rexx-10k_20161231.htm

Large Accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting 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, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one):

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2016 was $46,993,210. This amount is based on the closing price of the registrant’s common stock on The NASDAQ Global Select Market, the exchange on which the common stock traded as of June 30, 2016, 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 2017, 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.

We are an independent condensate, NGL and natural gas 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 currently trades on The NASDAQ Capital Market under the symbol “REXX”. 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 and have not been retroactively restated to remove the associated estimated proved reserves from prior year balances.

At December 31, 2016, our estimated proved reserves had the following characteristics:

At December 31, 2016, we owned an interest in approximately 559.0 condensate, NGL and natural gas wells. For the quarter ended December 31, 2016, we produced an average of 194.9 net MMcfe per day, composed of approximately 62.0% natural gas, 3.4% condensate and 34.6% NGLs.

In the Appalachian Basin during 2016, we averaged net production of approximately 195.3 MMcfe per day of natural gas, NGLs and condensate. As of December 31, 2016, including both developed and undeveloped acreage, we controlled approximately 214,600 gross (160,700 net) acres in Pennsylvania that we believe are prospective for Marcellus Shale exploration and 174,400 gross (147,700 net) acres in Pennsylvania that we believe are prospective for Burkett Shale exploration. In addition, as of December 31, 2016, we controlled approximately 219,000 gross (180,100 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, 2016 was $139.0 million, which was primarily derived from the sale of condensate, NGLs and natural gas.

For the year ended December 31, 2016, we drilled 20.0 gross (8.4 net) wells. We placed into sales 34.0 gross (16.2 net) wells and ended the year with nine gross (3.8 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 condensate and NGL production. As of December 31, 2016, our holdings believed to be prospective for liquids-rich production accounted for approximately 85.5% 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 61.0% between the fourth quarter of 2010 and the fourth quarter of 2016. 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 over 93.6% 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 $0.17 per Mcfe in 2014 to $0.15 per Mcfe in 2015 and $.012 per Mcfe in 2016. Our general and administrative expense per Mcfe has decreased from $0.62 per Mcfe in 2014 to $0.40 per Mcfe in 2015 and $0.28 per Mcfe in 2016.

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 condensate, NGL and natural gas 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 oil, natural gas and NGL derivative contracts. This strategy is designed to provide us with stability in our cash flows to support our on-going capital requirements. As of December 31, 2016, we had over 65.0% of our 2016 condensate production volumes hedged through 2017, over 75.0% of our 2016 natural gas production volumes hedged through 2017 and over 50.0% of our 2016 NGL production volumes hedged through 2017. Including the effects of derivatives added since December 31, 2016, we have over 80.0% of our 2016 natural gas production hedged through 2016 and over 60.0% of our 2016 NGL production hedged through 2016. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future development or the natural decline of our condensate, NGL and gas production.

We are currently in the process of developing our 2017 capital expenditure budget, which we expect to be between $70.0 and $80.0 million. We anticipate that a significant portion of this budget will be allocated toward further development in the Appalachian Basin. In the event our cash flows are materially less than anticipated and 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 2016 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, 2016, we had 104 full-time employees, 12 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, 2016. 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, 2016. 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 260,000 gross MMBTU per day in 2017; 263,000 gross MMBTU per day in 2018; 233,000 gross MMBTU per day in 2019; 198,000 gross MMBTU per day in 2020; and 191,000 gross MMBTU per day in 2021.

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 oil and natural gas 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. Oil and natural gas 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 condensate and natural gas. 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 oil and gas 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 operating 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, air emissions from flaring, compression and access roads, the impoundment of water, the manner and extent of earth disturbances, air emissions, sour gas management, 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 and 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, 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, in the past tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities that must be addressed before those 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 its jurisdiction.

The increasing regulatory burden on the oil and natural gas 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 for 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 oil and gas 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 crude oil, condensate and natural gas liquids 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 oil and NGLs.

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 sale or gathering, but does apply to activities or 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 and the discharge of materials into the environment. These laws and regulations:

The permits required for our operations may be subject to revocation, modification and renewal by 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, as well as the oil and natural gas 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, or EPA, the individual states administer some or all of the provisions of RCRA, 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 crude oil or natural gas 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. Any such change 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 and on persons who disposed of or arranged for the disposal of “hazardous substances” found at these sites. 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 have been used for oil and natural gas exploration and production, and produced water disposal operations for many years. 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 to perform remedial activities to prevent future 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. The Environmental Protection Agency (“EPA”) and delegated states have adopted regulations concerning the discharge of storm water runoff. These regulations require covered facilities to obtain individual permits or to seek coverage under a general permit. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the unpermitted discharge of 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 oil and natural gas exploration and production operations generate produced water as a waste material, which is subject to the disposal requirements of the Clean Water Act, the Safe Drinking Water Act (“SDWA”), or an equivalent state regulatory program.

This produced water is disposed of by re-injection into the subsurface through disposal wells, treatment and discharge to the surface or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies, and in compliance with applicable environmental regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the Clean Water Act or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the Underground Injection Control program, (“UIC”), which is a program promulgated under the SDWA. The EPA directly administers the UIC in some states and in others it is delegated to the states. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws and regulations.

The federal Clean Air Act, and comparable state laws, regulates emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. In April 2012, the EPA issued a final rule under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPs, programs. The rule establishes the NSPS for certain wells, storage vessels, pneumatic controllers, compressors, and natural gas processing plants and revises the NESHAP for glycol dehydration units. This rule also requires all new hydraulically fractured wells and wells that are refractured to reduce emissions of Volatile Organic Compounds through “green completions.” More recently, in May 2016, the EPA finalized a suite of regulations that set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities. 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.

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 certain gases, commonly referred to as “greenhouse gases” and 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 legislation 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 oil, natural gas and NGLs that we produce.

