounts Payable	$	62,354		$	40,712
Current Maturities of Long-Term Debt		834,325			764
Accrued Liabilities		45,218			37,207
Short-Term Derivative Instruments		14,892			25,025
Total Current Liabilities		956,789			103,708
Long-Term Derivative Instruments		14,249			7,227
Long-Term Debt		—			751,946
Other Long-Term Debt		8,156			3,409
Other Deposits and Liabilities		7,153			8,671
Future Abandonment Cost		9,352			8,736
Total Liabilities	$	995,699		$	883,697
Commitments and Contingencies (See Note 7)
Stockholders’ Equity (Deficit)
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on December 31, 2017 and 2016.	$	1		$	1
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 10,244,394 shares issued and outstanding on December 31, 2017 and 9,787,146 shares issued and outstanding on December 31, 2016		10			10
Additional Paid-In Capital		652,917			650,669
Accumulated Deficit		(706,490	)		(640,454	)
Total Stockholders’ Equity (Deficit)		(53,562	)		10,226
Total Liabilities and Stockholders’ Equity (Deficit)	$	942,137		$	893,923

	Year Ended December 31,
	2017			2016			2015
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	205,246		$	139,000		$	138,707
Other Revenue		20			17			42
TOTAL OPERATING REVENUE		205,266			139,017			138,749
OPERATING EXPENSES
Production and Lease Operating Expense		120,794			104,699			93,892
General and Administrative Expense		17,858			20,621			26,694
Gain on Disposal of Assets		(1,428	)		(4,121	)		(540	)
Impairment Expense		21,383			74,619			283,244
Exploration Expense		527			2,178			2,617
Depreciation, Depletion, Amortization and Accretion		59,028			62,874			85,844
Other Operating Expense		611			10,754			5,603
TOTAL OPERATING EXPENSES		218,773			271,624			497,354
LOSS FROM OPERATIONS		(13,507	)		(132,607	)		(358,605	)
OTHER INCOME (EXPENSE)
Interest Expense		(48,826	)		(43,519	)		(47,783	)
Gain (Loss) on Derivatives, Net		(1,347	)		(32,515	)		60,176
Other Expense		(261	)		(2,124	)		(129	)
Debt Exchange Expense		—			(9,063	)		—
Gain (Loss) on Extinguishments of Debt		(3,029	)		24,627			—
Loss on Equity Method Investments		—			—			(411	)
TOTAL OTHER INCOME (EXPENSE)		(53,463	)		(62,594	)		11,853
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(66,970	)		(195,201	)		(346,752	)
Income Tax Benefit (Expense)		2,728			(2,436	)		(6,030	)
NET LOSS FROM CONTINUING OPERATIONS		(64,242	)		(197,637	)		(352,782	)
Income (Loss) From Discontinued Operations, Net of Income Taxes		—			20,922			(8,251	)
NET LOSS		(64,242	)		(176,715	)		(361,033	)
Net Income Attributable to Noncontrolling Interests		—			—			2,245
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(64,242	)	$	(176,715	)	$	(363,278	)
Preferred Stock Dividends		(2,392	)		(5,091	)		(9,660	)
Effect of Preferred Stock Conversions		—			72,984			—
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(66,634	)	$	(108,822	)	$	(372,938	)
Earnings per common share:
Basic – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(16.37	)	$	(66.64	)
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		—		$	2.64			(1.93	)
Basic – Net Loss Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(13.73	)	$	(68.57	)
Basic – Weighted Average Shares of Common Stock Outstanding		9,902			7,926			5,439
Diluted – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(16.37	)	$	(66.64	)
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		—			2.64			(1.93	)
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(13.73	)	$	(68.57	)
Diluted – Weighted Average Shares of Common Stock Outstanding		9,902			7,926			5,439

	Common Stock				Preferred Stock
	Shares		Par Value			Shares			Par Value		Additional Paid- In Capital			Accumulated Deficit			Rex Energy Stockholders' Equity (Deficit)			Noncontrolling Interests			Total Stockholders’ Equity
BALANCE December 31, 2014		5,418	$	5			16		$	1	$	617,875		$	(90,749	)	$	527,132		$	4,241		$	531,373
Equity Based Compensation		—		—			—			—		6,469			—			6,469			—			6,469
Issuance of Restricted Stock, Net of Forfeitures		157		—			—			—		—			—			—			—			—
Capital Distributions		—		—			—			—		—			—			—			(830	)		(830	)
Sale of Consolidated Subsidiary		—		—			—			—		(432	)		—			(432	)		(5,656	)		(6,088	)
Dividends Declared on Preferred Stock		—		—			—			—		—			(9,660	)		(9,660	)		—			(9,660	)
Net Income (Loss)		—		—			—			—		—			(363,278	)		(363,278	)		2,245			(361,033	)
BALANCE December 31, 2015		5,574	$	5		$	16		$	1	$	623,912		$	(463,687	)	$	160,231		$	—		$	160,231
Equity Based Compensation		—		—			—			—		2,919			—			2,919			—			2,919
Issuance of Common Stock in Debt Exchange		841		1			—			—		6,411			—			6,412			—			6,412
Issuance of Common Stock for Debt Extinguishment		2,352		3			—			—		17,375			—			17,378			—			17,378
Preferred Stock Dividends Paid in Common Shares		6		—			—			—		52			(52	)		—			—			—
Issuance of Restricted Stock, Net of Forfeitures		82		—			—			—		1			—			1			—			1
Conversion of Preferred Stock to Common Stock		931		1			(12	)		—		(1	)		—			—			—			—
Net Income (Loss)		—		—			—			—		—			(176,715	)		(176,715	)		-			(176,715	)
BALANCE December 31, 2016		9,787	$	10		$	4		$	1	$	650,669		$	(640,454	)	$	10,226		$	—		$	10,226
Equity Based Compensation		—		—			—			—		1,231			—			1,231			—			1,231
Issuance of Common Stock for Debt Extinguishments		84		—			—			—		467			—			467			—			467
Issuance of Restricted Stock, Net of Forfeitures		59		—			—			—		—			—			—			—			—
Effect of Reverse Stock Split		—		—			—			—		(48	)		—			(48	)		—			(48	)
Payment of Preferred Dividends in Arrears		—		—			—			—		—			(1,196	)		(1,196	)		—			(1,196	)
Preferred Dividends in Arrears Paid in Common Shares		314		—			—			—		598			(598	)		—			—			—
Net Loss		—		—			—			—		—			(64,242	)		(64,242	)		—			(64,242	)
BALANCE December 31, 2017		10,244	$	10			4		$	1	$	652,917		$	(706,490	)	$	(53,562	)	$	—		$	(53,562	)

	For the Years Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(64,242	)	$	(176,715	)	$	(361,033	)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Loss on Equity Method Investments		—			—			411
Depreciation, Depletion, Amortization and Accretion		59,028			67,975			104,822
Loss (Gain) on Derivatives		1,347			32,515			(60,176	)
Cash Settlements of Derivatives		(10,100	)		32,571			55,793
Non-Cash Dry Hole Expense		13			905			330
Equity-based Compensation Expense		1,231			2,959			6,549
Impairment Expense		21,383			78,162			345,775
Amortization of Debt Issuance Costs		1,165			1,640			2,045
Amortization of Bond Discounts and Premiums		—			(100	)		(381	)
Non-cash Interest Expense related to Debt Restructurings and Exchanges		14,063			19,603			—
Loss (Gain) on Extinguishment of Debt		3,029			(24,627	)		—
Gain on Disposal of Assets		(1,428	)		(34,651	)		(521	)
Gain on Sale of Water Solutions		—			—			(57,778	)
Deferred Income Tax Benefit		(130	)		—			—
Other Non-cash Income (Expense)		471			22			(564	)
Changes in operating assets and liabilities
Accounts Receivable		5,258			(6,414	)		21,679
Taxes Receivable		(1,839	)		—			—
Inventory, Prepaid Expenses and Other Assets		(2,060	)		906			(568	)
Accounts Payable and Accrued Liabilities		14,558			2,795			(22,955	)
Other Assets and Liabilities		(3,259	)		(1,950	)		(2,543	)
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		38,488			(4,404	)		30,885
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		—			—			58
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		31,704			40,884			77,226
Proceeds from Joint Venture for reimbursement of capital Costs		—			19,461			16,611
Acquisitions of Undeveloped Acreage		(3,805	)		(6,712	)		(28,242	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment		(113,411	)		(48,982	)		(221,099	)
NET CASH (USED) PROVIDED BY INVESTING ACTIVITIES		(85,512	)		4,651			(155,446	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt, Lines of Credit and Term Loan		217,000			71,400			229,314
Repayments of Long-Term Debt, Lines of Credit and Term Loan		(145,170	)		(65,230	)		(108,335	)
Repayments of Loans and Other Notes Payable		(1,306	)		(828	)		(1,519	)
Debt Issuance Costs		(10,754	)		(2,983	)		(1,414	)
Distributions by the Partners of Consolidated Subsidiary		—			—			(830	)
Payment of Preferred Dividends in Arrears		(1,196	)		—			(9,660	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		58,574			2,359			107,556
NET INCREASE (DECREASE) IN CASH		11,550			2,606			(17,005	)
CASH AND CASH EQUIVALENTS – BEGINNING		3,697			1,091			18,096
CASH AND CASH EQUIVALENTS – ENDING	$	15,247		$	3,697		$	1,091
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	$	15,247		$	3,697		$	1,091
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of Capitalized Interest		22,382			30,805			47,628
Net Cash Paid (Received) for Income Taxes		1,839			29			(502	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations		—			1,346			14,210
NON-CASH ACTIVITIES
Change in fair value of contingent consideration receivable - sale of Illinois Basin		(1,216	)		(2,936	)		—
Proceeds held in Escrow - non cash component of Gain on Sale of Assets		5,000			—			—
Increase (Decrease) in Accounts Payable and Accrued Liabilities for Capital Expenditures		14,637			712			(11,703	)
Net Increase in Property and Equipment - Capital Lease Financing		7,170			—			—
Decrease in Senior Notes carrying value net of Issuance Costs, Deferred Gain on Exchanges, and Net Discount due to Debt to Equity Conversions		(879	)		(47,182	)		—
Decrease in Bond Interest Payable due to Debt to Equity Conversions		(12	)		(892	)		—
Increase in Common Stock Additional Paid-In Capital due to Debt to Equity Conversions		467			17,378
Preferred Dividends in Arrears Paid in Common Shares		598			—			—

Rex Energy Corporation, together with our subsidiaries (the “Company”), is an independent condensate, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian Basin. We are focused on Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.

The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. We report our interests in oil, NGL and natural gas properties using the proportional consolidation method of accounting. All intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying Consolidated Financial Statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.

Our term loan agreement (“Term Loan”) requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and a maximum net senior secured debt to EBITDAX ratio. EBITDAX is a non-GAAP measure used by our management team and by other users of our financial statements. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data - Non-GAAP Financial Measures.” If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties.

Our common stock has been listed on the Nasdaq Capital Market, where it had been listed since December 2016 after previously being listed on the Nasdaq Global Select Market. On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department of Nasdaq indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we requested an appeal before the Nasdaq Hearings Panel. We did not appeal this determination and the time period in which to appeal has lapsed. Following the expected delisting of our common stock from Nasdaq, our common stock may be eligible for quotation on the OTCBB or OTC Markets Group’s Pink marketplace. Trading on the OTCBB or Pink marketplace may occur only if a market maker applies to quote our common stock and we are current in our reporting obligations under the Securities Exchange Act of 1934. Once our common stock is delisted from Nasdaq, there can be no assurance that a market maker will apply to quote our common stock or that our common stock then will be eligible for quotation on the OTCBB or the Pink marketplace.

As of April 13, 2018, the date we filed our Consolidated Financial Statements with the Securities and Exchange Commission on Form 10-K for the annual reporting period ended December 31, 2017, we have not made the semi-annual interest payment to the holders of our second lien notes that was due April 2, 2018. The second lien notes provide a 30 day grace period in which to pay the interest coupon due to the noteholders. If the interest payment is not made prior to expiration of the 30 day grace period, the maturity date of the second lien notes will be, upon requisite notice from the noteholders, subject to acceleration. Nonpayment of interest due on the second lien notes is an event of default under our term loan agreement, which upon requisite notice from the lenders under the term loan agreement would result in an acceleration of the term loan maturity date. In addition to the non-payment of the April 2, 2018 interest coupon, we also encountered additional events of default related to certain non-financial covenants. These additional events of default are a result of our failure to timely deliver to the term loan lenders our unaudited quarterly financial statements for the quarter ended December 31, 2017 and our annual audited financial statements for the year ended December 31, 2017, as well as related inadvertent failures to provide accurate related written notices to the lenders, and proper written notices of the events of default in a subsequent draw request under the term loan agreement.

We entered into a forbearance agreement with the requisite lenders under our senior term loan facility on April 2, 2018. The forbearance agreement does not constitute a waiver of the events of default related to the nonpayment of interest and other non-financial covenants defaults described above. The forbearance agreement specifies that the lenders will forbear from taking any

enforcement actions during the forbearance period, which extends through April 16, 2018, unless earlier terminated, but does not prevent the administrative agent under the term loan agreement from accelerating amounts owed under the term loan agreement. If we are unsuccessful in negotiating a restructuring transaction prior to the April 16, 2018 expiration of the forbearance period, or are otherwise unable to further negotiate or extend the forbearance period, the agreement of the lenders to forbear from taking any enforcement actions with respect to the events of default will immediately and automatically cease.

If the lenders for the term loan agreement and subsequently the noteholders, accelerate the Company’s outstanding indebtedness (approximately $789.8 million as of December 31, 2017), it will become immediately due and payable and the Company will not have sufficient liquidity to repay those amounts.

The Company is currently in discussions with various stakeholders and is pursuing or considering a number of actions including: (i) obtaining additional sources of capital from potential outside investors, negotiating modifications of certain terms of both the second lien notes and the senior term loan facility, restructuring current debt obligations through debt for equity exchanges, or any combination thereof; (ii) pursuing in- and out-of-court restructuring transactions; (iii) obtaining waivers or amendments from its lenders; and (iv) continuing to minimize its capital expenditures, reduce costs and maximize cash flows from operations. There can be no assurance that sufficient liquidity can be obtained from one or more of these actions or that these actions can be consummated within the period needed.

The ability to conclude a successful negotiation with our lenders and note holders to restructure our debt obligations has been deemed to be outside of our control in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 205-40, Going Concern. If we are unable to negotiate an effective restructuring transaction, it is probable that the events of default related to the nonpayment of the second lien interest payment will continue. If our lenders and/or noteholders demand immediate repayment of all obligations, the Company would likely be unable to pay all such obligations. In such an event, if the Company has not otherwise been able to recapitalize, refinance, or raise additional liquidity through some other form of restructuring, the Company could be required to immediately file for protection under Chapter 11 of the U.S. Bankruptcy Code.

The events of default and significant risks and uncertainties described above raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of our discussions with the lenders under the term loan agreement and the holders of our second lien notes, or the outcome of the going concern uncertainty.

On May 12, 2017, we effected a one-for-ten reverse stock split. As a result of the reverse stock split, each ten shares of our common stock automatically combined into and became one share of our common stock. Any fractional shares which would have otherwise been due as a result of the reverse split were rounded up to the nearest whole share. As a result of the reverse stock split, we reduced the issued number of common shares from 99.0 million to 9.9 million. The reverse stock split automatically and proportionately adjusted, based on the one-for-ten split ratio, all issued and outstanding shares of our common stock, as well as common stock underlying stock options, warrants and other derivative securities outstanding at the time of the effectiveness of the reverse stock split. The exercise price on outstanding equity based-grants proportionately increased, while the number of shares available under our equity-based plans also was proportionately reduced. Share and per share data for the periods presented reflect the effect of this reverse stock split. References to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 4, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements. Our estimated proved reserves account for the sale of our Illinois Basin assets in 2016 have not been retroactively restated to remove the associated estimated proved reserves from prior year balances.

During December 2014, our board of directors approved and committed to a plan to sell Water Solutions Holdings, LLC and its related subsidiaries (“Water Solutions”), of which we owned a 60% interest. The sale of Water Solutions closed in July 2015. As a result, the results of operations of Water Solutions have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for the year ended December 31, 2015. As of December 31, 2017 and 2016, we had no assets, liabilities or continuing cash flows related to Water Solutions.