In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gas emissions may be regulated as an “air pollutant” under the federal Clean Air Act. In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes, the EPA adopted regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA has issued regulations that, among other things, require a reduction in emissions of greenhouse gases from motor vehicles and that impose greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. In November 2010 the EPA expanded its greenhouse reporting rule to include onshore petroleum and natural gas production, processing, transmission, storage, and distribution facilities. Under these rules, reporting of greenhouse gas emissions from such facilities is required on an annual basis, and the first reports became due in September 2012 for emissions occurring in 2011.

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) enacted stronger environmental standards, (ii) established impact fees, which are set based on a multi-year fee schedule and the average sales price of natural gas, (iii) increased the notice distance for unconventional well permit applications, (iv) extended the setback distance for unconventional wells and (v) increased the distance and duration of presumed 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 invalidated the portions of Act 13 providing for statewide zoning and state waivers of the setback requirements in Pennsylvania's Oil and Gas Act. In 2014, a Pennsylvania Commonwealth Court invalidated Act 13’s provisions allowing the commonwealth to review local drilling rules. These court decisions have the effect of giving local communities in Pennsylvania more authority to regulate oil and gas operations, which could make it more difficult to develop Marcellus Shale acreage in some municipalities. We cannot predict

whether the remaining portions of Act 13 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, Pennsylvania has finalized new rules for surface operations at oil and gas sites that, among other things, would increase public participation in the permitting process, increase mitigation obligations and require surveys for abandoned wells. In October 2016, the Pennsylvania Department of Environmental Protection issued final rules amending Pennsylvania Code Chapter 78a, revising requirements for surface activities related to unconventional oil and gas operations. The final rules increase requirements for permitting, waste handling, water management and restoration, surface reclamation and requirements related to abandoned and orphaned wells. In November 2016, a Pennsylvania state court issued an opinion requiring the enforcement of certain portions of the new rules while the court considers legal challenges to the rules brought by an industry group. These regulations may increase operating costs or cause unanticipated delays.

Although it is not possible at this time to predict whether proposed federal or state legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions 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 associated with legislation or regulations regarding greenhouse gas emissions or other environmental matters could have a material adverse effect on our business, financial condition and results of operation. In addition, these developments 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

Oil, NGL and natural gas 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. Oil and natural gas 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 oil and natural gas 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, oil and natural gas prices continued to be volatile in 2016. For example, the WTI oil spot price in 2016 ranged from a high of $54.01 to a low of $26.19 per Bbl and Henry Hub natural gas spot prices in 2016 ranged from a high of $3.80 to a low of $1.49 per MMBtu.

Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. For example, due to the significant decrease in commodity prices over the latter half of 2014 and the duration of 2015 and 2016, our capital expenditures budget for 2017 is considerably smaller than our actual capital expenditures for 2016. The amount we will be able to borrow under our revolving credit facility is subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices.

Lower oil, NGL and natural gas 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. The higher operating costs associated with many of our oil fields will make our profitability more sensitive to oil price declines. A sustained decline in oil, NGL or natural gas 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.

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

As of December 31, 2016, we had approximately $723.0 million of debt outstanding, including $601.2 million related to our senior notes, $117.7 million outstanding on our revolving credit facility and $4.1 million related to other obligations. We and our subsidiaries may be able to incur substantial additional indebtedness in the future, including under our revolving credit facility. At December 31, 2016, our $400.0 million revolving credit facility had a borrowing base of $190.0 million for secured borrowings, subject to periodic borrowing base redeterminations. Effective as of January 11, 2017, we entered into an amendment to our revolving credit facility pursuant to which the borrowing base was maintained at $190.0 million for secured borrowings following our sale of assets in our Warrior South Area (located in Guernsey, Noble and Belmont Counties, OH). The next borrowing base redetermination is scheduled to occur in April 2017. No assurances can be given that our borrowing base will not be lowered upon our next periodic redetermination or any redetermination thereafter. For additional information, see Note 26, Subsequent Events, to our Consolidated Financial Statements.

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 revolving 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 will increase when the interest rate applicable to our outstanding senior secured second lien notes increases 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. 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. While we have been able to obtain waivers from our lenders in connection with past failures to comply with the current ratio financial covenant in our revolving credit facility, there can be no assurance that we will be able to do so in connection with any future failures to comply with financial covenants in our revolving credit facility. 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.

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 eight years prior to December 31, 2016, 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, 2016, the Henry Hub spot market price of natural gas was $3.71 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 $53.75 per barrel on December 31, 2016, which 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 2016, we recorded impairment expense of $74.6 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 require us to repay debt earlier than we would otherwise be required. 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”).

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 oil and natural gas 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 credit facility or the issuance of additional debt securities will require that a greater portion of our cash flow from operations 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. Our borrowing base is subject to scheduled redeterminations semi-annually, and may also be redetermined more often at the discretion of our lenders. Lower oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination. A reduction in our borrowing base could require us immediately to repay any outstanding indebtedness under our revolving credit facility in excess of the borrowing base. In addition, our credit facility imposes certain limitations on our ability to incur additional indebtedness other than indebtedness under our credit facility. If we desire to issue additional debt securities other than as expressly permitted under our credit facility, we will be required to seek the

consent of the lenders in accordance with the requirements of the credit facility, which consent may be withheld by the lenders at their discretion. If we incur certain additional indebtedness, our borrowing base under our credit facility may be reduced. Also, our revolving credit 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 oil, NGL and natural gas 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 revolving 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.

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 revolving credit facility, the indentures governing our senior notes or any future indebtedness could result in an event of default under our revolving 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 revolving credit facility occurs and remains uncured, the lenders thereunder:

A payment default or an acceleration under our revolving 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 revolving 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 revolving credit facility, the lenders could seek to foreclose on our assets.

The value of our proved reserves as of December 31, 2016, 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, 2016, Standardized Measure and related PV-10 and were calculated under SEC rules using twelve-month trailing average benchmark prices of $39.25 per barrel of oil (WTI) and $2.481 per MMBtu (Henry Hub spot). The spot prices for oil and natural gas on February 27, 2017, were $54.04 per barrel of oil and $2.481 per MMBtu, respectively, higher than the benchmark prices 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 2017, would likely result in an increase in proved reserve volumes. If spot prices on February 27, 2017 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 2017 production, our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of oil and natural gas.

We have over 65.0% of our 2016 condensate production hedged through 2017, over 75.0% of our 2016 natural gas production hedged through 2017 and over 50.0% of our 2016 NGL production hedged through 2017. Including the effects of derivatives added since December 31, 2016, of our 2016 natural gas production over 80.0% is hedged through 2017 and over 60.0% of our 2016 NGL production hedged through 2017. In addition, we have basis swaps in place for 14.7 Bcf at an average differential to Henry Hub New York Mercantile Exchange (“NYMEX”) of $0.86 per Mcf through 2017. These hedges may be inadequate to protect us from continuing and prolonged decline in the price of oil and natural gas. To the extent that the price of oil and natural gas remain at current levels or declines further, 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 oil, NGLs and natural gas 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 oil, NGL and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil, NGL or natural gas 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 oil, NGL and gas financial derivative activities, and our oil, NGL and gas 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 oil and natural gas 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 received net payments of $32.6 million related to our commodity derivative instruments for the year ended December 31, 2016.

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 oil and gas 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 revolving 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 oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas 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, 2016 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 2016 prices would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2017 by approximately $4.3 million.

Prospects that we decide to drill may not yield oil, NGLs or natural gas 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 oil, NGLs or natural gas 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 oil, NGLs or natural gas will be present or, if present, whether oil, NGLs or natural gas 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 oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

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.

During 2016, we recorded impairment expense of approximately $74.6 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 require us to repay debt earlier than we would otherwise be required. 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 oil and natural gas reserves are inherently imprecise. The process of estimating oil and natural gas 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 oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas 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 oil, NGL and natural gas 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 oil, NGL and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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, oil and natural gas 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 oil or natural gas 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 oil, NGL and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil, NGLs and natural gas reservoirs generally are characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future oil, NGL and natural gas 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 between four and six million gallons 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 regulates the underground injection of substances through the UIC. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel under the SDWA’s UIC program. In February 2014, the EPA released an “interpretative memorandum” providing technical recommendations for implementing UIC requirements for hydraulic fracturing activities using diesel fuels. In this guidance document, the EPA expansively defined the term “diesel” to include hydrocarbons such as kerosene that have not typically been considered to be diesel. In addition, legislation has 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. Also, many state governments, including Pennsylvania and Ohio, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, well construction, and operational requirements on hydraulic fracturing operations or otherwise seek to temporarily or permanently ban fracturing activities. In addition to state laws, local land use restrictions, such as city ordinances, zoning laws, and traffic regulations may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. 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 are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In June 2015, the EPA published draft results of the study, concluding that hydraulic fracturing activities may adversely impact drinking water resources but finding no widespread impacts. Many observers, including the EPA’s Inspector General have criticized the results of the study. In the interim, however, the EPA has utilized existing statutory authority under the SDWA, the Clean Water Act CERCLA and the Clean Air Act to investigate, order actions, and potentially pursue penalties against some oil and natural gas producers where EPA believes their activities may have impacted the air or groundwater. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities. In April 2012, President Obama issued an executive order creating a task force to coordinate federal oversight over domestic natural gas production and hydraulic fracturing. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

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 oil, NGLs, and natural gas (including ethane) and/or receive market prices for our oil, NGLs and natural gas may be adversely affected by pipeline and gathering system capacity constraints.

Market conditions or the unavailability of satisfactory oil, NGL and natural gas transportation arrangements may hinder our access to oil, NGL and natural gas markets or delay our production. The availability of a ready market for our oil, NGL and natural gas production depends on a number of factors, including the demand for and supply of oil, NGLs and natural gas 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 oil, NGLs or natural gas 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. Because of the current economic climate, 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 have to shut in our wells awaiting 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, 2016, 100.0% 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 oil, NGL and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil, NGLs and natural gas 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 oil and natural gas 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 oil, NGLs and natural gas. These agreements commit us to future obligations to be paid regardless of volumes produced. As of December 31, 2016, we were a party to several transportation, marketing and processing agreements which commit us to approximately $227.5 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 oil, NGL and natural gas sales.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil, NGL and natural gas 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 oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil, NGLs and natural gas, 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 of oil, NGLs and natural gas 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 oil, NGL and natural gas 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, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, 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 oil, NGLs and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of greenhouse gases (“GHGs”) present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, in 2010, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration, or PSD, construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In June 2014, the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection Agency, struck down the EPA’s “tailoring” rule but affirmed the agency’s authority to regulate

GHG emissions from facilities already subject to permitting requirements on the basis of their emission of conventional pollutants. In addition, in November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. In July 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting. Under this rule, initial reports became due in September 2012. We believe that we are in substantial compliance with these reporting obligations. The EPA has indicated that it will use GHG reporting data in considering whether to initiate further rulemaking to establish GHG emissions limits. Further, in April 2012 the EPA issued final New Source Performance Standards and National Emission Standards for Air Pollutants. This rule requires all new hydraulically-fractured wells to reduce emissions of Volatile Organic Compounds through “green completions.” The rule is designed to reduce GHG emissions during well completions. More recently, in August 2015, the EPA proposed a suite of regulations that would set emission standards for methane, a GHG, for new and modified oil and gas production and natural gas processing and transmission facilities. These regulations were finalized in 2016. Also, Congress has from time to time considered legislation 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 regulations that requires reporting of 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 oil, natural gas and NGLs we produce. Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate change that could have significant physical effect, 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 oil and gas hedging transactions involving swaps. In particular, the Act includes a requirement that certain hedging transactions involving swaps be cleared and exchange-traded and a requirement to post cash collateral for non-cleared swap transactions, although, at this time, it is unclear which transactions will ultimately be required to be cleared and exchange-traded or which counterparties will be required to post cash collateral with respect to non-cleared swap transactions. The Act provides for a potential exception from the clearing and exchange-trading requirement for hedging transactions by commercial end-users, a category of non-financial entities in which we may be included. While the Commodity Futures Trading Commission, or CFTC, and other federal agencies have adopted, and continue to adopt, numerous regulations pursuant to the Act, many of the key concepts and defined terms under the Act have not yet been delineated by rules and regulations to be adopted by the CFTC and other applicable regulatory agencies. 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 is to occur within 120 days, but there is little guidance on 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 cash collateral with respect to such transaction will depend on the final rules and definitions adopted by the CFTC. If we are subject to such requirements, significant liquidity issues could result by reducing our ability to use cash posted as collateral for investment or other corporate purposes. A requirement to post cash collateral could also limit our ability to execute strategic hedges, which would result in increased commodity price uncertainty and volatility in our future cash flows. The Act and related regulations currently also would require us to comply with certain futures and swaps position limits and new recordkeeping and 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.