In June 2016, we entered into a purchase and sale agreement to divest all of our Illinois Basin assets and operations. The sale closed in August 2016, with an effective date of July 1, 2016. As a result of this transaction, the results of operations of our Illinois Basin operations have been classified as Discontinued Operations in the accompanying Consolidated Statements of Operations as of December 31, 2016 and 2015. As of December 31, 2017 and 2016, we have a derivative asset of $1.7 million and $2.9 million recorded, respectively, representing the fair value of contingent consideration payments as specified in the Illinois Basin sales agreement. For additional information, see Note 4, Discontinued Operations, to our Consolidated Financial Statements.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved natural gas, NGL and oil reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of condensate and natural gas, interest rates and our ability to generate future income.

We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2017 and 2016, our Cash and Cash Equivalents consisted of only cash.

Our trade accounts receivable, which are primarily from natural gas, NGLs and condensate sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2017 and 2016 were $0.1 million and $0.1 million, respectively.

At December 31, 2017, we carried approximately $22.9 million in production receivable, of which approximately $19.3 million were production receivables due from our three largest purchasers. At December 31, 2016, we carried approximately $22.2 million in production receivables, of which approximately $17.5 million were production receivables due from three purchasers. In addition, we carried approximately $2.5 million in receivables at December 31, 2017 and $2.7 million at December 31, 2016 that was in relation to our joint operations with Sumitomo Corporation, Benefit Street Partners, LLC and ArcLight Capital Partners, LLC.

Inventory is valued at the lower of cost or market value and consists of our ownership interest in NGLs and condensate held in terminal tanks located in the field. NGL and condensate cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.

We account for natural gas, NGL and oil exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of

the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proven natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of condensate, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2017, 2016 and 2015, we capitalized interest costs of $1.7 million, $2.7 million and $7.7 million, respectively.

Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable natural gas and oil are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.

We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future natural gas, NGL and condensate prices are based on forward strip prices for NYMEX oil and various natural gas markets that are relevant to our operations. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved natural gas and oil properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved natural gas, NGL and condensate properties, we analyze the level and success of current development, changes in future development plans and changes in market value. If it is determined that it is unlikely for an unproved property to be successfully developed prior to the lease expiration or extension, an impairment of the respective unproved property is recognized in the period in which that determination is made. Performing the impairment evaluations requires use of judgment since the results are dependent on future events, including the timing of future capital expenditures, production and the intent to develop properties, among others.

We recognized approximately $21.4 million, $74.6 million and $283.2 million of impairment from continuing operations on certain natural gas, NGL and condensate properties for the years ended December 31, 2017, 2016 and 2015, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense, to our Consolidated Financial Statements.

Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depletion are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.

and economic parameters. For the years ended December 31, 2017 and 2016, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our natural gas, NGLs, and condensate reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineers estimate reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.

Accretion expense from continuing operations during the years ended December 31, 2017, 2016 and 2015 totaled approximately $1.9 million, $1.0 million and $1.0 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2017 and 2016, approximately $0.6 million and $1.1 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Liabilities on our Consolidated Balance Sheets. During 2017 and 2016, we recognized an increase of $0.8 million and $1.9 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.

Natural gas, NGLs, and condensate revenue is recognized when the natural gas, NGLs, or condensate is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of condensate sales, title is transferred to the purchaser when the condensate leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, wellhead gas volumes are first processed through various third-party gas processing facilities to separate the raw (“wet”) gas into NGL products and natural gas. Title to NGL and natural gas products transfers to the purchaser when the separated product volumes are metered for sale either at the exit flange of a processing facility, or the inlet flange of a purchaser’s designated delivery point. Sales prices for purchased volumes are defined in sales contracts and are readily determinable based on certain publicly available indices. Our commodity purchasers have historically made payment for natural gas, NGL and condensate purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible.

estimated and recorded as Accounts Receivable in our Consolidated Balance Sheets, and as natural gas, NGL, and condensate Sales in our Consolidated Statements of Operations.

We use put and call options (collars), fixed rate swap contracts, puts, basis swaps and three-way collars to manage price risks in connection with the sale of natural gas, NGLs, and condensate. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third parties. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on natural gas, NGL, and oil production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rates. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.

This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.

We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 15, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). Stock appreciation rights are classified as a liability and are re-measured at fair value each reporting period.

In March 2016, the Financial Account Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. We elected to early adopt ASU 2016-09 effective January 1, 2016. One provision of this update addresses the presentation of excess tax benefits and employee paid taxes on the statement of cash flows. We are now required to present excess tax benefits as an operating activity on the statement of cash flows rather than a financing activity, and we have adopted this change prospectively.

Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2017, we had 10,244,394 common shares outstanding, 86,331 options outstanding and 2,050 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 200,475 restricted stock awards, of which approximately 38,261 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share, to our Consolidated Financial Statements.

From May 2014 through September 2017, the FASB issued several ASUs revising certain revenue accounting standards, codified together as Accounting Standards Codification (“ASC”) 606 – Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASC 606 is effective for interim and annual periods beginning after December 15, 2017. The permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented and any cumulative effect of applying the standard recognized in the earliest period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized as an adjustment to opening equity balances at the date of initial application. We have adopted ASC 606 as of January 1, 2018 using the modified retrospective method. This method allows us to apply the standard to new contracts entered into after January 1, 2018, and to our existing contracts for which revenue earned through December 31, 2017 has been recognized under the guidance in effect prior to the effective date of ASC 606. The revenue recognition processes we have applied prior to adoption of ASC 606 align closely with the recognition and measurement guidance of the new

standard, therefore adoption of the standard did not require a cumulative adjustment to opening equity. We do not expect the standard to have a significant impact on our results of operations, financial position, or liquidity following adoption. We have implemented the necessary changes to our business processes, systems, and controls to support recognition and disclosure of ASC 606 upon adoption. Beginning the first quarter of 2018, revenue related disclosures will be expanded to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers and remaining performance obligations.

During 2016 and 2017, we evaluated our contracts with customers under ASC 606. We have determined that adoption of the standard would not result in any material change to the timing or method of recognizing revenue for our natural gas, NGL, and condensate commodity sales under contracts with our customers. The impact of adopting ASC 606 relates primarily to contract arrangements wherein title to the good or service and risk of loss transfer from seller to purchaser at different points. Our sales contracts with customers specify that title to purchased commodity volumes and the risk of loss associated with those goods transfers to the purchaser at the same point in time, which is consistent with the ASC 606 revenue recognition model. Our analysis of contract performance obligations and transaction pricing structures under ASC 606 is not materially different from our obligations and pricing structures identified under our current revenue recognition model. ASC 606 requires evaluation of contracts with customers to determine whether the selling party in a contract for goods or services is acting in the capacity of the Principal or as an Agent, as defined in the standard. This determination is then applied to evaluate whether revenues earned from sales to a customer are to be reported in the statement of operations as gross revenue receipts (in our instance commodity volumes sold multiplied by the contract specified sales price), or reported net of various costs incurred by the seller to fulfill the performance obligation. To produce the various saleable commodities that we supply to our customers from our wellhead wet gas and to transport products to the physical points of sale, we incur expenses including gas plant processing fees, gathering and compressions fees, transportation charges, and fees for pipeline capacity commitments. We have determined that we are the principal in all our current commodity sales contracts, and accordingly we record sales revenue at the gross sales price received. Our expense associated with processing and delivering the products to our buyers are reported as components of Production and Lease Operating Expense in our Consolidated Statement of Operations. The key determinants in our evaluation of the principal versus agent considerations are control of the goods (title to the commodity volumes) and risk of loss, both of which remain with us until the point of sale for our population of active contracts.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The amendments in the update provide guidance regarding the presentation in the statement of cash flows of eight specific cash flow disclosure issues:

In December 2014, our board of directors approved a formal plan to sell Water Solutions, of which we owned a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.6 million. The transaction is recorded as Discontinued Operations.

On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight participated and funded 35.0% of the estimated well costs for the designated wells. We received total consideration for the transaction of approximately $67.6 million, of which $16.6 million was received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. All wells have been drilled and placed in service. If the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest may revert back to us, leaving ArcLight with a 17.5% working interest.

The ArcLight transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized. Due to the fixed payment per well structure of the transaction, payments by ArcLight are treated as gains or losses, as appropriate, on a well-by-well basis for tax purposes.

On March 1, 2016, we entered into a joint exploration and development agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. BSP agreed to participate in and fund 15.0% of the estimated well costs for 16 designated wells in Butler County, Pennsylvania, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also agreed to participate in and fund 65.0% of the estimated well costs for six designated wells in Warrior North, Ohio, all of which have been drilled, completed, placed in sales and paid for by BSP. BSP also has the option to participate in the development of 36 additional wells and would fund 65.0% of the estimated well costs for the designated wells in return for a 65.0% working interest. To date, BSP has exercised their option to participate in 23 of these additional wells. Total consideration for this transaction could be up to $175.0 million, with approximately $134.0 million committed as of December 31, 2017. BSP has paid for their interest in the elected wells as of December 31, 2017. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of December 31, 2017, all 45 committed wells were in line and producing.

The BSP transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by BSP. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from BSP are considered a recovery of costs and no gain or loss is recognized.

effective date for the transaction of May 1, 2016. We received proceeds at closing of approximately $0.1 million. Included in the sale were approximately 300 wells, pipelines and support equipment. The sale of well properties generated approximately $4.6 million of gain in the second quarter of 2016 due to the elimination of our future abandonment liability associated with wells and pipelines sold to DOG. The gain, which is included in Gain on Disposal of Assets on our Consolidated Statement of Operations, is reported net of approximately $0.2 million of uncollectible accounts receivable written off in conjunction with the sale.

On June 14, 2016, we, through our wholly owned subsidiaries, Penntex Resources Illinois, LLC, Rex Energy I, LLC, Rex Energy IV, LLC, Rex Energy Marketing, LLC, R. E. Ventures Holdings, LLC, and Rex Energy Operating Corp. (collectively, “Rex”), entered into a Purchase and Sale Agreement (the “Agreement”) with Campbell Development Group, LLC (“Campbell”). Pursuant to the Agreement, Campbell agreed to purchase all of Rex’s oil and gas-related properties and assets, both operated and non-operated, in the Illinois Basin on an as-is, where-is basis. Closing occurred on August 18, 2016, with an effective date for the transaction of July 1, 2016. We received a purchase deposit of $2.5 million from Campbell in June 2016 and received the additional proceeds of approximately $38.5 million at closing in August 2016. An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up $9.9 million, in installments of $0.9 million per quarter, over the period beginning with the quarter ending December 31, 2016, and ending with the quarter ending June 30, 2019. For the proceeds to become payable by Campbell in any of the eleven individual quarters, the average spot price of West Texas Intermediate (“WTI”) as published by the New York Mercantile Exchange must be in excess of the amount shown in the table below for the applicable quarter. As of December 31, 2017, the first five of the eleven quarterly measurement periods have expired with the calculated average spot price of WTI below the threshold price stipulated in the agreement. Consequently, we did not receive any additional proceeds relate to those measurement periods. As of December 31, 2017, we have the potential to receive up to $5.4 million of additional proceeds if the WTI exceeds the price per Bbl as specified in the agreement. Proceeds earned for any quarter are payable to us within one year and fifteen days following the end of the quarter in which additional proceeds are earned. For additional information, see Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

to us. This acreage was considered non-core to us. We used the proceeds from the transaction to pay down amounts outstanding under our prior revolving line of credit and for general corporate purposes.

As described in Note 3 above, during 2015 we sold Water Solutions pursuant to a purchase and sale agreement with American Water. As of December 31, 2017 and 2016, we had no assets or liabilities related to Water Solutions or continuing cash flows from this region.

Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.

As described in Note 3 above, we sold our Illinois Basin assets and operations pursuant to a purchase and sale agreement with Campbell in August 2016. As of December 31, 2017 and 2016, we had no assets or liabilities related to the Illinois Basin or continuing cash flows from this region.

Summarized financial information for Discontinued Operations related to our Illinois Basin operations is set forth in the tables below, and does not reflect the costs of certain services provided. Such indirect costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support. The sale of our Illinois Basin assets and operations does not include any of our derivative contracts or positions related to our Illinois Basin revenues or production. No derivative positions or activity has been attributed to or included in Discontinued Operations for the years ended December 31, 2017, 2016 and 2015.

RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly owned with WPX Energy Inc. (“WPX”) and Summit Discovery Resources II, LLC and Sumitomo Corporation (collectively, “Sumitomo”), with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania. Effective as of January 1, 2018, we sold our 40% interest in RW Gathering to COG2, LLC in connection with the sale of our interest in 61 wells located in Westmoreland, Centre and Clearfield Counties, Pennsylvania (the “Westmoreland Sale”). For additional information regarding the Westmoreland Sale, see Note 26, Subsequent Events, to our Consolidated Financial Statements.

We incurred a 100% impairment charge of $17.5 million during the second quarter of 2015 related to our investment in RW Gathering (for additional information, see Note 16, Impairment Expense, to our Consolidated Financial Statements). We did not make any capital contributions to RW Gathering during 2017 and 2016. RW Gathering recorded net losses from continuing operations of $2.0 million for each of the years ended December 31, 2017, 2016 and 2015. The losses incurred were due to insurance fees, bank fees, rent expenses and DD&A expense. Our share of the net loss from continuing operations incurred by RW Gathering is recorded on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued recording our share of the net losses due to our investment being reduced to zero.

At times during the years ended December 31, 2017 and 2016, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.

By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our term loan facility. We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled settlement date. For additional information, see Note 2, Summary of Significant Accounting Policies, and Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.

We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2017, we carried approximately $22.9 million in production receivables, of which approximately $19.3 million were production receivables due from three purchasers. At December 31, 2016, we carried approximately $22.2 million in production receivables, of which approximately $17.5 million were production receivables due from three purchasers. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of condensate and gas sales as well as the quantity of purchasers.

We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.

The accrual of reserves for legal matters is included in Accrued Liabilities on our Consolidated Balance Sheets. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we believe that these reserves are adequate, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The reserved and unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur losses in excess of the amounts currently accrued. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures for legal proceedings will exceed our current accruals by an amount that would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs are incurred.

Due to the nature of the natural gas and oil business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews to identify changes our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. We manage our exposure to environmental liabilities on properties to be acquired by conducting evaluations (both internal and using consultants) to identify existing problems and assessing the potential liability. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages cost of employees who are expected to devote a significant amount of time directly to any remediation effort. At this time we know of no significant probable or possible environmental contingent liabilities relating to our operations.

As of December 31, 2017 and 2016, we had posted $32.0 million and $46.5 million, respectively, in various letters of credit to secure our drilling and related operations. Approximately $31.7 million of the letters of credit outstanding at December 31, 2017 are related to firm natural gas transportation agreements.

At December 31, 2017 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.8 million, $0.9 million and $1.0 million for the years ended December 31, 2017, 2016 and 2015, respectively. Lease commitments by year for each of the next five years are presented in the table below.

We are a party to a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $16.6 million in 2018, $16.6 million in 2019, $16.6 million in 2020, $16.6 million in 2021, $16.6 million in 2022 and $65.0 million thereafter, assuming our average working interest in the region of approximately 53.2%. For the years ended December 31, 2017, 2016 and 2015, we incurred capacity reservation charges of $5.2 million, $3.2 million and $0.6 million, respectively. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations. As we continue to develop our assets in 2018 and beyond, we expect that our capacity reservation fees will decrease.

We have contracted with a water district in Ohio to supply bulk water in support of our Ohio drilling operations. The contract is effective from July 5, 2017 through July 4, 2022. Over the duration of the contract, we are obligated to purchase 150 million gallons of water at a fixed price of $7.50 per 1,000 gallons. As of December 31, 2017, our future commitment for unpurchased volumes is approximately $0.8 million.

We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $1.9 million in 2018. We also have contracted completions services in the Appalachian Basin. The minimum gross cost to retain these completion services is approximately $7.0 million in 2018. These costs are partially offset by other working interest owners, whose interests and share of these expenses vary from well to well. If the drilling rig is idle, the Company is solely responsible for the associated cost, unless otherwise negotiated with these other working interest owners.

During the normal course of business we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our condensate, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $377.2 million through 2029.

For the years ended December 31, 2017, 2016 and 2015, we incurred expenses related to the transportation, processing and marketing our condensate, natural gas and natural gas liquids of approximately $109.2 million, $91.7 million and $79.5 million, respectively.

Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:

In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional natural gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. For the years ended December 31, 2017, 2016 and 2015, we incurred approximately

$3.6 million, $3.0 million and $3.0 million, respectively, in fees related to the natural gas impact fee. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.