While Pennsylvania has historically not imposed a severance tax (relating to the extraction of natural gas), with a focus on its budget deficit and the increasing exploration of the Marcellus Shale, various legislation has been proposed since 2008. In February 2012, Pennsylvania implemented an impact fee. This law imposes an impact fee on all unconventional wells drilled in the Commonwealth of Pennsylvania in counties that elected to impose the fee. The fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. The impact fee is initially imposed for the year after an unconventional well is spudded and is imposed

annually for 15 years for a horizontal well and 10 years for a vertical well. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed.

In 2015, 2016 and 2017, the Pennsylvania governor proposed budgets that included proposals for a new 6.5% severance tax in addition to the impact tax. Although no such proposals have 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 crude oil, NGL and natural gas 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 78.8% of our commodity sales from continuing operations for the year ended December 31, 2016 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 45.6%. with the largest single customer accounting for 45.6%. If we were unable to continue to sell our oil, NGLs, or natural gas 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.

The administration of President Obama made budget proposals which, if enacted into law by Congress, would potentially have increased and accelerated the payment of U.S. federal income taxes by independent producers of oil and natural gas. Proposals have included, but have not been limited to, repealing the enhanced oil recovery credit, repealing the credit for oil and natural gas produced from marginal wells, repealing the expensing of intangible drilling costs (“IDCs”), repealing the deduction for the cost of qualified tertiary expenses, repealing the exception to the passive loss limitation for working interests in oil and natural gas properties, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and natural gas companies, and increasing the

amortization period of geological and geophysical expenses. Legislation which would have implemented the proposed changes was introduced but not enacted. It is unclear whether legislation supporting any of the above described proposals, or designed to accomplish similar objectives, will be introduced or, if introduced, would be enacted into law, or, if enacted, how soon resulting changes would become effective. However, the passage of any legislation designed to implement changes in the U.S. federal income tax laws similar to the changes included in the budget proposals offered by the Obama administration could eliminate certain tax deductions currently available with respect to oil and natural gas exploration and development, and any such changes (i) could make it more costly for us to explore for and develop our oil and natural gas resources and (ii) could negatively affect our financial condition and results of operations.

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

The oil and gas 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 oil and natural gas 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 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 2016, the sales price of our stock ranged from a low of

$0.23 per share (on November 15, 2016) to a high of $2.43 per share (on March 7, 2016). Factors such as announcements concerning 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 not declaring and paying regular quarterly dividends on our Series A Preferred Stock, 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 200,000,000 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 March 2, 2017, there were 98,013,126 shares of our common stock issued and outstanding and 3,987 shares of our 6.0% Convertible Preferred Stock, Series A, issued and outstanding.

In the future, we may issue additional shares of our common stock or securities convertible into or exchangeable for our common stock in connection with public offerings, private placements, the hiring of personnel, acquisitions, for capital raising purposes, to pay accrued dividends on our Series A Preferred Stock in accordance with the terms of our Series A Preferred Stock or for other business purposes. 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 our Chairman and other executive officers, who collectively beneficially own approximately 7.5% of the outstanding shares of our common stock as of March 2, 2017.

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 2, 2017, our board of directors, including Lance T. Shaner, our Chairman, and our other executive officers collectively own approximately 7.5% 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 revolving 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.

If we cannot meet The NASDAQ Capital Market continued listing standards, our common stock may be subject to delisting.

Our common stock is currently listed on The NASDAQ Capital Market, where it has been listed since December 2016 after previously being listed on The NASDAQ Global Select Market. NASDAQ’s continued listing standards require, among other things, that the average closing price of our common stock not fall below $1.00 per share over a consecutive thirty trading day period. On June 14, 2016, we received a letter from the Listing Qualifications Department of NASDAQ stating that we were not in compliance with NASDAQ Listing Rule 5450(a)(1) because our common stock failed to maintain a minimum closing bid price of $1.00 for 30 consecutive trading days. We then had a period of 180 calendar days, or until December 12, 2016, to achieve compliance with the Rule 5450(a)(1). On December 13, 2016, we announced that NASDAQ approved our continued listing on the Nasdaq Capital Market and granted us an additional 180-day period (until June 12, 2017) in which to regain full compliance with the minimum bid requirement. In accordance with NASDAQ Listing Rule 5810(c)(3)(A) we need to have the closing price of our common stock at or above $1.00 per share for a minimum of ten consecutive trading days on or prior to June 12, 2017, or NASDAQ may, at its discretion, commence suspension and delisting procedures. Our closing share price on March 2, 2017, was $0.62.

Such a delisting 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) limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby 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.

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, 2016:

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, 2016, we owned an interest in approximately 559.0 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 3.6 Bcfe. At December 31, 2016, we had approximately 259,600 gross (193,500 net) acres under lease, of which 83,700 gross (75,600 net) acres were undeveloped. Of our total acreage holdings, we believe that approximately 174,400 gross (147,700 net) acres are prospective for three producing horizons, including the Marcellus, Utica and Burkett. Reserves at December 31, 2016 decreased 32.7 Bcfe, or 4.8%, from 2015 due primarily to the sale of our Illinois Basin assets and the continued depressed commodity price environment.

Capital expenditures in 2016 for drilling and facility development totaled $27.9 million, net of credits from our joint venture partners, which funded the drilling of 20.0 gross (8.4 net) wells. During the year, we placed into service 34.0 gross (16.2 net) wells and had an inventory of 9.0 gross (3.8 net) wells awaiting completion.

As of December 31, 2016, we had interests in approximately 214,600 gross (160,700 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 174,400 gross (147,700 net) acres that we believe to be prospective for liquid-rich Marcellus production. During 2016, we drilled, or participated in the drilling of 10.0 gross (4.9 net) Marcellus Shale wells and placed into service 20.0 gross (10.8 net) Marcellus Shale wells. Our estimated proved reserves related to the Marcellus Shale as of December 31, 2016, totaled approximately 496.8 Bcfe, including one proved non-producing locations with estimated proved reserves of 3.6 Bcfe.

We are a party to four 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 (collectively “Sumitomo”). 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 in our Westmoreland, Centre and Clearfield Counties, Pennsylvania project areas is with WPX Energy Production, LLC (“WPX”), with WPX serving as the operator. Our working interest in this area of mutual interest is approximately 40.0%. The third 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 fourth joint venture covers 30 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, 2016, we had under lease approximately 219,000 gross (180,100 net) acres that we believe are prospective for the Utica Shale in Ohio and Pennsylvania. In Ohio, our holdings comprise approximately 20,400 gross (17,000 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, 2016, we estimate Utica Shale acreage holdings in Pennsylvania of approximately 198,300 gross (162,900 net) acres. During 2016, we drilled seven gross (2.5 net) Utica Shale wells and placed into service 13.0 gross (5.1 net) Utica Shale wells. Our estimated proved reserves related to the Utica Shale as of December 31, 2016, totaled approximately 96.1 Bcfe.

We are a party to two joint ventures in Ohio that represent our primary source for Utica Shale production. The first joint venture, for which we serve as the operator, is with MFC Drilling, Inc. and ABARTA Oil & Gas Co., Inc. and covers an area of mutual interest in Belmont, Guernsey and Noble Counties, Ohio. Our average working interest in these areas is approximately 64%. The second joint venture covers 12 specifically identified units 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 60%.

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 expected $29.0 million in net proceeds, subject to customary post-closing adjustments. Our estimated proved reserves related to these properties as of December 31, 2016, totaled approximately 21.6 Bcfe.

As of December 31, 2016, we had under lease approximately 174,400 gross (147,700 Net) acres prospective for the liquids-rich Burkett Shale in Pennsylvania. During 2016, we drilled three gross (1.1 net) Burkett Shale wells and placed into service one gross (0.4 net) wells. Our estimated proved reserves related to the Burkett Shale as of December 31, 2016 totaled approximately 41.8 Bcfe.

For estimated proved reserves as of December 31, 2016, 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, 2016 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:

We did not recognize estimated proved reserves associated with PUD locations as of December 31, 2016. Changes in PUDs that occurred during the year were due to a conversion of 33.4 Bcfe attributable to PUDs into proved developed reserves. Costs incurred relating to the development of seven gross (5.2 net) PUD locations converted to proved developed were approximately $7.2 million in 2016.

The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2016:

In our 2015 reserve report, we had seven gross proved undeveloped locations all of which were scheduled for development in 2016. During 2016, all seven of the PUD locations were completed and converted to proved developed producing reserves. This equated to a conversion of 100.0% of our proved undeveloped locations to proved developed producing reserves. The depressed commodity price environment has significantly impacted our development plans, leading to the removal of proved undeveloped locations from the 2016 reserves report. 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, 2016 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.

The reduction in expected capital expenditures on proved undeveloped locations is largely due to the current commodity price environment and the related impact on the economic viability of our proved undeveloped locations from 2015 and prior years, as described above, in addition to our current drilling program that is focused on holding acreage by production.

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 10 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, 2016:

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 38.3% of our total net acreage. As of December 31, 2016, 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.

	2016						2015						2014
	Gross			Net			Gross			Net			Gross			Net
Development:
Appalachian Basin		9.0			3.9			22.0			11.3			24.0			16.2
Non-Productive		—			—			—			—			-			-
Total Developmental Wells		9.0			3.9			22.0			11.3			24.0			16.2
Exploratory:
Appalachian Basin		11.0			4.5			12.0			11.7			27.0			21.4
Non-Productive		—			—			2.0			1.0			3.0			2.0
Total Exploratory Wells		11.0			4.5			14.0			12.7			30.0			23.4
Total Wells		20.0			8.4			36.0			24.0			54.0			39.6
Success Ratio¹		100.0	%		100.0	%		94.4	%		95.8	%		94.4	%		94.9	%

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 is traded on The NASDAQ Capital Market under the symbol “REXX”, where it has traded since December 2016. Our common stock previously traded on The NASDAQ Global Select Market. As of March 2, 2017, there were approximately 161 holders of record of our common stock.