We have an oral month-to-month agreement with Charlie Brown Air Corp. (“Charlie Brown”), a New York corporation owned by Lance T. Shaner, our Chairman, regarding the use of one airplane owned or managed by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplane equal to our percentage (based upon the total number of hours of use of the airplane by us) of the monthly fixed costs for the airplane, plus a variable per hour flight rate that ranges from $700 to $1,560 per hour. For the year ended December 31, 2017, we did not pay Charlie Brown for use of the aircraft. For the years ended December 31, 2016 and 2015 we paid Charlie Brown zero and approximately $0.1 million, respectively, for the use of the aircraft, including the variable per hour cost in addition to pilot fees, maintenance, hangar rental and other miscellaneous expenses.

We own a 50% membership interest in Charlie Brown Air II, LLC (“Charlie Brown II”). The other 50% is owned by Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Lance T. Shaner (“Shaner Hotel”). Charlie Brown II owns and operates an Eclipse 500 aircraft. In June 2007, Charlie Brown II borrowed approximately $1.5 million in original principal amount from BB&T Bank to purchase the aircraft. The loan currently bears interest at a rate equal to the Prime Rate as published in the Wall Street Journal. Charlie Brown II is required to make monthly payments of principal and interest of approximately $0.1 million in the aggregate annually and a final balloon payment of approximately $0.6 million at maturity in August 2019. The Company and Shaner Hotel each guarantee up to fifty percent of the principal balance of the loan. The balance of this loan as of December 31, 2017 and 2016 was approximately $0.8 million and $0.9 million, respectively. For the years ended December 31, 2017, 2016 and 2015, we paid Charlie Brown II approximately $0.2 million, $0.2 million and $0.3 million, respectively, for loan interest, services rendered and retainer fees.

The business affairs of Charlie Brown II are managed by two members, appointed by each of its two owners. We have designated Thomas C. Stabley, our President and Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown II require the written consent of both managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company.

On June 27, 2012, we entered into an office lease agreement with Shaner Office Holdings, L.P., a limited partnership controlled by Lance T. Shaner. The office lease, which replaced our former headquarters office lease in State College, Pennsylvania, calls for monthly rental payments in the initial amount of $35,000 beginning on April 1, 2013, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The terms of the lease provided that the lease may be extended for up to three five-year periods following the initial five-year term, or in the alternative, that the property could be purchased outright by our exercise of a purchase option at the end of the initial five-year term. On September 15, 2017, we exercised our option to renew the lease for a five-year period beginning on January 1, 2018 and ending on December 31, 2022, and did not exercise the purchase option. For the year ended December 31, 2017, we paid Shaner Office Holdings, L.P. approximately $0.6 million in office rental payments and utilities. We account for this lease as an operating lease, subsequently recording the rental payments as General and Administrative Expense on our Consolidated Statements of Operations.

In May 2017, the Lance T. Shaner Revocable Trust (which is solely controlled by Lance T. Shaner) acquired approximately $4.6 million in principal amount of our 1.00%/8.00% Senior Secured Second Lien Notes due 2020 (the “Second Lien Notes”) at face value in an open market purchase. As a result, Mr. Shaner is entitled to all of the rights of a holder of Second Lien Notes as described in the Indenture governing the Second Lien Notes, including the right to receive twice-yearly interest payments, and to payment of the principal amount at maturity.

From time to time, Bronder Technical Services, Inc. (“Bronder”), an electrical services contractor in which Lance T. Shaner owns a controlling interest, provides wellsite-based electrical services to the Company. The electrical work on each of the Company’s well sites is subject to a competitive bidding process. In 2017, Bronder’s bid was selected for various electrical jobs on four of the Company’s well pads. Due to this competitive bidding process, the pricing terms applicable to these projects were consistent with, or more favorable than, market rates for the type of services performed. In 2017, the Company compensated Bronder in an aggregate amount of approximately $0.3 million for these services. Rex is under no continuing obligation to use Bronder, and electrical services will continue to be awarded on a wellsite-by-wellsite basis based on price and quality of work of contractors.

As of December 31, 2017, there were negligible amounts due to us from or from us to any Shaner affiliated entities.

As of December 31, 2017, we owned a 40% interest in RW Gathering which owns gas-gathering assets that facilitate the development of our joint operations with WPX and Sumitomo (see Note 5, Equity Method Investments, to our Consolidated Financial Statements). We incurred approximately $0.6 million, $0.6 million and $0.7 million for the years ended December 31, 2017, 2016 and 2015, respectively, in compression expenses that were charged to us from Williams Appalachia, LLC, which relate to compression costs incurred by RW Gathering. These costs are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2017, 2016 and 2015, there were no receivables or payables in relation to RW Gathering due to or from us. Effective as of January 1, 2018, we sold our 40% interest in RW Gathering to COG2, LLC in connection with the Westmoreland Sale.

We incurred approximately $6.1 million in gross water transfer and equipment rental expenses that were charged to us from Water Solutions during 2015 (through the date of sale in July 2015). Of the amounts incurred, we eliminated approximately $4.7 million in consolidation for the year 2015. As of December 31, 2015, we had no payables owed to Water Solutions for work performed during the period due to sale of our interest in Water Solutions during third quarter 2015. As of December 31, 2015, we classified the operations of Water Solutions as Discontinued Operations. See note 4, Discontinued Operations/Assets Held for Sale, of our Consolidated Financial Statements for additional information.

On April 28, 2017 (the “Effective Date”), we entered into a term loan agreement (“Term Loan”) with Angelo, Gordon Energy Servicer, LLC (“AGES”), as administrative agent, AGES, as collateral agent (in such capacity, the “Collateral Agent”), Macquarie Bank Limited, as issuing bank (in such capacity, the “Issuing Bank”), and the lenders from time to time party thereto. The Term Loan replaced our prior amended and restated senior secured revolving credit agreement with Royal Bank of Canada, as Administrative Agent, and the lenders from time to time party thereto (the “Prior Credit Agreement”). The Term Loan provides for a $143,500,000 secured term loan facility (the “Term Facility”) and a $156,500,000 secured delayed draw term loan facility (the “Delayed Draw Term Facility”), which includes a letter of credit sub-facility (the “Letter of Credit Sub-facility”). The proceeds of the initial loans under the Term Loan were used to refinance the loans then outstanding under the Prior Credit Agreement and payment of fees and expenses related thereto; the proceeds of future loans under the Delayed Draw Term Facility may be used for cash collateralizing letters of credit under the Letter of Credit Sub-facility and general corporate purposes. The maximum commitments of the lenders under the Term Loan are currently limited to $300,000,000. Amounts borrowed and repaid may not be re-borrowed. The maturity date for the loans under the Term Facility and the loans drawn under the Delayed Draw Term Facility is the earlier of (a) April 28, 2021 and (b) the date that is six months prior to the maturity of our Second Lien Notes unless less than $25,000,000 in aggregate principal amount of Second Lien Notes are then outstanding and no Event of Default (as defined in the Term Loan) exists on such date. The commitments under the Delayed Draw Term Facility expire if not drawn prior to the earlier of (a) April 28, 2018 (which date may be extended for one year with lender consent) and (b) the date upon which we terminate such commitments. As of December 31, 2017, we had $189.5 million in borrowings outstanding and approximately $32.0 million in outstanding undrawn letters of credit. We incurred approximately $3.5 million in debt issuance costs and $4.3 million in original issue discount (“OID”) related to the initial Term Loan borrowing. We incurred an additional $1.4 million in OID related to the Delayed Draw Term Facility. From April 28, 2017 through December 31, 2017, we amortized $0.7 million of debt issuance costs and $1.0 million of OID. The amortization of debt issuance costs and OID are reported as Interest Expense in our Consolidated Statement of Operations.

Borrowings under the Term Loan bear interest at a rate per annum equal to the “Adjusted LIBO Rate” (subject to a 1.00% floor) plus an 8.75% per annum margin. The “Adjusted LIBO Rate” is equal to the product of the three month LIBOR rate multiplied by the statutory reserve rate. At December 31, 2017 the weighted average interest rate on the Company’s Term Loan was 10.2%. Interest expense on the Term Loan for the year ended December 31, 2017 was approximately $11.0 million. Upon the occurrence and continuance of an Event of Default all outstanding loans shall bear interest at a rate equal to 4.00% per annum plus the then-effective rate of interest. Interest is payable on the last business day of each March, June, September and December. Under the Term Loan, we will pay a 3.5% commitment fee on any unused portion of the Delayed Draw Term Facility.

The Term Loan requires us to prepay the loans with 100% of the net cash proceeds received from certain asset sales, swap terminations, incurrences of borrowed money indebtedness, casualty events and equity issuances, subject to certain exceptions and specified reinvestment rights. Prepayments based on 75% of excess cash flow, (“excess cash flow” as defined in the Term Loan agreement represents EBITDAX less capital expenditures, cash payments for interest, cash payments for income taxes, and adjustments for certain non-cash expenses) are required until no more than $287,950,000 in aggregate principal amount of Second Lien Notes remain outstanding, at which time, prepayments based on 50% of excess cash flow will be required. Prepayments (including mandatory prepayments), terminations, refinancing, reductions and accelerations under the Term Loan are subject to a yield maintenance amount equal to the interest which would have accrued on such prepaid, terminated, refinanced, reduced or accelerated amount during the period beginning on the date of such prepayment, termination, refinancing, reduction or acceleration and ending on the date that is 30 months after the Effective Date and a call protection amount (a) during the period commencing on the Effective Date and ending on the date that is 30 months thereafter, in an amount equal to 3.0% of such prepaid, terminated, refinanced, reduced or accelerated amount and (b) during the period commencing on the date that is 30 months and one day after the Effective Date and ending on the date that is 36 months after the Effective Date, an amount equal to 1.0% of such prepaid, terminated, refinanced, reduced or accelerated amount. There were no prepayments made during 2017.

The Term Loan contains covenants that restrict our ability to, among other things, materially change the nature of our business, make dividend payments, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

The Term Loan also requires that we comply with the following financial covenants: (1) as of the last day of any fiscal quarter ending on or after December 31, 2017, the PDP Coverage Ratio (as defined in the Term Loan) will not be less than 1.65 to 1.00; (2) as of the last day of any fiscal quarter ending on or after March 31, 2017, the ratio of Net Senior Secured Debt (as defined in the Term Loan) as of such date to EBITDAX (as defined in the Term Loan) for the period of four fiscal quarters then ending on such day will not be greater than 3.25 to 1.00 (provided that EBITDAX for the four fiscal quarters ending on (i) March 31, 2017 shall be EBITDAX for the fiscal quarter then ending multiplied by four and (ii) June 30, 2017 shall be EBITDAX for the two fiscal quarters then ending multiplied by two); and (3) as of the last day of any fiscal quarter ending on or after September 30, 2017, the ratio of EBITDAX for the four fiscal quarters then ending to cash interest expense will not be less than (i) 1.00 to 1.00 for any fiscal quarter ending on or before December 31, 2017 and (ii) 1.30 to 1.00 for each fiscal quarter thereafter. As of December 31, 2017, our PDP Coverage Ratio was 2.63 to 1.00, Net Senior Secured Debt to EBITDAX Ratio was 3.00 to 1.00 and EBITDAX to Cash Interest Expense was 2.60 to 1.00.

Our obligations under the Credit Agreement may be accelerated upon the occurrence of an Event of Default (as such term is defined in the Term Loan). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as such term is defined in the Term Loan).

Obligations under the Term Loan are secured by mortgages on our oil and gas properties. In connection with the Term Loan, we, including our wholly owned subsidiaries, Rex Energy I, LLC, Rex Energy Operating Corp., PennTex Resources Illinois, Inc., Rex Energy IV, LLC, and R.E. Gas Development, LLC (collectively, the “Guarantors” and together with us, the “Grantors”), entered into an amended and restated guaranty and collateral agreement, dated as of April 28, 2017, in favor of the Collateral Agent for the lenders from time to time party to the Term Loan, the secured swap parties and the Issuing Bank (the “Guaranty and Collateral Agreement”). Pursuant to the Guaranty and Collateral Agreement, each of the Guarantors, jointly and severally, guaranteed the prompt and complete payment of our obligations under the Term Loan. In addition, each Grantor granted, as security for the prompt and complete payment and performance when due of such Grantor’s obligations, a security interest in substantially all of its assets, including equity interests in other Guarantors, as applicable.

On April 28, 2017, we terminated our senior secured line of credit under the Prior Credit Agreement. A portion of the proceeds of the initial loans under the Term Loan were used to refinance loans outstanding under the Prior Credit Agreement. In conjunction with the retirement of the Prior Credit Agreement, we expensed $3.4 million of associated unamortized debt issuance costs, included

in Loss on Extinguishments of Debt in our Consolidated Statement of Operations. We had $117.7 million in borrowings outstanding under the Prior Credit Agreement as of December 31, 2016.

On March 31, 2016, we completed an exchange offer and consent solicitation related to our 8.875% Senior Notes due 2020 (the “2020 Notes”) and 6.25% Senior Notes due 2022 (the “2022 Notes” and, together with the 2020 Notes, the “Existing Notes”). We offered to exchange (the “Exchange”) any and all of the Existing Notes held by eligible holders for up to (i) $675.0 million aggregate principal amount of our new Second Lien Notes and (ii) 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the troubled debt exchanges, the future undiscounted cash flows of the Second Lien Notes are greater than the net carrying value of the Existing Notes. As such, no gain has been recognized within our GAAP basis financial statements and a new effective interest rate has been established. See Note 11, Income Taxes, to our Consolidated Financial Statements, for information regarding the tax treatment and impact of the Exchange for federal and state income tax purposes.

In exchange for $324.0 million in aggregate principal amount of the 2020 Notes, representing approximately 92.6% of the outstanding aggregate principal amount of the 2020 Notes, and $309.1 million in aggregate principal amount of the 2022 Notes, representing approximately 95.1% of the outstanding aggregate principal amount of the 2022 Notes, we issued (i) $633.2 million aggregate principal amount of Second Lien Notes and (ii) 8.4 million Shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of Second Lien Notes were issued to holders who were ineligible to accept Shares. In addition, upon closing, we paid in cash accrued and unpaid interest on the Existing Notes accepted in the Exchange from the applicable last interest payment date totaling approximately $12.8 million. The remaining Existing Notes will continue to accrue interest at their historical rates. The Second Lien Notes bore interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and have borne interest at a rate of 8.0% per annum thereafter, payable in cash. Interest payments are due on April 1 and October 1 of each year, beginning October 1, 2016 and ending October 1, 2020. In connection with the Exchange, we incurred approximately $9.1 million in third-party debt issuance costs during the year ended December 31, 2016. These costs were recorded as Debt Exchange Expense in our Consolidated Statement of Operations.

The Company has not made the semi-annual interest payment to the holders of our second lien notes that was due on April 2, 2018, and if such interest payment is not made prior to the expiration of the 30 day grace period, the maturity date of the second lien notes will be, upon requisite notice, subject to acceleration. This nonpayment of the semi-annual interest payment on the second lien notes is an event of default under the Company’s Term Loan, which upon requisite notice, would result in an acceleration of the Term Loan maturity date as well.

Following the completion of the Exchange, we entered into debt-for equity exchanges during the remainder of 2016 with certain holders of our Existing Notes, as well as holders of our Second Lien Notes, in which such Existing Notes and Second Lien Notes were exchanged for unrestricted shares of our common stock. These exchanges resulted in the retirement of $27.7 million in aggregate principal amount of our remaining Existing Notes and $45.7 million in aggregate principal amount of our outstanding Second Lien Notes, in exchange for the issuance of a total of approximately 2.4 million shares of unrestricted common stock during the year ended December 31, 2016. During the year ended December 31, 2017, we completed debt-for equity exchanges with certain holders of our Existing Notes. These exchanges resulted in the retirement of approximately $0.9 million in aggregate principal amount of our remaining Existing Notes, in exchange for approximately 0.1 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain for the year ended December 31, 2017 of approximately $0.4 million, included as a component of Gain (Loss) on Extinguishments of Debt in our Consolidated Statements of Operations.

We may redeem, at specified redemption prices, some or all of the Second Lien Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the Second Lien Notes using the proceeds of certain equity offerings completed before April 1, 2018. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the Existing Notes and the Second Lien Notes from the holders.

Our Existing Notes and Second Lien Notes (collectively, the “Senior Notes”) are recorded as Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges on our Consolidated Balance Sheets.

The Senior Notes are governed by indentures (the “Indentures”), which contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on our ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or transfer substantially all of our assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including our ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most

recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25 to 1.00. As of December 31, 2017, our Fixed Charge Coverage Ratio was 1.10 to 1.00. We expect our Fixed Charge Coverage Ratio to be in compliance for the foreseeable future. As of December 31, 2017, we were limited to incurring approximately $161.7 million of additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual trustees under the Indentures or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

As of December 31, 2017 and December 31, 2016, we had recorded on our Consolidated Balance Sheets approximately $14.0 million and $3.6 million, respectively, of net premium/discounts related to the Senior Notes. The amortization of our net premium during the years ended December 31, 2017 and 2016, which follows the effective interest method, was approximately $10.4 million and $5.2 million, respectively, and was recorded as a credit to Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually on our Existing Notes. Interest on the 2020 Notes is paid at a rate of 8.875% per annum on June 1 and December 1 of each year, while interest on the 2022 Notes is paid at a rate of 6.25% per annum on February 1 and August 1 of each year. Total interest expense for the year ended December 31, 2017 is comprised of non-cash amortization of $16.2 million, cash interest payments of $22.4 million and an increase in accrued interest of $10.2 million. Total interest expense for the year ended December 31, 2016 is comprised of non-cash amortization of $22.2 million, cash interest payments of $29.7 million and a decrease in accrued interest of $8.4 million.

			December 31, 2017
			Principal			Unamortized net Premium / Discount			Unamortized Debt Issuance Costs			Unamortized Deferred Gain on Debt Restructurings		Net Carrying Value

Term Loans, Net
	Term Loan Draw - due April 2020		$	189,500		$	(4,711	)	$	(2,761	)	$	—	$	182,028

Senior Notes, Net
	8.875% Senior Notes due 2020		$	7,333		$	20		$	(80	)	$	—	$	7,273
	6.25% Senior Notes due 2022			5,363			—			(67	)		—		5,296
	1% / 8% Second Lien Senior Notes due 2020			587,606			(13,991	)		33,751			30,436		637,802
			$	600,302		$	(13,971	)	$	33,604		$	30,436	$	650,371

Other Long-Term Debt
	Long-Term Capital Leases - Equipment Financing
		Due March, 2021	$	632
		Due June, 2021		1,418
		Due September, 2021		1,578
		Due May, 2022		6,454
		Total Capital Lease Obligations	$	10,082
		Less: Current Portion of Capital Leases		(1,926	)
			$	8,156

The following is the principal maturity schedule for total debt outstanding as of December 31, 2017:

The audit report the Company received with respect to its consolidated financial statements contains an explanatory paragraph expressing uncertainty as to the Company’s ability to continue as a going concern, the delivery of which constitutes a default under the senior term loan facility. See “Going Concern” in Note 1 – Basis of Presentation and Principals of Consolidation for information regarding additional events of default that have occurred subsequent to December 31, 2017.

We enter derivative financial instruments with the primary objective of managing our exposure to commodity price fluctuations and providing more predictable cash flows. Our results of operations and operating cash flows are impacted by changes in market prices for natural gas, NGLs, and oil. To mitigate a portion of the exposure to adverse market changes, we enter into natural gas, NGLs, and oil commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels

that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of December 31, 2017, 2016 and 2015, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations. For additional information, see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements.

Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established.

Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing and between Henry Hub and Texas Gas pricing.

We enter into the majority of our derivative arrangements with two counterparties and have a netting agreement in place with these counterparties, however the fair value of our derivative contracts are reported on a gross basis. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 6, Concentrations of Credit Risk, to our Consolidated Financial Statements.

None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense). We paid net cash settlements of $10.1 million, in relation to our commodity derivatives for the year ended December 31, 2017, and we received net cash settlements of $32.6 million and $54.9 million in relation to our commodity derivatives for the years ended December 31, 2016 and 2015, respectively.

In conjunction with the sale of our Illinois Basin operations, we executed a contract with the buyer that would allow us to receive future cash payments from the buyer if index pricing targets, as defined in the contract, are achieved at specified future dates (see Note 4, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements for additional information). We have evaluated the contract and concluded that it meets the definition and requirements for accounting treatment as a derivative instrument. At December 31, 2017 and 2016, the contract had a fair value of approximately $1.7 million and $2.9 million, respectively. Fair value is determined through an application of mathematical models designed to provide fair value estimates utilizing probability measures and the market index measures underlying the contract. The fair value will be adjusted at each future reporting period for the duration of the contract, which concludes on June 30, 2019. Changes in the fair value are includes as a component of Gain/Loss on Derivatives, Net, on our Consolidated Statements of Operations.

We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of December 31, 2017, we had approximately $189.5 million in borrowings outstanding under our Term Loan, which is subject to variable rates of interest, and had $600.3 million of Senior Notes outstanding subject to a fixed interest rate. See Note 9, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.

We did enter into fixed-to-variable interest rate swaps during 2015, however there were no arrangements in place as of December 31, 2017 and 2016. We utilize the mark-to-market accounting method to account for our interest rate swaps. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under

Other Income (Expense). During the year ended December 31, 2015, we received cash payments of approximately $0.9 million, related to our interest rate swaps.

The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015:

We account for our derivatives in accordance with ASC 815, which requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The fair value associated with our derivative instruments was a net liability of $19.4 million and $28.2 million at December 31, 2017 and 2016, respectively. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2017 consisted of the following:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2018 - Swaps		95,000	Bbls	$	—	$	—	$	—	$	53.93		$	(518	)
2018 - Collars		18,000	Bbls		—		53.00		60.00		—			(31	)
2018 - Three-Way Collars		72,000	Bbls		42.29		51.46		61.38		—			(92	)
2019 - Swaps		31,500	Bbls		—		—		—		51.00			(90	)
2019 - Collars		60,250	Bbls		—		45.00		55.07		—			(100	)
2019 - Three-Way Collars		50,250	Bbls		38.81		48.81		58.35		—			(94	)
2020 - Swaps		24,000	Bbls		—		—		—		51.00			(90	)
2020 - Collars		71,750	Bbls				45.00		55.10					(133	)
2020 - Three-Way Collars		29,600	Bbls		39.24		49.24		56.99		—			(52	)
2021 - Swaps		6,000	Bbls		—		—		—		51.00			(22	)
2021 - Collars		63,750	Bbls		—		45.00		55.02		—			(123	)
2021 - Three-Way Collars		24,000	Bbls		37.50		47.50		60.25		—			(12	)
2022 - Collars		36,000	Bbls		—		45.00		54.75		—			(69	)
2022 - Three-Way Collars		6,000	Bbls		37.50		47.50		60.25		—			(3	)
		588,100	Bbls										$	(1,429	)
Natural Gas
2018 - Swaps		15,335,000	Mcf	$	—	$	—	$	—	$	3.10		$	3,733
2018 - Three-Way Collars		10,600,000	Mcf		2.33		2.90		3.52		—			1,672
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(154	)
2018 - Collars		4,415,000	Mcf		—		2.66		3.10		—			37
2018 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.83	)		(3,604	)
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		173
2019 - Swaps		10,470,000	Mcf		—		—		—		2.84			154
2019 - Three-Way Collars		8,205,000	Mcf		2.27		2.77		3.40		—			132
2019 - Collars		7,520,500	Mcf		—		2.54		3.04		—			(295	)
2019 - Basis Swaps - Dominion South		12,775,000	Mcf		—		—		—		(0.84	)		(3,570	)
2020 - Swaps		4,560,000	Mcf		—		—		—		2.87			13
2020 - Three-Way Collars		4,555,000	Mcf		2.23		2.73		3.30		—			113
2020 - Collars		4,720,000	Mcf		—		2.51		3.05		—			(183	)
2020 - Basis Swaps - Dominion South		7,320,000	Mcf		—		—		—		(0.84	)		(1,945	)
2021 - Swaps		3,875,000	Mcf		—		—		—		2.77			(87	)
2021 - Three-Way Collars		3,037,500	Mcf		2.17		2.67		3.15		—			(30	)
2021 - Collars		2,737,500	Mcf		—		2.50		3.05		—			(134	)
2021 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
2022 - Swaps		2,730,000	Mcf		—		—		—		2.73			(91	)
2022 - Three-Way Collars		2,047,500	Mcf		2.15		2.65		3.10		—			(58	)
2022 - Collars		2,047,500	Mcf		—		2.50		3.05		—			(101	)
2022 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
2023 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
2024 - Basis Swaps - Dominion South		3,650,000	Mcf		—		—		—		(0.72	)		(401	)
		154,735,500	Mcf										$	(5,829	)
NGLs
2018 - C3+ NGL Swaps		1,367,572	Bbls	$	—	$	—	$	—	$	33.30		$	(10,254	)
2018 - Ethane Swaps		1,247,500	Bbls		—		—		—		12.92			900
2019 - C3+ NGL Swaps		705,922	Bbls		—		—		—		30.65			(2,750	)
2019 - C5 Collars		113,040	Bbls		—		45.00		54.83		—			(308	)
2019 - Ethane Swaps		727,500	Bbls		—		—		—		12.98			306
2019 - C5 Three-Way Collars		8,472	Bbls		—		32.31		50.00		55.75			(17	)
2020 - C3+ NGL Swaps		271,276	Bbls		—		—		—		37.63			(1,157	)
2020 - C5 Collars		28,260	Bbls		—		45.00		54.83		—			(77	)
2020 - Ethane Swaps		448,500	Bbls		—		—		—		12.83			(9	)
2020 - C5 Three-Way Collars		28,134	Bbls		—		32.31		50.00		55.75			(49	)
2021 - C3+ NGL Swap		158,112	Bbls		—		—		—		45.62			(376	)
2021 - Ethane Swaps		251,000	Bbls		—		—		—		12.77			(3	)
2022 - C3+ NGL Swap		48,984	Bbls		—		—		—		50.56			(74	)
2022 - Ethane Swaps		111,500	Bbls		—		—		—		12.69			(9	)
		5,515,772	Bbls										$	(13,877	)

The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016 is summarized below.

	December 31,			December 31,
($ in Thousands)	2017			2016
Short-Term Derivative Assets:
NGL—Swaps		928			—
Natural Gas—Swaps		3,734			206
Natural Gas—Cap Swaps		—			61
Natural Gas—Collars		183			—
Natural Gas—Basis Swaps		191			232
Natural Gas—Three-Way Collars		1,721			151
Contingent Consideration - Sale of Illinois Basin		1,251			1,223
Total Short-Term Derivative Assets	$	8,008		$	1,873
Long-Term Derivative Assets:
NGL—Swaps		409			—
Natural Gas—Swaps		411			206
Natural Gas—Basis Swaps		—			293
Natural Gas—Three-Way Collars		429			—
Contingent Consideration - Sale of Illinois Basin		470			1,713
Total Long-Term Derivative Assets	$	1,719		$	2,212
Total Derivative Assets	$	9,727		$	4,085
Short-Term Derivative Liabilities:
Crude Oil—Collars	$	(31	)	$	(86	)
Crude Oil—Deferred Put Spread		—			(9	)
Crude Oil—Three-Way Collars		(92	)		(132	)
Crude Oil—Swaps		(518	)		(220	)
NGL—Swaps		(10,281	)		(9,895	)
Natural Gas—Three-Way Collars		(49	)		(2,397	)
Natural Gas—Cap Swaps		—			(3,364	)
Natural Gas—Collars		(146	)		(873	)
Natural Gas—Basis Swaps		(3,621	)		(640	)
Natural Gas—Call		(154	)		(1,478	)
Natural Gas—Swaption		—			(1,258	)
Natural Gas—Swaps		—			(4,673	)
Total Short - Term Derivative Liabilities	$	(14,892	)	$	(25,025	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars	$	(161	)	$	(58	)
Crude Oil—Swaps		(202	)		(146	)
Crude Oil—Collars		(425	)		—
NGL—Swaps		(4,482	)		(2,200	)
NGL—Collars		(385	)		—
NGL—Three Way Collars		(66	)		—
Natural Gas—Swaps		(423	)		(1,004	)
Natural Gas—Swaption		—			(167	)
Natural Gas—Basis Swaps		(7,120	)		(1,260	)
Natural Gas—Collars		(713	)		(115	)
Natural Gas—Call		—			(491	)
Natural Gas—Three-Way Collars		(272	)		(1,786	)
Total Long-Term Derivative Liabilities	$	(14,249	)	$	(7,227	)
Total Derivative Liabilities	$	(29,141	)	$	(32,252	)

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These

inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of December 31, 2017 and 2016, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

We had no Level 3 commodity derivative contracts outstanding as of December 31, 2017 and 2016.

The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the years ended December 31, 2017 and 2016, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:

Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.

The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of December 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, swaption,

three way collar, basis swap, cap swap, call and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of December 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of December 31, 2017 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.

The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2017 and 2016 (in thousands):

Changes in fair value on our Level 3 commodity derivative contracts outstanding for the years ended December 31, 2017 and 2016, resulted in no change and an increase of approximately $7.2 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.

We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances.

The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:

The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.

The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

During the years ended December 31, 2017 and 2016, we recorded impairments of $21.4 million and $74.6 million, respectively, related to proven and unproved properties. We primarily use proved reserve reports in our determination of impairment. These proved reserve reports are generated with inputs that are primarily established internally with the use of internally developed engineering estimates and methodologies. The inputs used in determining fair value as a part of the impairment calculation are considered to be Level 3 within the fair value hierarchy. For additional information on our impairment, see Note 16, Impairment Expense, to our Consolidated Financial Statements.

We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax basis of assets and liabilities using enacted tax rates. 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.

A reconciliation of income tax expense using the statutory U.S. income tax rate compared with actual income tax expense is as follows:

The current tax benefit of $2.6 million is the result of reconciling the 2016 tax returns to the expected Federal and State liabilities generated by the CODI incurred in 2016. Of the current benefit $2.0 million is related to AMT and $0.6 million is related to state tax. The $0.1 million of deferred tax benefit is related to the removal of the valuation allowance associated with the Alternative Minimum Tax Credit Carry-forward as described in the Tax Law Changes paragraph below.

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2017 and 2016:

The Tax Cuts and Jobs Act (H.R. 1) was enacted on December 22, 2017. The new law reduces the federal corporate tax rate to 21% from 35% for tax years ending after December 31, 2017. The rate change led to a $79.3 million reduction in our net deferred tax asset but did not result in any deferred expense due the offsetting valuation allowance. The law also provides for a refund of the Alternative Minimum Tax Credit over four years beginning in 2018, allowing for the removal of the valuation allowance associated with this deferred tax attribute. Although we do not expect any immediate negative impacts from the passage of H.R. 1, the law does limit the interest deduction while also limiting the NOL deduction to 80% of taxable income. Both of these limitations could lead to current tax expense in a future period. The extent to which state tax authorities pass legislation to conform with or decouple from the Federal legislation could also have positive or negative impacts on our tax burden in future periods.

During 2016, we completed a series of debt for equity exchanges with holders of our Senior Notes. We accounted for the exchanges as troubled debt restructurings. For additional information regarding the exchanges, see Note 9, Long-Term Debt, to our Consolidated Financial Statements. For tax purposes, as a result of the debt exchanges the company recognized cancellation of debt income (“CODI”). The taxable income generated by the CODI was offset by net operating loss carryforwards from previous years. However, the CODI generated a current AMT liability of $2.0 million and a state Liability of $0.6 million in 2016. Applying troubled debt accounting to the exchanges results in book-tax timing differences of deferred financing costs. These costs will be amortized at different rates as they are recognized in income over the term of the new notes. The timing differences result in the recognition of a deferred tax asset of $182.5 million as of December 31, 2016. We have determined that our ability to recognize the future tax benefits of this deferred tax assets are less than more likely than not, and we have recorded a full valuation allowance to offset the benefit of the deferred tax asset, for the year ended December 31, 2016.

Effective January 1, 2016 Management elected to early adopt ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 eliminates additional paid in capital (“APIC”) pools and requires excess tax benefits and tax deficiencies to be recorded in the income statement when the awards vest or are settled. The retrospective adoption of ASC 2016-09 eliminates the requirement that excess tax benefits be realized (i.e., through a reduction in income taxes payable) before we can recognize them. Due to the full valuation allowance, there is no cumulative effect to retained earnings. For additional information, see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements

Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize our inventory of deferred tax assets. The company’s deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2017, management determined, based on positive and negative evidence, including our three-year cumulative loss position that it was necessary to provide a valuation allowance of approximately $154.4 million for deferred tax assets for which the company may be unable to realize the tax benefit. For the year ended December 31, 2016, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it was necessary to provide a valuation allowance of approximately $212.0 million for deferred tax assets for which the company may be unable to realize the tax benefit. Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances.