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 revolving 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, 2012 to December 31, 2016, 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, 2016, 2015, 2014, 2013 and 2012. 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, 2016 and 2015 and for each of the years ended December 31, 2016, 2015 and 2014, 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)
	2016			2015			2014			2013			2012
Statement of Operations Data:
Operating Revenue:
Natural Gas, NGL and Condensate Sales	$	139,000		$	138,707		$	225,511		$	139,542		$	69,260
Other Revenue		17			42			118			200			218
Total Operating Revenue		139,017			138,749			225,629			139,742			69,478
Operating Expenses:
Production and Lease Operating Expense		104,699			93,892			69,547			36,649			24,875
General and Administrative Expense		20,621			26,694			31,917			27,237			19,733
(Gain) Loss on Disposal of Assets		(4,121	)		(540	)		218			104			(10	)
Impairment Expense		74,619			283,244			20,225			2,798			19,366
Exploration Expense		2,178			2,617			6,813			5,915			4,379
Depreciation, Depletion, Amortization & Accretion		62,874			85,844			65,817			38,170			28,776
Other Operating Expense		10,754			5,603			312			65			430
Total Operating Expenses		271,624			497,354			194,849			110,938			97,549
Income (Loss) from Operations		(132,607	)		(358,605	)		30,780			28,804			(28,071	)
Other Income (Expense):
Interest Expense		(43,519	)		(47,783	)		(36,945	)		(22,626	)		(6,398	)
Gain (Loss) on Derivatives, Net		(32,515	)		60,176			38,876			(2,908	)		10,687
Other Income (Expense)		(2,124	)		(129	)		73			6,694			98,607
Debt Exchange Expense		(9,063	)		—			—			—			—
Gain on Extinguishment of Debt		24,627			—			—			—			—
Loss on Equity Method Investments		—			(411	)		(813	)		(763	)		(3,921	)
Total Other Income (Expense)		(62,594	)		11,853			1,191			(19,603	)		98,975
Income (Loss) from Continuing Operations Before Income Tax		(195,201	)		(346,752	)		31,971			9,201			70,904
Income Tax Expense		(2,436	)		(6,030	)		(15,460	)		(2,012	)		(28,033	)
Income (Loss) from Continuing Operations		(197,637	)		(352,782	)		16,511			7,189			42,871
Income (Loss) from Discontinued Operations, Net of Income Taxes		20,922			(8,251	)		(59,161	)		(7,762	)		3,427
Net Income (Loss)		(176,715	)		(361,033	)		(42,650	)		(573	)		46,298
Net Income Attributable to Noncontrolling Interests		—			2,245			4,039			1,557			819
Net Income (Loss) Attributable to Rex Energy		(176,715	)		(363,278	)		(46,689	)		(2,130	)		45,479
Preferred Stock Dividends		(5,091	)		(9,660	)		(2,335	)		—			—
Effect of Preferred Stock Conversions		72,984			—			—			—			—
Net Income (Loss) Attributable to Common Shareholders	$	(108,822	)	$	(372,938	)	$	(49,024	)	$	(2,130	)	$	45,479
Earnings per Common Share
Basic - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(1.63	)	$	(6.66	)	$	0.27		$	0.14		$	0.83
Basic - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.26			(0.19	)		(1.19	)		(0.18	)		0.05
Basic - Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(1.37	)	$	(6.85	)	$	(0.92	)	$	(0.04	)	$	0.88
Basic - Weighted Average Shares of Common Stock Outstanding		79,256			54,392			53,150			52,572			51,543
Diluted - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(1.63	)	$	(6.66	)	$	0.27		$	0.14		$	0.83
Diluted - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.26			(0.19	)		(1.19	)		(0.18	)		0.05
Diluted - Net Income (Loss) Attributable to Rex Energy Common Shareholders	$	(1.37	)	$	(6.85	)	$	(0.92	)	$	(0.04	)	$	0.88
Diluted - Weighted Average Shares of Common Stock Outstanding		79,256			54,392			53,150			52,572			52,025

	Year Ended December 31,
	($ in Thousands)
	2016			2015			2014			2013			2012
Cash Flow Data:
Cash provided by operating activities	$	(4,404	)	$	30,885		$	162,706		$	108,316		$	45,705
Cash used in investing activities		4,651			(155,446	)		(560,036	)		(313,518	)		(100,742	)
Cash provided by financing activities		2,359			107,556			413,526			163,127			87,216
Balance Sheet Data:
Cash and Cash Equivalents		3,697			1,091			17,978			1,307			43,234
Property and Equipment (net of Accumulated Depreciation)		855,444			951,043			1,108,217			689,659			478,301
Total Assets		893,923			1,071,931			1,378,772			978,579			765,307
Current Liabilities, including current portion of long-term debt		103,708			116,601			170,180			121,026			78,016
Long-Term Liabilities		779,989			795,099			697,867			440,628			274,997
Total Liabilities		883,697			911,700			847,399			561,654			353,013
Noncontrolling Interests		—			—			4,241			2,042			775
Stockholders' Equity		10,226			160,231			531,373			416,925			412,294
Other Financial Data:
EBITDAX from Continuing Operations¹	$	45,272		$	78,787		$	136,422		$	87,784		$	46,148

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.

	2016			2015			2014
Production
Condensate (Bbls)		360,384			402,867			334,944
Natural Gas (Mcf)		44,684,571			44,606,753			37,011,177
C3+ NGLs (Bbls)		1,996,075			2,026,321			1,531,131
Ethane (Bbls)		2,111,321			1,319,582			551,315
Mcf Equivalent (Mcfe)		71,491,251			67,099,373			51,515,517
Condensate, NGL and Natural Gas Sales (thousands)
Condensate Sales	$	13,364		$	14,068		$	25,068
Natural Gas Sales	$	73,275		$	83,140		$	126,500
C3+ NGL Sales	$	35,877		$	32,789		$	69,626
Ethane Sales	$	16,484		$	8,710		$	4,317
Total	$	139,000		$	138,707		$	225,511
Average Sales Price (a)
Condensate ($ per Bbl)		37.08		$	34.92		$	74.84
Natural Gas ($ per Mcf)	$	1.64		$	1.86		$	3.42
C3+ NGLs ($ per Bbl)	$	17.97		$	16.18		$	45.47
Ethane ($ per Bbl)	$	7.81		$	6.60		$	7.83
Mcf Equivalent ($ per Mcfe)	$	1.94		$	2.07		$	4.38
Average Production Cost
Mcf Equivalent ($ per Mcfe)	$	1.46		$	1.40		$	1.35
Estimated Proved Reserves (b)
Bcf Equivalent (Bcfe)		647.8			680.4			1,336.8
% Condensate and NGL		43	%		40	%		37	%
% Proved Producing		100	%		80	%		40	%
Standardized Measure (millions)	$	165.6		$	255.6		$	1,025.4
PV-10 (millions)	$	175.5		$	300.7		$	1,205.2