At December 31, 2017, we had available unused gross federal net operating loss carryforwards of $407.6 million and gross state net operating loss carryforwards of $533.9 million that may be applied against future taxable income that expire from 2023 through 2037. The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected):

Due to a change of ownership, as defined under the provisions of the Tax Reform Act of 1986, which occurred during 2016, a portion of our domestic net operating loss and tax credit carryforwards may be limited in future periods. Internal Revenue Code Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event. As a result of this ownership change, certain of our accumulated net operating losses may be subject to an annual limitation regarding their utilization against taxable income in future periods. The 2016 change creates an estimated annual utilization limit of approximately $1.4 million on our ability to utilize net operating losses generated prior to the ownership change event. Built-in gains associated with our deferred tax attributes on the date of the ownership change may decrease the net operating loss utilization limit in future periods, allowing additional utilization of net operating losses generated prior to the date of the ownership change. If we were to experience another ownership change in future periods, our net operating loss carryforwards may be subject to additional utilization limits.

FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position.

Our management has concluded that, as of December 31, 2017, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no-liability balance is required to offset any unsustainable positions. We did not have any accrued interest or penalties as of December 31, 2017 and 2016.

We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States federal jurisdiction and in many state jurisdictions. We are subject to U.S. federal income tax examinations and to various state tax examinations for periods after December 31, 2012.

Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For the year ended December 31, 2017, we excluded stock options to purchase 0.1 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2016 and 2015, we excluded stock options to purchase 1.2 million shares and 0.4 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2017, 2016 and 2015, we excluded performance-based restricted stock of 0.1 million shares, 0.6 million shares and 1.1 million shares, respectively, due to our Net Loss from Continuing Operations (for additional information on our non-cash compensation plans, see Note 15, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For the years ended December 31, 2017, 2016 and 2015, we excluded the assumed conversion of preferred stock equating to approximately 2.2 million, 2.2 million and 8.9 million shares, respectively, due to our Net Loss from Continuing Operations. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data):

As discussed in Note 1, Basis of Presentation and Principles of Consolidation, references to numbers of shares of common stock and per share data in the accompanying financial statements and notes thereto have been adjusted to reflect the reverse stock split on a retroactive basis.

Our common stock previously traded on The Nasdaq Capital Market under the symbol “REXX”. On April 3, 2018, we received a Staff Determination Letter from the Listing Qualifications Department of Nasdaq indicating that, based on our continued non-compliance with Nasdaq Listing Rule 5550(b), our common stock would be suspended from trading on Nasdaq at the opening of business on April 12, 2018, and a Form 25-NSE would be filed with the Securities and Exchange Commission, which would remove our common stock from listing and registration on Nasdaq, in each case unless we requested an appeal before the Nasdaq Hearings Panel. We did not appeal this determination and the time period in which to appeal has lapsed. Following the delisting of our common stock from Nasdaq, our common stock may be eligible for quotation on the OTCBB or OTC Markets Group’s Pink marketplace. Trading on the OTCBB or Pink marketplace may occur only if a market maker applies to quote our common stock and we are current in our reporting obligations under the Securities Exchange Act of 1934. Once our common stock is delisted from Nasdaq, there can be no assurance that a market maker will apply to quote our common stock or that our common stock then will be eligible for quotation on the OTCBB or the Pink marketplace.

On May 27, 2016, our common shareholders approved an increase in the number of authorized shares from 100,000,000 to 200,000,000 common shares. On May 5, 2017, our common shareholders approved a decrease in the number of authorized shares from 200,000,000 to 100,000,000 common shares, contingent upon the effectiveness of a reverse stock split, which occurred on May 12, 2017. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of December 31, 2017 and 2016, we had 10,244,394 and 9,787,146 shares of common stock outstanding, respectively. During the year ended December 31, 2017, we issued approximately 0.3 million shares of our common stock as payment of our preferred stock dividend and 0.1 million shares of our common stock in conjunction with debt for equity exchanges completed with certain holders of our Senior Notes. During the year ended December 31, 2016, we issued approximately 0.8 million shares of our common stock in conjunction with the Exchange completed on March 31, 2016, and approximately 2.4 million shares of our common stock in debt-to-equity exchanges with certain holders of our Senior Notes. See Note 9, Long-Term Debt, to our Consolidated Financial Statements for additional information regarding our debt and equity exchanges.

As of December 31, 2017 and 2016, shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (“Series A Preferred Stock”), issued and outstanding totaled 3,987 for each period, respectively. During the year ended December 31, 2016, 12,113 shares of Series A Preferred Stock were converted into an aggregate of approximately 0.9 million shares of common stock pursuant to the terms of the Series A Preferred Stock, and through negotiated exchanges with certain holders of the Series A Preferred Shares. See Note 12, Earnings Per Common Share, to our Consolidated Financial Statements, for additional information regarding the effect of the preferred stock conversions on Net Loss Attributable to Common Shareholders.

The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on each February 15, May 15, August 15 and November 15 of each year.

We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. Dividends that are not declared and paid in accordance with the quarterly schedule will accumulate from the most recent date upon which dividends were paid but will not bear interest. In February 2016, we suspended our quarterly dividend payment. Dividends of $1.8 million were declared by our Board of Directors in 2017. For the year ended December 31, 2017, we paid cash dividends of $150.00 per share in the aggregate amount of $1.2 million, for the periods of November 15, 2015 to February 15, 2016 and February 15, 2016 to May 15, 2016 and we paid a dividend of $150.00 per share in the aggregate amount of $0.6 million for the period of May 15, 2016 to August 15, 2016, which was paid in shares of the Company’s common stock. As of December 31, 2017, accumulated dividends in arrears totaled approximately $3.0 million. While the accumulation does not result in the presentation of a liability on the Consolidated Balance Sheets, the accumulated dividends are added to our Net Loss in the determination of Loss Attributable to Common Shareholders and related loss per share calculations. No dividends were declared by our board of directors in 2016. For the year ended December 31, 2015, we declared quarterly cash dividends totaling approximately $9.7 million.

The Series A Preferred Stock is convertible at the option of the holder at an initial conversion rate of 55.56 shares of our common stock per share (0.5556 shares of our common stock per depositary share), equivalent to an initial conversion price of $18.00 per share of common stock. The conversion price represents a premium of approximately 25.2% relative to the Nasdaq Global Market closing sale price of our common stock on August 12, 2014, or $14.38 per share.

At any time on or after August 30, 2019, we may at our option cause all outstanding shares of the Series A Preferred Stock to be automatically converted into common stock at the then-applicable conversion price, if the closing sale price of our common stock exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion. If a holder elects to convert shares

of Series A Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to the converting holder.

If we do not pay dividends for an aggregate of six quarterly periods, the holders of the Series A Preferred Stock will have the right to elect two additional directors to our board of directors.

For the year ended December 31, 2017, approximately $143.8 million, or 78.5%, of our commodity sales from continuing operations were attributable to three customers with the largest single purchaser accounting for $86.1 million, or 47.0%. For the year ended December 31, 2016, approximately $95.1 million, or 78.8%, of our commodity sales from continuing operations were attributable to three customers with the largest single purchaser accounting for $55.1 million, or 45.6%. For the year ended December 31, 2015, approximately $120.0 million, or 82.2%, of our commodity sales from continuing operations were derived from three customers, with the largest customer being responsible for approximately $76.0 million, or 52.0%, of total commodity sales.

We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Company matching contributions were suspended during 2016, and partially reinstated in October 2017. Our contributions to the plan attributable to continuing operations were negligible for the years ended December 31, 2017 and 2016 and were approximately $0.5 million for the year ended December 31, 2015.

We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as a financing cash flow, rather than as an operating cash flow.

We have granted stock options and restricted stock awards to various employees, non-employee directors and non-employee contractors under the terms of our Amended and Restated 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards, interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees may be designed, at the Compensation Committee’s discretion, to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes. The Compensation Committee has authorized the issuance of 597,947 shares under the Plan, with 217,552 and 238,579 still available as of December 31, 2017 and 2016, respectively.

All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with between five and ten year expiration at an exercise price equal to our closing price on the Nasdaq Global Select Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.

Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised

portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan. During the year ended December 31, 2017, there were no issuances of options to purchase shares of our common stock. During the year ended December 31, 2016, we issued 88,892 options to purchase shares of our common stock to 34 employees.

Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2017 and 2016 was $0.4 million and $0.4 million, respectively. Expense related to stock-based compensation relating to stock options for the year ended December 31, 2015 was negligible. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative expense. No stock options were exercised for the years ended December 31, 2017, 2016 and 2015. The total tax benefit for the years ended December 31, 2017, 2016 and 2015was negligible.

We use the Black-Scholes option pricing model to calculate the fair value of stock option awards. Determining the fair value of equity-based awards requires judgement, including estimating the expected term that options will be outstanding prior to exercise, and the associated volatility measure. The fair value of each option award is estimated on the date of the grant.

The assumptions used to estimate the fair value of options granted during the years ended December 31, 2017 and 2016 are as follows:

A summary of the status of our issued and outstanding stock options as of December 31, 2017 is as follows:

The weighted average remaining contractual term for options exercisable at December 31, 2017 was 4.2 years and the aggregate intrinsic value was negligible. The weighted average remaining contractual term for options exercisable at December 31, 2016 were 1.2 years and the aggregate intrinsic value was negligible. As of December 31, 2017, unrecognized compensation expense related to stock options was $0.1 million.

During the year ended December 31, 2017, the Compensation Committee issued 101,237 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. During the year ended December 31, 2016, the Compensation Committee issued 142,309 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2017 and 2016 are subject to time vesting and, in some cases, performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date until the date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted common stock is valued at the closing price of our common stock on the Nasdaq Global Select Market or the Nasdaq Capital Market, as applicable, on the date of the grant. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse for performance-based awards to varying degrees based on performance metrics at the time of the change in control. For awards that do not contain a performance-based condition, all restrictions immediately lapse upon a change in control. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period.

Certain of the restricted common stock awards in 2015 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group of 13 to 15 companies over a three-year period. The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:

The weighted average fair value of the TSR awards as of December 31, 2015 were $2.56. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:

The dividend yield of zero reflects the fact that we have never paid cash dividends on our common stock and have no present intentions of doing so. The risk-free interest rate reflects the U.S. Treasury Constant Maturity rates as of the measurement date, converted into an implied “spot rate” yield. Our expected volatility estimates are based on observed historical volatility of daily stock returns for the three-year period preceding the grant date. Market index is an equal-weight index of the companies in the peer group. Expected life is measured as the grant date through the end of the performance period. Performance and market shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Compensation expense for the TSR awards is recognized on a straight-line basis over the vesting period.

Stock-based compensation expense from continuing operations related to restricted common stock awards for the years ended December 31, 2017, 2016 and 2015 was $0.9 million, $2.7 million and $5.8 million, respectively. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of approximately 18,987 restricted stock awards with associated expense of approximately $2.5 million. As of December 31, 2017, total unrecognized compensation cost related to the restricted common stock grants was approximately $0.6 million to be recognized over a weighted average of 1.4 years. The total fair value of restricted common stock awards that vested in 2017 was approximately $0.4 million as compared to $0.6 million for restricted common stock awards that vested in 2016.

A summary of the restricted stock activity for the years ended December 31, 2017, 2016 and 2015 is as follows:

For the years ended December 31, 2017, 2016 and 2015, we incurred impairment expense from continuing operations of approximately $21.4 million, $74.6 million and $283.2 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). Approximately $9.9 million of the impairment incurred during 2017 was attributable to unconventional proved properties in the Appalachian Basin. The

analysis for proved properties included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. In addition, we also incurred approximately $11.5 million in unproved property impairments for leases that expired or are expected to expire without being developed, of which approximately $7.8 million was related to leases in Butler County, Pennsylvania and Ohio and approximately $3.2 million was attributable to non-operated Marcellus leases. The impairments were identified through an analysis of market conditions and future development plans that were in existence throughout 2017, related to these properties, which indicated that the carrying value of the assets was not recoverable. The primary reason for the decrease in the estimated future cash flows of our assets is attributable to the depressed estimated future commodity prices during 2017. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices were to decline, which may result in our incurrence of additional impairment expense. As of December 31, 2017, we continued to carry the costs of unproved properties of approximately $186.5 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.

During 2016, we recorded impairment expense from continuing operations of $74.6 million. Approximately $28.3 million of the impairment incurred during 2016 was attributable to unconventional proved properties in the Appalachian Basin. In addition, we also incurred approximately $46.3 million in unproved property impairments for leases that expired or are expected to expire without being developed in Butler County, Pennsylvania and Ohio.

During 2015, we recorded impairment expense from continuing operations of $283.2 million. Approximately $223.6 million of the impairment incurred during 2015 was attributable to proven properties and other fixed assets, of which approximately $204.6 million was attributable to unconventional assets in the Appalachian Basin and $17.5 million was attributable to our equity method investment in RW Gathering. The remaining proved property impairment expense is related to our conventional dry gas assets and salt water disposal well in the Appalachian Basin. In addition, we also incurred approximately $59.6 million in unproved property impairments related to leases in the Appalachian Basin that will not be developed.

We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for each of the years ended December 31, 2017, 2016 and 2015 ($ in thousands):

As of December 31, 2017 and 2016, there were no capitalized exploratory well costs that were capitalized for a period greater than one year. The costs as of December 31, 2015 were related to 13 properties located in Pennsylvania for wells that we purchased through our acquisition from Shell in 2014. Due to the required development timing of these properties combined with our current development plan and optimization of our capital spend, we did not allocate capital to complete the wells or build out the infrastructure to place them into sales and these costs were reclassified to Impairment Expense.

Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands):

The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands):

Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands):

Our independent engineers, NSAI evaluated all of our proved oil, natural gas and NGL reserves for the years ended December 31, 2017, 2016 and 2015. The technical persons responsible for preparing the estimates of our estimated proved reserves meet the requirements with regards to 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. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil, natural gas and NGL reserve estimates were generally based upon extrapolation of historical production trends, performance analysis, and analogy to similar properties. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our estimated proved reserves are located within the United States.

Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience 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 - 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. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Developed natural gas, oil and NGL reserves are reserves of any category that can be expected to be recovered (x) through existing wells with existing equipment and operating methods or in which the cost of the

required equipment is relatively minor compared to the cost of a new well; and (y) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped natural gas, oil and NGL reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2017, 2016 and 2015. We accounted for the estimated proved reserves of our Illinois Basin assets as a sale in 2016. Prior years were not retroactively adjusted for the effect of discontinued operations.

Our estimated proved undeveloped reserves did not include any locations that generated a positive future net revenue and a negative present value discounted at 10%. We may, from time to time, have proved undeveloped locations with these characteristics based on our planned operating budget and strategy to hold acreage by production combined with our expectations of future commodity prices.

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from developmental drilling and production history or resulting from a change in economic factors, such as commodity prices and operating costs.

Our revisions in 2017 included a positive adjustment of approximately 165.0 Bcfe related primarily to positive well performance in our Butler, Moraine East, and Warrior North assets as well as an improvement in commodity prices as compared to 2016.

Our revisions in 2016 included a positive adjustment of approximately 59.1 Bcfe related primarily to positive well performance in our Warrior North prospect in Ohio and increased ethane recovery expectations.

Our revisions in 2015 included a negative adjustment of approximately 741.1 Bcfe related to lower commodity prices. This negative adjustment was partially offset by positive revision of approximately 15.4 Bcfe related to positive operating expenses, 4.1 Bcfe related to changes in our ethane recovery expectations and 18.6 Bcfe related to technical revisions. The positive technical revisions included 10.3 Bcfe in our Butler County, Pennsylvania area related to positive well performance. An additional 9.8 Bcfe of positive technical revisions were related to positive well performance in our Warrior North prospect in Ohio. These additions were partially offset by approximately 2.2 Bcfe in negative technical revisions related to well performance in our other areas of operation.

Extensions, discoveries and other additions. These are additions to estimated proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with estimated proved reserves or of new reservoirs of estimated proved reserves in old fields.