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 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)
	2016			2015			2014			2013			2012
Net Income (Loss) from Continuing Operations	$	(197,637	)	$	(352,782	)	$	16,511		$	7,189		$	42,871
Add Back Non-Recurring Costs (Income)¹		(6,760	)		4,774			—			—			2,809
Add Back Depletion, Depreciation, Amortization and Accretion		62,874			85,844			65,817			38,170			28,776
Add Back Non-Cash Compensation Expense		3,078			5,791			5,223			4,988			2,962
Add Back Interest Expense		43,519			47,783			36,945			22,626			6,398
Add Back Impairment Expense		74,619			283,244			20,225			2,798			19,366
Add Back Exploration Expense		2,178			2,617			6,813			5,915			4,379
Add (Less) Back (Gain) Loss on Disposal of Asset²		(4,121	)		(537	)		218			(6,702	)		(99,417	)
Add (Less) Back (Gain) Loss on Financial Derivatives		32,515			(60,176	)		(38,876	)		2,908			(10,687	)
Add Back Cash Settlement of Derivatives		32,571			55,793			7,281			7,128			16,219
Add Back Non-Cash Portion of Equity Method Investments		—			406			805			752			4,471
Less Non-Cash Portion of Noncontrolling Interests		—			—			—			—			(32	)
Add Back Income Tax Expense		2,436			6,030			15,460			2,012			28,033
EBITDAX from Continuing Operations	$	45,272		$	78,787		$	136,422		$	87,784		$	46,148
Income (Loss) from Discontinued Operations	$	20,922		$	(8,251	)	$	(59,161	)	$	(7,762	)	$	3,427
Net Income Attributable to Noncontrolling Interests		—			(2,245	)		(4,039	)		(1,557	)		(819	)
Income (Loss) From Discontinued Operations Attributable to Rex Energy		20,922			(10,496	)		(63,200	)		(9,319	)		2,608
Add Back Depletion, Depreciation, Amortization and Accretion		5,101			18,978			32,353			25,774			16,661
Add Back (Less) Non-Cash Compensation Expense (Income)		(159	)		659			449			396			147
Add Back Interest Expense		4			510			661			156			45
Add Back Impairment Expense		3,543			62,531			112,460			29,274			20,989
Add Back Exploration Expense		143			394			2,633			5,590			1,270
Add (Less) Back (Gain) Loss on Disposal of Asset³		(30,530	)		(57,748	)		371			574			(2,058	)
Less Non-Cash Portion of Noncontrolling Interests		—			(208	)		(1,738	)		(631	)		(108	)
Add Back (Less) Income Tax Expense (Benefit)		—			(6,030	)		(41,607	)		(4,792	)		2,027
EBITDAX from Discontinued Operations	$	(976	)	$	8,590		$	42,382		$	47,022		$	41,581
EBITDAX	$	44,296		$	87,377		$	178,804		$	134,806		$	87,729

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, 2016, 2015 and 2014, 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, 2016, 2015 and 2014, 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 $36.68 per Bbl, $44.45 per Bbl and $88.02 per Bbl of oil and condensate, respectively, and $2.264 per MMBtu, $2.401 per MMBtu and $3.455 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, 2016, 2015 and 2014, were $39.25 per Bbl, $46.79 per Bbl and $91.48, respectively. Unadjusted prices for natural gas for the years ended December 31, 2016, 2015 and 2014,

were $2.481 per MMBtu, $2.587 per MMBtu and $$4.35 per MMBtu, respectively. NGLs were priced at $10.50 per Bbl, $12.48 per Bbl and $28.30 per Bbl for the years ended December 31, 2016, 2015 and 2014, 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 condensate, NGL and natural gas 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.

We believe the outlook for our business is favorable despite the continued uncertainty of oil and gas prices. 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 Oil, NGL and Natural Gas 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 condensate, natural gas and NGLs. 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 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.

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 beyond 2016 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 20 of these additional wells. We expect total consideration for this transaction to be $175.0 million with approximately $126.1 million committed as of December 31, 2016. BSP has paid approximately $82.4 million for their interest in elected wells as of December 31, 2016. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of December 31, 2016, 30 of the 42 committed wells were in line and producing, eight wells were drilled and awaiting completion and four wells were in process of being drilled.

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 Senior Secured Second Lien Notes (the “New Notes”) and (ii) an aggregate of 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the Exchange, the future undiscounted cash flows of the New 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 New Notes and (ii) issued an aggregate of 8.4 million Shares. An additional $0.5 million aggregate principal amount of New Notes were issued to holders who were ineligible to accept the 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 New Notes bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, commencing with the payment due April 1, 2018, 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 $9.0 million in third party debt issuance costs in the year ended December 31, 2016. These costs were recorded as Debt Exchange Expense in 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, subject to certain parameters and provisions for adjustment customary for transactions of this type, 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 $38.0 million during the third and fourth quarters. An addendum executed in conjunction with the Agreement allows for Rex to receive from Campbell potential additional proceeds of up $9.0 million, in installments of $0.9 million per quarter, 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:

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 December 31, 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.

During the second, third and fourth quarters of 2016, we entered into privately negotiated debt-to-equity exchanges with certain holders of our Existing Notes as well as holders of our New Notes in exchange for unrestricted shares of our common stock. These exchanges resulted in the retirement of $28.7 million of our Existing Notes, and $2.2 million of our New Notes, in exchange for the issuance of a total of approximately 6.7 million shares of unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the company of approximately $24.6 million, presented as Gain on Extinguishment of Debt in our Consolidated Statement of Operations for the year ended December 31, 2016.