We had extensions, discoveries and other additions for the year ended December 31, 2017, of 1.9 MMBOE of oil, 22.3 MMBOE of NGLs and 164.0 Bcfe of natural gas. We had extensions, discoveries and other additions for the year ended December 31, 2016, of 0.4 MMBOE of oil, 2.2 MMBOE of NGLs and 11.1 Bcfe of natural gas. We had significant extensions, discoveries and other additions for the year ended December 31, 2015 of 0.9 MMBOE of oil, 10.1 MMBOE of NGLs and 76.8 Bcfe of natural gas. Our continued success in the Appalachian Basin has been the primary contributor to the growth of our extensions, discoveries and other additions, specifically the Marcellus and Utica Shales. At December 31, 2017, 100.0% of our extensions, discoveries and other additions were related to Marcellus Shale and Utica Shale properties.

FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of estimated proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.

The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

The following summary sets forth our future net cash flows relating to proven oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2017, 2016 and 2015 ($ in thousands):

The principal sources of change in the standardized measure of discounted future net cash flows are as follows:

Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation):

Litigation Related to Proposed Oil and Gas Leases in Clearfield County, Pennsylvania

In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to these proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees.

On May 9, 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that no contracts were formed between the Company and the plaintiffs. The plaintiffs appealed the dismissal to the Superior Court of Pennsylvania on May 16, 2012. On May 3, 2013, a three-judge panel of the Pennsylvania Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings.

In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in the Cardinale and Billotte cases and the plaintiffs in Meeker would be included in a class under the Cardinale and Billotte cases if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, it was consolidated with the Billotte case. The Meeker case has not been consolidated with the Cardinale and Billotte cases.

On June 19, 2015, the trial court conducted a hearing on plaintiffs’ motion for class certification in the Cardinale case. On July 6, 2015, the trial court issued an order denying plaintiffs’ motion for class certification. Plaintiffs served notice of their appeal of that decision in August 2015. In June 2016, oral argument was conducted before a three-judge panel of the Pennsylvania Superior Court. On January 17, 2017, the Superior Court vacated the trial court’s order denying class certification and remanded the case to the trial court for a redetermination of whether class certification is proper in the case.

On January 31, 2017, the Company filed an Application for Reargument Before En Banc Court and/or Panel Reconsideration, which was denied by the Superior Court on March 21, 2017. On April 20, 2017, the Company filed a Petition for Allowance of Appeal to the Supreme Court of Pennsylvania, which was denied on November 20, 2017.

The case has been remanded to the trial court for further consideration. The trial court entered a scheduling order setting a briefing schedule for plaintiffs to file a supplemental motion for class certification. A hearing regarding the supplemental motion for class certification has been scheduled for September 12, 2018.

We intend to continue to vigorously defend against these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses.

The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.

	2016
	March			June			September			December
Revenues	$	25,686		$	31,265		$	34,039		$	48,027
Impairment Expense		10,641			25,136			9,563			29,279
Other Costs and Expenses		67,696			59,040			40,953			94,346
Net Loss From Continuing Operations		(52,651	)		(52,911	)		(16,477	)		(75,598	)
Net Income (Loss) From Discontinued Operations, Net of Income Taxes		(7,490	)		(1,683	)		21,892			8,203
Net Income (Loss) Attributable to Rex Energy		(60,141	)		(54,594	)		5,415			(67,395	)
Preferred Stock Dividends		(2,105	)		(1,723	)		(613	)		(650	)
Effect of Preferred Stock Conversions		—			72,316			—			668
Net Income (Loss) Attributable to Common Shareholders	$	(62,246	)	$	15,999		$	4,802		$	(67,377	)
Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Continuing Operations	$	(9.78	)	$	2.45		$	(1.89	)	$	(7.77	)
Basic — Discontinued Operations		(1.34	)		(0.23	)		2.41			0.84
Basic — Net Income (Loss)	$	(11.12	)	$	2.22		$	0.52		$	(6.93	)
Basic — Weighted Average Shares Outstanding		5,600			7,180			9,080			9,740
Diluted — Continuing Operations	$	(9.78	)	$	2.45		$	(1.89	)	$	(7.77	)
Diluted — Discontinued Operations		(1.34	)		(0.23	)		2.41			0.84
Diluted — Net Income (Loss)	$	(11.12	)	$	2.22		$	0.52		$	(6.93	)
Diluted — Weighted Average Shares Outstanding		5,600			7,180			9,080			9,740

As of December 31, 2017, we had $600.3 million of outstanding Senior Notes, as shown in Note 9, Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of December 31, 2017:

The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of December 31, 2017, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.

The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of December 31, 2017 and 2016, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years ended December 31, 2017, 2016 and 2015.

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	15,244		$	—		$	3		$	—		$	15,247
Accounts Receivable		25,974			—			—			—			25,974
Taxes Receivable		—			—			2,049			—			2,049
Short-Term Derivative Instruments		8,008			—			—			—			8,008
Inventory, Prepaid Expenses and Other		2,106			—			2,508			—			4,614
Total Current Assets		51,332			—			4,560			—			55,892
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,086,625			—			—			—			1,086,625
Unevaluated Oil and Gas Properties		186,523			—			—			—			186,523
Other Property and Equipment		19,640			—			—			—			19,640
Wells and Facilities in Progress		38,660			—			—			—			38,660
Pipelines		16,803			—			—			—			16,803
Total Property and Equipment		1,348,251			—			—			—			1,348,251
Less: Accumulated Depreciation, Depletion and Amortization		(463,899	)		—			—			—			(463,899	)
Net Property and Equipment		884,352			—			—			—			884,352
Other Assets		44			—			—			—			44
Intercompany Receivables		—			—			1,072,637			(1,072,637	)		—
Investment in Subsidiaries – Net		(2,484	)		—			(272,261	)		274,745			—
Long-Term Derivative Instruments		(2	)		—			1,721			—			1,719
Deferred Tax Assets - Long-Term		—			—			130			—			130
Total Assets	$	933,242		$	—		$	806,787		$	(797,892	)	$	942,137
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	62,354		$	—		$	—		$	—		$	62,354
Current Maturities of Long-Term Debt		1,926			—			832,399			—			834,325
Accrued Liabilities		32,214			—			13,004			—			45,218
Short-Term Derivative Instruments		14,892			—			—			—			14,892
Total Current Liabilities		111,386			—			845,403			—			956,789
Long-Term Derivative Instruments		14,249			—			—			—			14,249
Long-Term Debt		—			—			—			—			—
Other Long-Term Debt		8,156			—			—			—			8,156
Other Deposits and Liabilities		7,153			—			—			—			7,153
Future Abandonment Cost		9,352			—			—			—			9,352
Intercompany Payables		1,068,231			4,406			—			(1,072,637	)		—
Total Liabilities		1,218,527			4,406			845,403			(1,072,637	)		995,699
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			10			—			10
Additional Paid-In Capital		177,144			—			652,917			(177,144	)		652,917
Accumulated Deficit		(462,429	)		(4,406	)		(691,544	)		451,889			(706,490	)
Total Stockholders’ Equity		(285,285	)		(4,406	)		(38,616	)		274,745			(53,562	)
Total Liabilities and Stockholders’ Equity	$	933,242		$	—		$	806,787		$	(797,892	)	$	942,137

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	205,246		$	—		$	—		$	—	$	205,246
Other Revenue		20			—			—			—		20
TOTAL OPERATING REVENUE		205,266			—			—			—		205,266
OPERATING EXPENSES
Production and Lease Operating Expense		120,794			—			—			—		120,794
General and Administrative Expense		16,601			—			1,257			—		17,858
Gain on Disposal of Assets		(1,428	)		—			—			—		(1,428	)
Impairment Expense		21,383			—			—			—		21,383
Exploration Expense		527			—			—			—		527
Depreciation, Depletion, Amortization and Accretion		58,713			315			—			—		59,028
Other Operating Expense		611			—			—			—		611
TOTAL OPERATING EXPENSES		217,201			315			1,257			—		218,773
LOSS FROM OPERATIONS		(11,935	)		(315	)		(1,257	)		—		(13,507	)
OTHER INCOME (EXPENSE)
Interest Expense		(2,288	)		—			(46,538	)		—		(48,826	)
Loss on Derivatives, Net		(131	)		—			(1,216	)		—		(1,347	)
Other Income (Expense)		(270	)		(7	)		16			—		(261	)
Loss on Extinguishment of Debt		—			—			(3,029	)		—		(3,029	)
Loss From Equity in Consolidated Subsidiaries		(309	)		—			(14,337	)		14,646		—
TOTAL OTHER INCOME (EXPENSE)		(2,998	)		(7	)		(65,104	)		14,646		(53,463	)
LOSS BEFORE INCOME TAX		(14,933	)		(322	)		(66,361	)		14,646		(66,970	)
Income Tax (Expense) Benefit		596			13			2,119			—		2,728
NET LOSS		(14,337	)		(309	)		(64,242	)		14,646		(64,242	)
Preferred Stock Dividends		—			—			(2,392	)		—		(2,392	)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(14,337	)	$	(309	)	$	(66,634	)	$	14,646	$	(66,634	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(14,337	)	$	(309	)	$	(64,242	)	$	14,646		$	(64,242	)
Adjustments to Reconcile Net Loss to Net Cash Provided (Used) by Operating Activities
Depreciation, Depletion, Amortization and Accretion		58,713			315			—			—			59,028
Loss on Derivatives		131			—			1,216			—			1,347
Cash Settlements of Derivatives		(10,100	)		—			—			—			(10,100	)
Non-Cash Dry Hole Expense		13			—			—			—			13
Equity-based Compensation Expense		(1	)		—			1,232			—			1,231
Impairment Expense		21,383			—			—			—			21,383
Amortization of Debt Issue Costs		—			—			1,165			—			1,165
Non-cash Interest Expense related to Debt Restructurings and Exchanges		—			—			14,063			—			14,063
Loss on Extinguishment of Debt		—			—			3,029			—			3,029
Gain on Sale of Assets		(1,428	)		—			—			—			(1,428	)
Deferred Income Tax Benefit		—			—			(130	)		—			(130	)
Other Non-cash Expenses		471			—			—			—			471
Changes in operating assets and liabilities
Accounts Receivable		5,261			—			(3	)		—			5,258
Taxes Receivable		—			—			(1,839	)		—			(1,839	)
Inventory, Prepaid Expenses and Other Assets		(1,159	)		—			(901	)		—			(2,060	)
Accounts Payable and Accrued Liabilities		6,000			—			8,558			—			14,558
Other Assets and Liabilities		(3,210	)		—			(49	)		—			(3,259	)
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		61,737			6			(37,901	)		14,646			38,488
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		36,631			(6	)		(21,979	)		(14,646	)		—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		31,704			—			—			—			31,704
Acquisitions of Undeveloped Acreage		(3,805	)		—			—			—			(3,805	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(113,411	)		—			—			—			(113,411	)
NET CASH PROVIDED (USED) BY INVESTING ACTIVITIES		(48,881	)		(6	)		(21,979	)		(14,646	)		(85,512	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			—			217,000			—			217,000
Repayments of Long-Term Debt and Lines of Credit		—			—			(145,170	)		—			(145,170	)
Repayments of Loans and Other Notes Payable		(1,306	)		—			—			—			(1,306	)
Debt Issuance Costs		—			—			(10,754	)		—			(10,754	)
Dividends Paid on Preferred Stock		—			—			(1,196	)		—			(1,196	)
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES		(1,306	)		—			59,880			—			58,574
NET INCREASE IN CASH		11,550			0			(0	)		0			11,550
CASH – BEGINNING		3,694			—			3			—			3,697
CASH - ENDING	$	15,244		$	0		$	3		$	0		$	15,247

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,694		$	—		$	3		$	—		$	3,697
Accounts Receivable		22,609			—			2,839			—			25,448
Taxes Receivable		—			—			211			—			211
Short-Term Derivative Instruments		1,873			—			—			—			1,873
Inventory, Prepaid Expenses and Other		2,521			—			25			—			2,546
Total Current Assets		30,697			—			3,078			—			33,775
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,053,461			—			—			—			1,053,461
Unevaluated Oil and Gas Properties		215,794			—			—			—			215,794
Other Property and Equipment		21,401			—			—			—			21,401
Wells and Facilities in Progress		21,964			—			—			—			21,964
Pipelines		18,029			—			—			—			18,029
Total Property and Equipment		1,330,649			—			—			—			1,330,649
Less: Accumulated Depreciation, Depletion and Amortization		(475,205	)		—			—			—			(475,205	)
Net Property and Equipment		855,444			—			—			—			855,444
Deferred Financing Costs and Other Assets—Net		2,492			—			—			—			2,492
Intercompany Receivables		—			—			1,035,713			(1,035,713	)		—
Investment in Subsidiaries – Net		(2,388	)		—			(127,974	)		130,362			—
Long-Term Derivative Instruments		(723	)		—			2,935			—			2,212
Total Assets	$	885,522		$	—		$	913,752		$	(905,351	)	$	893,923
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	40,712		$	—		$	—		$	—		$	40,712
Current Maturities of Long-Term Debt		764			—			—			—			764
Accrued Liabilities		32,328			421			4,458			—			37,207
Short-Term Derivative Instruments		25,025			—			—			—			25,025
Total Current Liabilities		98,829			421			4,458			—			103,708
Long-Term Derivative Instruments		7,227			—			—			—			7,227
Long-Term Debt		—			—			751,946			—			751,946
Other Long-Term Debt		3,409			—			—			—			3,409
Other Deposits and Liabilities		8,671			—			—			—			8,671
Future Abandonment Cost		8,736			—									8,736
Intercompany Payables		1,032,050			3,663			—			(1,035,713	)		—
Total Liabilities		1,158,922			4,084			756,404			(1,035,713	)		883,697
Stockholders’ Equity
Preferred Stock		—			—			1			—			1
Common Stock		—			—			10			—			10
Additional Paid-In Capital		177,144			—			650,669			(177,144	)		650,669
Accumulated Deficit		(450,544	)		(4,084	)		(493,332	)		307,506			(640,454	)
Total Stockholders’ Equity		(273,400	)		(4,084	)		157,348			130,362			10,226
Total Liabilities and Stockholders’ Equity	$	885,522		$	—		$	913,752		$	(905,351	)	$	893,923

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	139,000		$	—		$	—		$	—	$	139,000
Other Revenue		17			—			—			—		17
TOTAL OPERATING REVENUE		139,017			—			—			—		139,017
OPERATING EXPENSES
Production and Lease Operating Expense		104,699			—			—			—		104,699
General and Administrative Expense		17,488			5			3,128			—		20,621
Gain on Disposal of Assets		(4,121	)		—			—			—		(4,121	)
Impairment Expense		74,624			(5	)		—			—		74,619
Exploration Expense		2,177			1			—			—		2,178
Depreciation, Depletion, Amortization and Accretion		62,849			25			—			—		62,874
Other Operating Expense		10,754			—			—			—		10,754
TOTAL OPERATING EXPENSES		268,470			26			3,128			—		271,624
LOSS FROM OPERATIONS		(129,453	)		(26	)		(3,128	)		—		(132,607	)
OTHER INCOME (EXPENSE)
Interest Expense		(1,326	)		—			(42,193	)		—		(43,519	)
Gain (Loss) on Derivatives, Net		(34,285	)		—			1,770			—		(32,515	)
Other Income (Expense)		41			—			(2,165	)		—		(2,124	)
Debt Exchange Expense		—			—			(9,063	)		—		(9,063	)
Gain on Extinguishment of Debt		—						24,627			—		24,627
Income (Loss) From Equity in Consolidated Subsidiaries		(94	)		94			(146,344	)		146,344		—
TOTAL OTHER INCOME (EXPENSE)		(35,664	)		94			(173,368	)		146,344		(62,594	)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(165,117	)		68			(176,496	)		146,344		(195,201	)
Income Tax Expense		(2,060	)		—			(376	)		—		(2,436	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(167,177	)		68			(176,872	)		146,344		(197,637	)
Income (Loss) From Discontinued Operations, Net of Income Tax		20,887			(122	)		157					20,922
NET LOSS		(146,290	)		(54	)		(176,715	)		146,344		(176,715	)
Preferred Stock Dividends		—			—			(5,091	)		—		(5,091	)
Effect of Preferred Stock Conversion		—			—			72,984			—		72,984
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(146,290	)	$	(54	)	$	(108,822	)	$	146,344	$	(108,822	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(146,290	)	$	(54	)	$	(176,715	)	$	146,344		$	(176,715	)
Adjustments to Reconcile Net Loss to Net Cash Used by Operating Activities
Depreciation, Depletion, Amortization and Accretion		67,915			60			—			—			67,975
Gain (Loss) on Derivatives		34,285			—			(1,770	)		—			32,515
Cash Settlements of Derivatives		32,571			—			—			—			32,571
Non-Cash Dry Hole Expense		905			—			—			—			905
Equity-based Compensation Expense		40			—			2,919			—			2,959
Impairment Expense		78,160			2			78,162			(78,162	)		78,162
Amortization of Debt Issuance Costs		—			—			1,640			—			1,640
Amortization of Bond Discounts and Premiums		—			—			(100	)		—			(100	)
Non-cash Interest Expense related to Debt Restructurings and Exchanges		—			—			19,603			—			19,603
Gain on Extinguishment of Debt		—			—			(24,627	)		—			(24,627	)
(Gain) Loss on Sale of Assets		(34,697	)		46			—			—			(34,651	)
Other Non-cash (Income) Expense		(208	)		—			230			—			22
Changes in operating assets and liabilities
Accounts Receivable		(44,354	)		(863	)		38,803			—			(6,414	)
Inventory, Prepaid Expenses and Other Assets		906			—			—			—			906
Accounts Payable and Accrued Liabilities		8,815			—			(6,020	)		—			2,795
Other Assets and Liabilities		(1,953	)		3			—			—			(1,950	)
NET CASH USED BY OPERATING ACTIVITIES		(3,905	)		(806	)		(67,875	)		68,182			(4,404	)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		3,587			(94	)		64,689			(68,182	)		—
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		39,904			980			—			—			40,884
Proceeds from Joint Venture		19,461			—			—			—			19,461
Acquisitions of Undeveloped Acreage		(6,671	)		(41	)		—			—			(6,712	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(48,943	)		(39	)		—			—			(48,982	)
NET CASH PROVIDED BY INVESTING ACTIVITIES		7,338			806			64,689			(68,182	)		4,651
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			—			71,400			—			71,400
Repayments of Long-Term Debt and Lines of Credit		—			—			(65,230	)		—			(65,230	)
Repayments of Loans and Other Notes Payable		(828	)		—			—			—			(828	)
Debt Issuance Costs		—			—			(2,983	)		—			(2,983	)
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES		(828	)		—			3,187			—			2,359
NET INCREASE IN CASH		2,605			0			1			—			2,606
CASH – BEGINNING		1,089			—			2			—			1,091
CASH - ENDING	$	3,694		$	0		$	3		$	—		$	3,697

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	138,707		$	—		$	—		$	—	$	138,707
Other Revenue		42			—			—			—		42
TOTAL OPERATING REVENUE		138,749			—			—			—		138,749
OPERATING EXPENSES
Production and Lease Operating Expense		93,892			—			—			—		93,892
General and Administrative Expense		20,849			—			5,845			—		26,694
Gain on Disposal of Assets		(540	)		—			—			—		(540	)
Impairment Expense		282,833			411			—			—		283,244
Exploration Expense		2,616			1			—			—		2,617
Depreciation, Depletion, Amortization and Accretion		85,839			5			—			—		85,844
Other Operating Expense		5,603			—			—			—		5,603
TOTAL OPERATING EXPENSES		491,092			417			5,845			—		497,354
LOSS FROM OPERATIONS		(352,343	)		(417	)		(5,845	)		—		(358,605	)
OTHER INCOME (EXPENSE)
Interest Expense		(248	)		—			(47,535	)		—		(47,783	)
Gain on Derivatives, Net		59,242			—			934			—		60,176
Other Expense		(129	)		—			—			—		(129	)
Loss From Equity Method Investments		(411	)		—			—			—		(411	)
Income (Loss) From Equity in Consolidated Subsidiaries		(429	)		429			(309,250	)		309,250		—
TOTAL OTHER INCOME (EXPENSE)		58,025			429			(355,851	)		309,250		11,853
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(294,318	)		12			(361,696	)		309,250		(346,752	)
Income Tax Expense		(5,111	)		(7	)		(912	)		—		(6,030	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(299,429	)		5			(362,608	)		309,250		(352,782	)
Income (Loss) From Discontinued Operations, Net of Income Taxes		(45,546	)		37,965			(670	)		—		(8,251	)
NET INCOME (LOSS)		(344,975	)		37,970			(363,278	)		309,250		(361,033	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			2,245			—			—		2,245
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY		(344,975	)		35,725			(363,278	)		309,250		(363,278	)
Preferred Stock Dividends		—			—			(9,660	)		—		(9,660	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(344,975	)	$	35,725		$	(372,938	)	$	309,250	$	(372,938	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(344,975	)	$	37,970		$	(363,278	)	$	309,250		$	(361,033	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided (Used) by Operating Activities
Loss on Equity Method Investments		411			—			—			—			411
Depreciation, Depletion, Amortization and Accretion		105,555			3,230			—			(3,963	)		104,822
Gain on Derivatives		(59,242	)		—			(934	)		—			(60,176	)
Cash Settlements of Derivatives		54,859			—			934			—			55,793
Non-Cash Dry Hole Expense		199			136			—			(5	)		330
Equity-based Compensation Expense		99			—			6,450			—			6,549
Impairment Expense		345,892			1,396			345,892			(347,405	)		345,775
Amortization of Debt Issuance Costs		17			13			2,015			—			2,045
Amortization of Bond Discounts and Premiums		—			—			(381	)		—			(381	)
Gain on Sale of Assets		(477	)		(44	)		—			—			(521	)
Gain on Sale of Water Solutions		—			—			(57,778	)		—			(57,778	)
Other Non-cash Income (Expense)		(218	)		(346	)		—			—			(564	)
Changes in operating assets and liabilities
Accounts Receivable		24,240			(453	)		429			(2,537	)		21,679
Inventory, Prepaid Expenses and Other Assets		(431	)		(142	)		5			—			(568	)
Accounts Payable and Accrued Liabilities		(20,008	)		(4,969	)		(515	)		2,537			(22,955	)
Other Assets and Liabilities		(2,497	)		(73	)		27			—			(2,543	)
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES		103,424			36,718			(67,134	)		(42,123	)		30,885
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		96,664			(37,425	)		(100,198	)		40,959			—
Proceeds from Joint Venture Acreage Management		58			—			—			—			58
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		9,766			560			66,900			—			77,226
Proceeds from Joint Venture		16,611			—			—			—			16,611
Acquisitions of Undeveloped Acreage		(27,963	)		(279	)		—			—			(28,242	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(214,450	)		(7,813	)		—			1,164			(221,099	)
NET CASH PROVIDED USED BY INVESTING ACTIVITIES		(119,314	)		(44,957	)		(33,298	)		42,123			(155,446	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			35,814			193,500			—			229,314
Repayments of Long-Term Debt and Lines of Credit		—			(26,335	)		(82,000	)		—			(108,335	)
Repayments of Loans and Other Notes Payable		(999	)		(520	)		—			—			(1,519	)
Debt Issuance Costs		—			(3	)		(1,411	)		—			(1,414	)
Distribution by the Partners of Consolidated Subsidiary		—			(830	)		—			—			(830	)
Dividends Paid on Preferred Stock		—			—			(9,660	)		—			(9,660	)
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES		(999	)		8,126			100,429			—			107,556
NET DECREASE IN CASH		(16,889	)		(113	)		(3	)		—			(17,005	)
CASH – BEGINNING		17,978			113			5			—			18,096
CASH - ENDING	$	1,089		$	(0	)	$	2		$	—		$	1,091

On March 13, 2018, the Company, entered into a Purchase and Sale Agreement with XPR Resources, LLC (“XPR”), pursuant to which the Company agreed to sell to XPR certain of its non-operated oil and gas interests in 61 wells located in Westmoreland and Clearfield Counties, Pennsylvania, along with associated production and other ancillary assets. The acreage sold was considered non-core to the Company. In a related transaction, the Company entered into a Membership Interest Purchase Agreement on the same date with COG2, LLC (“COG2”), an affiliate of XPR, pursuant to which the Company agreed to sell to COG2 its 40% membership interest in RW Gathering, LLC. Closing occurred on March 21, 2018, with an effective date for the transactions of January 1, 2018. Total consideration for the transactions was approximately $17.2 million, subject to customary closing and post-closing adjustments. We received approximately $16.4 million of proceeds on March 23, 2018. Approximately $0.2 million of the total proceeds due to us is being held in escrow. The sale of assets resulted in a loss on the disposal of assets of approximately $0.6 million in the first quarter of 2018.

Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures to ensure that material information relating to the company is made known to the officers who certify the financial statements and to other members of senior management and the audit committee of our board of directors. as of December 31, 2017, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer (the “CEO”) and the Chief Financial Officer (the “CFO”), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e), and 15d-15(e) under the Securities Exchange Act of 1934). An evaluation was conducted to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our CEO and CFO have concluded that our disclosure controls and procedures were effective as of the date of such evaluation.

Changes in Internal Control over Financial Reporting. No change to our internal control over financial reporting occurred during the year ended December 31, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f), and 15d-15(f) under the Securities Exchange Act of 1934). Management has used the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission entitled Internal Control-Integrated Framework (2013) to evaluate the effectiveness of our internal control over financial reporting. Internal control over financial reporting refers to the process designed by, or under the supervision of, our CEO and CFO, and overseen by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

Our internal control over financial reporting 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 generally accepted accounting principles, however, neither internal control over financial reporting nor disclosure controls and procedures can provide absolute assurance of achieving financial reporting objectives because of their inherent limitations. Internal control over financial reporting and disclosure controls are processes that involve human diligence and compliance, and are subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting and disclosure controls also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented, detected or reported on a timely basis by internal control over financial reporting or disclosure controls. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design safeguards for these processes that will reduce, although may not eliminate, these risks.

Management has concluded that our internal controls over financial reporting and our disclosure controls and procedures were effective as of December 31, 2017. Management reviewed the results of their assessment with our Audit Committee. The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by KPMG, LLP an independent registered public accounting firm, as stated in their report which is set forth below.

We have audited Rex Energy Corporation and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the committee of sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in non-controlling interests and stockholders’ equity (deficit) and cash flows for each of the years in the three-year period ended December 31, 2017, and the related notes (collectively, the consolidated financial statements), and our report dated April 13, 2018 expressed an unqualified opinion on those consolidated financial statements. Our report dated April 13, 2018, contains an explanatory paragraph that states there is substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting 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 generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

The information required by this item is incorporated by reference to such information as set forth in our definitive Proxy Statement (the “2018 Proxy Statement”) for our 2018 annual meeting of stockholders. The 2018 Proxy statement will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

The information required by this item is incorporated herein by reference to the 2018 Proxy Statement for the 2018 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2017.

All other schedules are omitted because they are not applicable, not required, or because the required information is included in the financial statements or related notes.

The following is a description of the meanings of some of the oil and gas industry terms used in this report:

Basin. A large natural depression on the earth’s surface in which sediments accumulate.

Bcf. Billion cubic feet, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or gas.

Development or Developmental well. A well drilled within the proved boundaries of an oil or gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses, taxes and the royalty burden.

Estimated proved reserves. Those quantities of oil and gas, which, by analysis of geosciences 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, 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 project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geosciences and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Exploitation. A drilling or other project which may target proved or unproved reserves (such as probable or possible reserves), but generally is expected to have lower risk.

Exploration or Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

Injection well or Injection. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

PV-10 or present value of estimated future cash flows. An estimate of the present value of the estimated future cash flows from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future cash flows are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future cash flows are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.

Primary recovery. The period of production in which oil and natural gas is produced from its reservoir through the wellbore without enhanced recovery technologies, such as water floods or ASP floods.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed non-producing reserves or PDNP. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves or PDP. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved developed reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate

Proved undeveloped reserves or PUD. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Recompletion. The addition of production from another interval or formation in an existing wellbore.

Reserve life index. An index calculated by dividing year-end estimated proved reserves by the average production during the past year to estimate the number of years of remaining production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Secondary recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.

Tertiary recovery. The third stage of hydrocarbon production during which sophisticated techniques that alter the original properties of the oil are used. Chemical flooding (including ASP flooding), miscible displacement and thermal flooding are examples of this technique.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether or not such acreage contains estimated proved reserves.

Waterflooding. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

	For the Years Ended December 31, ($ in thousands)
	2018 (Estimated)		2017 (Actual)
Capital Expenditures
Drilling & Completion	$	80,000	$	131,635
Other Field Assets		300		743
Other Corporate Expenditures		400		416
Total Capital Expenditures¹	$	80,700	$	132,794

	Net Reserves
Category	Condensate (Barrels)		NGL (Barrels)		Gas (Mcf)
Proved Developed		2,101,700		62,453,700		504,971,200
Proved Developed Non-Producing		133,700		2,284,800		14,147,300
Proved Undeveloped		1,233,900		7,543,300		59,261,000
Total Proved		3,469,300		72,281,800		578,379,500

	2017		2016		2015
Description
Proved Developed Reserves
Condensate (Bbls)		2,235,400		1,865,900		1,544,000
Natural Gas (Mcf)		519,118,500		367,641,300		389,754,400
NGLs (Bbls)		64,738,500		44,824,400		37,941,900
Proved Undeveloped Reserves
Condensate (Bbls)		1,233,900		—		372,500
Natural Gas (Mcf)		59,261,000		—		16,708,400
NGLs (Bbls)		7,543,300		—		2,404,700
Total Estimated Proved Reserves (Mcfe)^{1, 2}		1,032,886,100		647,783,100		660,041,400
Standardized Measure (millions)³	$	507.0	$	165.6	$	255.6
PV-10 Value (millions)³	$	541.0	$	175.5	$	272.7

Proved Undeveloped Reserves (Mcfe)	For the Year Ended December 31, 2017
Beginning proved undeveloped reserves		—
Sales of Reserves in Place		—
Undeveloped reserves converted to developed		—
Revisions		—
Extensions and discoveries		111,924,200
Ending proved undeveloped reserves		111,924,200

	Undeveloped Acreage¹				Developed Acreage²				Total Acreage				Producing Gas Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Appalachian Basin
Pennsylvania		33,117		27,102		158,005		101,695		191,122		128,797		521		182
Ohio		593		593		12,919		11,636		13,512		12,229		33		21
Total		33,710		27,695		170,924		113,331		204,634		141,026		554		203

Title of each class		Name of each exchange on which registered
Common Stock, $.001 par value per share		The Nasdaq Capital Market

PART I
Item 1.	Business	6
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	40
Item 4.	Mine Safety Disclosures	40
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	41
Item 6.	Selected Financial Data	44
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	75
Item 8.	Financial Statements and Supplementary Data	78
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	138
Item 9A.	Controls and Procedures	138
Item 9B.	Other Information	140
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	140
Item 11.	Executive Compensation	140
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	140
Item 13.	Certain Relationships and Related Transactions and Director Independence	140
Item 14.	Principal Accountant Fees and Services	140
PART IV
Item 15.	Exhibits and Financial Statement Schedules	141
Item 16.	Form 10-K Summary	147
GLOSSARY SIGNATURES

	Production and Revenue For the Years Ended December 31, ($ in thousands)
	2017		2016		2015
Revenue	$	205,246	$	139,000	$	138,707
Condensate Production (Bbls)¹		267,585		360,384		402,867
Natural Gas Production (Mcf)		41,456,680		44,684,571		44,606,753
C3+ NGL Production (Bbls)		1,851,414		1,996,075		2,026,321
Ethane (Bbls)		2,196,050		2,111,321		1,319,582
Total Production (Mcfe)²		67,346,974		71,491,251		67,099,373
Condensate Average Sales Price	$	44.89	$	37.08	$	34.92
Natural Gas Average Sales Price	$	2.74	$	1.64	$	1.86
C3+ NGL Average Sales Price	$	31.21	$	17.97	$	16.18
Ethane Average Sales Price	$	9.96	$	7.81	$	6.60
Average Production Cost per Mcfe³	$	1.79	$	1.45	$	1.39

	Expiring Acreage
	Gross		Net
Year Ending December 31,
2018		22,522		17,627
2019		9,512		8,317
2020		377		304
2021		143		137
2022		239		197
Thereafter		4		4
Total		32,797		26,586

2017	High		Low
First Quarter	$	0.98	$	0.41
Second Quarter	$	4.71	$	0.32
Third Quarter	$	3.15	$	2.10
Fourth Quarter	$	2.70	$	1.25

2016	High		Low
First Quarter	$	2.43	$	0.52
Second Quarter	$	1.44	$	0.55
Third Quarter	$	0.74	$	0.45
Fourth Quarter	$	0.64	$	0.28

	Rex Energy		DJ U.S. E&P Index		S&P
December 31, 2012	$	100	$	100	$	100
December 31, 2013	$	151	$	130	$	130
December 31, 2014	$	39	$	114	$	144
December 31, 2015	$	8	$	86	$	143
December 31, 2016	$	4	$	105	$	157
December 31, 2017	$	11	$	105	$	187

Calendar Quarter Ending	West Texas Intermediate Average Price per Bbl
3/31/2018	$	61.25
6/30/2018	$	61.75
9/30/2018	$	62.25
12/31/2018	$	62.75
3/31/2019	$	63.25
6/30/2019	$	63.75

	Year Ended December 31,
	2017		% of Total			2016		% of Total			2015		% of Total
Sources of Revenue ($ in thousands)
Revenue from Condensate Sales	$	12,012		5.9	%	$	13,364		9.6	%	$	14,068		10.1	%
Revenue from Natural Gas Sales		113,575		55.3	%		73,275		52.7	%		83,140		59.9	%
Revenue from C3+ NGL Sales		57,780		28.1	%		35,877		25.8	%		32,789		23.6	%
Revenue from Ethane Sales		21,879		10.7	%		16,484		11.9	%		8,710		6.3	%
Other		20		0.0	%		17		0.0	%		42		0.0	%
Total	$	205,266		100.0	%	$	139,017		100.0	%	$	138,749		100.0	%

	Performance Measurements
	For the Years Ended December 31,
	2017		2016		2015
EBITDAX ($ in thousands)	$	58,123	$	45,272	$	78,787
Lease Operating Expense per Mcfe	$	1.79	$	1.46	$	1.40
Total Estimated Proved Reserves (Bcfe)		1,032.9		647.8		680.4
G&A per Mcfe	$	0.27	$	0.29	$	0.40

	Payment Due by Period (in thousands)
	2018		2019		2020		2021		2022		Thereafter		Total
Senior Notes (a)	$	600,302	$	—	$	—	$	—	$	—	$	—	$	600,302
Operating Leases		1,013		1,020		888		475		485		—		3,881
Other Loans and Notes Payable		191,426		2,252		2,636		2,462		806		—		199,582
Derivative Obligations (b)		8,136		6,631		3,569		1,190		806		803		21,135
Firm Commitments (c)		75,857		67,463		66,171		63,174		62,739		529,633		865,037
Asset Retirement Obligations (d)		597		2,344		406		6		13		6,573		9,939
Total Contractual Obligations	$	877,331	$	79,710	$	73,670	$	67,307	$	64,849	$	537,009	$	1,699,876

		Page
Report of Independent Registered Public Accounting Firm		79
Consolidated Balance Sheets at December 31, 2017 and 2016		80
Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015		81
Consolidated Statements of Changes in Noncontrolling Interests and Stockholders’ Equity (Deficit) for the Years Ended December 31, 2017, 2016 and 2015		82
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015		83
Notes to the Consolidated Financial Statements		84

	December 31, 2017 (in thousands)			December 31, 2016 (in thousands)
Beginning Balance	$	9,865		$	11,934
Asset Retirement Obligation Incurred		1,061			575
Asset Retirement Obligation Settled		(3,187	)		(671	)
Asset Retirement Obligation Cancelled or Sold Properties		(549	)		(4,876	)
Asset Retirement Obligation Revision of Estimated Obligation		834			1,918
Asset Retirement Obligation Accretion Expense		1,915			985
Total Future Abandonment Costs	$	9,939		$	9,865

Calendar Quarter Ending	West Texas Intermediate ("WTI") Average Price per Bbl (a)
3/31/2018	$	61.25
6/30/2018	$	61.75
9/30/2018	$	62.25
12/31/2018	$	62.75
3/31/2019	$	63.25
6/30/2019	$	63.75

($ in thousands)
2018 (a)	$	791,728
2019		2,252
2020		2,636
2021		2,462
2022		806
Thereafter		—
Total (b)	$	799,884

				Fair Value Measurements at December 31, 2017 Using:
($ in Thousands)	Total Carrying Value as of December 31, 2017			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(19,414	)	$	—	$	(19,414	)	$	—

				Fair Value Measurements at December 31, 2016 Using:
($ in Thousands)	Total Carrying Value as of December 31, 2016			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	(28,167	)	$	—	$	(28,167	)	$	—

($ in Thousands)	Year Ended December 31, 2017			Year Ended December 31, 2016			Year Ended December 31, 2015
Income (Loss) from continuing operations before noncontrolling interests and income taxes	$	(66,970	)	$	(195,201	)	$	(346,752	)
Statutory U.S. income tax rate		35.0	%		35.0	%		35.0	%
Tax expense recognized using statutory U.S. income tax rate	$	(23,440	)	$	(68,320	)	$	(121,363	)
State income taxes, net of federal income tax benefit		(1,723	)		(3,632	)		(17,137	)
Change in future rates		79,322			(400	)		(212	)
Permanent differences		1,130			2,264			1,784
Change in valuation allowances		(57,622	)		72,784			143,566
Other		(395	)		(260	)		(608	)
Total income tax expense	$	(2,728	)	$	2,436		$	6,030
Effective income tax rate		4.07	%		-1.25	%		-1.74	%

	For the Years Ended December 31,
($ in Thousands)	2017			2016
Tax effects of temporary differences for:
Assets:
Asset retirement obligation	$	2,647		$	3,955
Deferred compensation plans		600			1,581
Compensation Accruals		390			762
Unrealized loss on derivatives		5,457			11,760
Net operating loss carryforwards		126,820			79,531
Deferred Financing Costs (a)		98,065			182,519
Gas Transportation Capacity Commitments		1,697			3,031
Deferred revenue timing differences		388			443
Organization costs		213			391
Percentage depletion carryforward		2,155			2,717
AMT credits		130			2,131
Timing differences - tax partnerships		465			1,046
Other		217			331
Valuation allowances		(154,416	)		(212,041	)
Total Deferred Tax Assets net of Valuation Allowances	$	84,828		$	78,157
Liabilities:
Book basis of oil and gas properties in excess of tax basis		(84,622	)		(77,690	)
Other		(76	)		(467	)
Total Deferred Tax Liabilities	$	(84,698	)	$	(78,157	)
Net Deferred Tax Asset	$	130		$	—

Year of Expiration	Net Operating Loss Carryforwards (in thousands)
2023		2
2024		—
2025		—
2026		572
2027		1,183
2028		35
2029		18
2030		95
2031		2,089
2032		36
2033		2,227
2034		2,730
2035		39,280
2036		15,236
2037		63,317
Total		126,820

	Year Ended December 31,			Year Ended December 31,			Year Ended December 31,
(in thousands, except per share amounts)	2017			2016			2015
Numerator:
Net Loss From Continuing Operations	$	(64,242	)	$	(197,637	)	$	(352,782	)
Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests		—			20,922			(10,496	)
Less: Preferred Stock Dividends		(2,392	)		(5,091	)		(9,660	)
Effect of Preferred Stock Conversions		—			72,984			—
Net Loss Attributable to Common Shareholders	$	(66,634	)	$	(108,822	)	$	(372,938	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		9,902			7,926			5,439
Effect of Dilutive Securities:
Employee Stock Options		—			—			—
Employee Performance-Based Restricted Stock Awards		—			—			—
Effect of Assumed Conversions of Preferred Stock		—			—			—
Weighted Average Common Shares Outstanding - Diluted		9,902			7,926			5,439
Earnings per Common Share Attributable to Rex Energy Common Shareholders(a):
Basic — Net Loss From Continuing Operations	$	(6.73	)	$	(16.37	)	$	(66.64	)
— Net Income (Loss) From Discontinued Operations		—			2.64			(1.93	)
— Net Loss Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(13.73	)	$	(68.57	)
Diluted — Net Loss From Continuing Operations	$	(6.73	)	$	(16.37	)	$	(66.64	)
— Net Income (Loss) From Discontinued Operations		—			2.64			(1.93	)
— Net Loss Attributable to Rex Energy Common Shareholders	$	(6.73	)	$	(13.73	)	$	(68.57	)

	Number of Shares			Weighted-Average Exercise Price		Weighted-Average Remaining Term (in years)		Aggregate Intrinsic Value (in thousands)
Options outstanding December 31, 2014		40,268		$	108.20
Granted		8,000			44.80
Exercised		—			—
Cancelled/Forfeited		(3,889	)		112.30
Options outstanding December 31, 2015		44,379		$	96.40
Granted		88,892			16.60
Exercised		—			—
Cancelled/Forfeited		(15,149	)		57.20
Options Outstanding December 31, 2016		118,122		$	41.40
Granted		—			—
Exercised		—			—
Cancelled/Forfeited		(31,791	)		72.60
Options Outstanding December 31, 2017		86,331		$	29.90		4.7	$	—
Options Exercisable December 31, 2017		32,746		$	45.30		4.2	$	—

		Outstanding				Exercisable
Exercise Price		Number Outstanding At 12/31/17		Weighted-Average Exercise Price		Number Exercisable At 12/31/17		Weighted-Average Exercise Price
$	9.70		2,750	$	9.70		919	$	9.70
$	16.90		67,294	$	16.90		22,873	$	16.90
$	40.50		4,000	$	40.50		—	$	—
$	49.00		4,000	$	49.00		667	$	49.00
$	50.40		3,070	$	50.40		3,070	$	50.40
$	104.20		2,217	$	104.20		2,217	$	104.20
$	223.40		3,000	$	223.40		3,000	$	223.40
			86,331	$	29.90		32,746	$	45.30

TSR Rank	Percentage of Awards to Vest
1-3		100	%
4-6		75	%
7-10		50	%
11-13		25	%
14-16		0	%

	Year Ended December 31, 2015
Expected Dividend Yield		0.0	%
Risk-Free Interest Rate		1.0	%
Expected Volatility – Rex Energy		58.6	%
Expected Volatility – Peer Group	29.8%-85.0%
Market Index		35.6	%
Expected Life	Three Years

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of December 31, 2014		152,005		$	140.50
Awards		223,684			33.50
Vested		(60,636	)		93.90
Forfeitures		(67,037	)		113.30
Restricted stock awards, as of December 31, 2015		248,016		$	62.70
Awards		142,309			9.10
Vested		(87,206	)		73.30
Forfeitures		(60,295	)		67.30
Restricted stock awards, as of December 31, 2016		242,824		$	26.30
Awards		101,237			5.18
Vested		(102,351	)		21.52
Forfeitures		(41,235	)		48.17
Restricted stock awards, as of December 31, 2017		200,475		$	13.62

	2017			2016
Consolidated Entities:
Proven Oil and Natural Gas Properties	$	1,086,625		$	1,055,467
Pipelines and Support Equipment		18,902			21,088
Field Operation Vehicles and Other Equipment		9,586			11,239
Wells and Facilities in Progress		38,660			21,964
Unproven Properties		186,523			215,794
Total		1,340,296			1,325,552
Less Accumulated Depreciation and Depletion		(459,652	)		(474,046	)
Total	$	880,644		$	851,506
Share of Equity Method Investments:
Pipelines and Support Equipment		19,963			19,962
Wells and Facilities in Progress		—			—
Total		19,963			19,962
Less Accumulated Depreciation and Depletion		(5,011	)		(4,211	)
Total	$	14,952		$	15,751

	2017
	Oil (MBbls)			NGL (MBbls)			Natural Gas (MMcf)			(MMcf) Equivalents
Estimated Proved Reserves-Beginning of Period		1,866.0			44,824.4			367,640.9			647,783.1
Extensions, Discoveries and Additions		1,929.6			22,295.2			164,222.7			309,571.7
Revisions of Previous Estimates		90.0			10,225.7			103,278.3			165,172.5
Sales of Reserves		(144.5	)		(984.4	)		(14,790.4	)		(21,563.8	)
Production		(271.8	)		(4,079.1	)		(41,972.0	)		(68,077.4	)
Estimated Proved Reserves-End of Period		3,469.3			72,281.8			578,379.5			1,032,886.1

		Page
Index to Financial Statements		78

Report of Independent Registered Public Accounting Firms		79

Consolidated Balance Sheets at December 31, 2017 and 2016		80

Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015		81

Consolidated Statements of Changes in Noncontrolling Interests and Stockholder’s Equity (Deficit) for the Years Ended December 31, 2017, 2016 and 2015		82

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015		83

Notes to the Consolidated Financial Statements		84

Exhibit Number		Exhibit Title
2.1-		Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on September 3, 2010).

2.2		First Amendment to Participation and Exploration Agreement, dated September 30, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on October 6, 2010).
2.3		Form of Area One Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed with the SEC on September 3, 2010).
2.4		Form of Area Two Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.3 to our Current Report on Form 8-K filed with the SEC on September 3, 2010).
2.5		Form of Area Three Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.4 to our Current Report on Form 8-K filed with the SEC on September 3, 2010).
2.6		Form of Area Four Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.5 to our Current Report on Form 8-K filed with the SEC on September 3, 2010).
2.7		Form of Parent Guaranty of Rex Energy Corporation attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.6 to our Current Report on Form 8-K filed with the SEC on September 3, 2010).
2.8		Form of Parent Guaranty of Sumitomo Corporation attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.7 to our Current Report on Form 8-K filed with the SEC on September 3, 2010).

2.9-		Participation Agreement, dated March 30, 2015, by and between R.E. Gas Development, LLC and AL Marcellus Holdings, LLC (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 11, 2015).

2.10		Membership Interest Purchase Agreement, dated June 18, 2015, by and between Rex Energy Corporation and Sand Hills Management, LLC, as Sellers, and American Industrial Water, LLC, as Purchaser (incorporated by reference to Exhibit 2.1 to our Amendment No. 1 to Quarterly Report on Form 10-Q filed with the SEC on October 9, 2015).

Exhibit Number		Exhibit Title
2.11		Amendment to Membership Interest Purchase Agreement, dated July 8, 2015, by and between Rex Energy Corporation and Sand Hills Management, LLC, as Sellers, and American Industrial Water, LLC, as Purchaser (incorporated by reference to Exhibit 2.2 to our Amendment No. 1 to Quarterly Report on Form 10-Q filed with the SEC on October 9, 2015).
2.12-		Joint Exploration and Development Agreement, dated as of March 1, 2016, by and between R.E. Gas Development, LLC and OhPa Drillco, LLC (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 10, 2016.

2.13-		Purchase and Sale Agreement by and among R.E. Gas Development, LLC, MFC Drilling, Inc., and ABARTA Oil & Gas Co., Inc., dated as of January 3, 2017 (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 10, 2017

3.1		Certificate of Incorporation of Rex Energy Corporation, as amended (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q filed with the SEC on August 9, 2017).

3.2		Amended and Restated Bylaws of Rex Energy Corporation, as amended (incorporated by reference to Exhibit 3.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 9, 2017).

4.1		Form of Specimen Common Stock Certificate of Rex Energy Corporation (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on June 11, 2007).

4.2		Form of 6.00% Convertible Perpetual Preferred Stock, Series A (included in Exhibit 3.1 to this Annual Report on Form 10-K).

4.3		Indenture dated as of December 12, 2012 among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012).

4.4		Form of 8.875% Senior Notes due 2020 (included in Exhibit 4.3 to this Annual Report on Form 10-K).

4.5		First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of December 12, 2012, among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed with the SEC on March 31, 2016).

4.6		Indenture dated as of July 17, 2014 among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on July 17, 2014).

4.7		Form of 6.250% Senior Notes due 2022 (included in Exhibit 4.6 to this annual Report on Form 10-K).

4.8		First Supplemental Indenture, dated as of March 31, 2016, to the Indenture dated as of July 17, 2014, among Rex Energy Corporation, the Guarantors named therein and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.3 to our Current Report on Form 8-K filed with the SEC on March 31, 2016).

4.9		Deposit Agreement, dated August 18, 2014, by and among the Company, Computershare Trust Company, N.A. and Computershare Inc., together as depositary, and holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).

4.10		Form of Depositary Receipt Representing the Depositary Shares (included in Exhibit 4.9 to this Annual Report on Form 10-K).

4.11		Indenture, dated as of March 31, 2016, among Rex Energy Corporation, the Guarantors named therein and Wilmington Savings Fund Society, FSB, as trustee (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on March 31, 2016).

4.12		Form of 1.00%/8.00% Senior Secured Second Lien Note due 2020 (included in Exhibit 4.11 to this Annual Report on Form 10-K).

10.1+		Independent Director Agreement by and between Jack N. Aydin and Rex Energy Corporation dated June 1, 2015 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on May 26, 2015).

10.2+		Independent Director Agreement with John A. Lombardi dated April 1, 2007 (incorporated by reference to Exhibit 10.6 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).