During the third quarter of 2016, we entered into a privately negotiated debt-to-equity exchange with a single holder of our New Notes in exchange for unrestricted shares of our common stock. This exchange resulted in the retirement of $43.5 million of our New Notes in exchange for the issuance of approximately 16.8 million shares of unrestricted common stock. The transaction was accounted for as troubled debt restructuring. The exchange resulted in a deferred gain of $32.5 million, which will be amortized over the life of the New Notes through a change to the effective interest rate.

During 2016, 12,113 shares of Series A Preferred Stock were converted into approximately 9.3 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 Stock. 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 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.

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.

In 2014, we grew our daily production by 76.4% year-over-year to 141.1 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 51.0 gross (37.6 net) operated wells within the Appalachian Basin, targeting primarily the Marcellus and Utica shales, including 38.0 gross (26.6 net) operated wells in Butler County, Pennsylvania and 12.0 gross (10.6 net) operated wells in Ohio. With a drilling success rate of 100.0% in 2014, we increased proved reserves by 57.3% from 849.9 Bcfe at December 31, 2013 to 1,336.8 Bcfe at December 31, 2014. As of December 31, 2014, we had approximately 407,200 gross (339,500 net) acres in the Appalachian Basin, of which 324,300 gross (295,200 net) acres are believed to be prospective for the liquids-rich portion of the Marcellus and Utica Shales.

In July 2014, we issued a $325.0 million aggregate principal amount of the 2022 Notes in a private offering at an issue price of 100.0%. The 2022 Notes are due to mature on August 1, 2022. The net proceeds of the 2022 Senior Notes, after discounts and expenses, were approximately $318.8 million. In August 2014, we completed a registered offering of 16,100 shares of the Series A Preferred Stock that are represented by 1,610,000 depositary shares. The net proceeds of the offering were approximately $155.0 million, after deducting underwriting discounts, commissions and other offering expenses.

In September 2014, we completed the acquisition of approximately 208,000 gross (207,000 net) acres believed to be prospective for the Marcellus, Burkett and Utica Shales from Shell, for approximately $120.6 million in cash, after customary closing adjustments. Included in the acquisition were several producing wells and properties in various stages of development. The assets acquired are located in Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in Pennsylvania and Columbiana and Mahoning counties in Ohio.

We generate our revenue primarily from the sale of condensate, NGLs and natural gas. 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, 2016, 2015 and 2014.

“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 decrease in our EBITDAX from 2015 to 2016 can be primarily attributable to the continued depressed commodity price environment and a decrease in the cash settlements of our derivatives contracts, which has been partially offset by increased production and lower general and administrative expenses (“G&A”). 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, condensate and NGLs 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 2016 was $1.46, as compared to $1.40 in 2015 and $1.35 in 2014. Our production costs are largely comprised of variable type costs such as transportation, marketing, processing and gathering. In 2016, transportation, capacity and processing fees accounted for approximately 87.6% of our total Production and Lease Operating Expense, as compared to 84.7% during 2015 and 79.6% during 2014. 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 condensate, NGLs and natural gas 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 2014 was approximately 972% based on total production for the year of 56.4 Bcfe and extensions, discoveries and other additions of 547.9 Bcfe. 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. For 2016, our proved reserve base decreased by approximately 4.8%. The decrease in our estimated proved reserves is primarily due to the sale of our Illinois Basin assets as well as a decrease in commodity prices during 2016.

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 2016, our general and administrative expenses per Mcfe produced decreased to $0.28 from $0.40 in 2015 and $0.62 in 2014. The decreases are predominately due to further cost control measures and headcount reductions implemented during 2016 in response to our decreased capital plan related to commodity price declines combined with our increase in production.

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, 2016, 2015 and 2014, we incurred approximately $3.0 million, $3.0 million and $4.1 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 0.2% in 2016 over 2015. This slight increase was primarily driven by an increase in production, which was partially offset by a decrease in the average sales price for natural gas. For 2016, total production increased 6.5% to 71,491 MMcfe from 67,099 MMcfe in 2015. Our average sales price for natural gas, before the effects of derivatives, decreased approximately 12.0%, from $1.86 per mcf to $1.64 per mcf.

Operating expenses decreased $226.0 million in 2016, or 45.5%, as compared to 2015. 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 $208.6 million of this decrease is due to 2015 impairment expense, which is primarily due to the write down of proved and unproved properties as a result of the sustained depressed commodity price environment. As the future outlook for commodity prices became more favorable throughout 2016, 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.

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			67,099,370		4,391,881			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 revolving credit facility. We discuss our Senior Notes and 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 New 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 senior notes, wherein approximately $30.9 million of outstanding senior 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.

Comparison of the Year Ended December 31, 2015 to the Year Ended December 31, 2014

Condensate, NGL and gas revenue for the years ended December 31, 2015 and 2014 is summarized in the following table:

	For the Year Ended December 31,
($ in Thousands, except total Mcfe production and price per Mcfe)	2015		2014		Change			%
Condensate, NGL and Gas Revenue:
Condensate sales revenue	$	14,068	$	25,068	$	(11,000	)		-43.9	%
Oil derivatives realized (a)	$	11,860	$	1,085	$	10,775			993.1	%
Total condensate revenue and derivatives realized	$	25,928	$	26,153	$	(225	)		-0.9	%
Gas sales revenue	$	83,140	$	126,500	$	(43,360	)		-34.3	%
Gas derivatives realized (a)	$	32,573	$	1,637	$	30,936			1889.8	%
Total gas revenue and derivatives realized	$	115,713	$	128,137	$	(12,424	)		-9.7	%
C3+ NGL sales revenue	$	32,789	$	69,626	$	(36,837	)		-52.9	%
C3+ NGL derivatives realized (a)	$	10,384	$	3,247	$	7,137			219.8	%
Total C3+ NGL revenue and derivatives realized	$	43,173	$	72,873	$	(29,700	)		-40.8	%
Ethane sales revenue	$	8,710	$	4,317	$	4,393			101.8	%
Ethane derivatives realized (a)	$	42	$	—	$	42			100.0	%
Total ethane revenue and derivatives realized	$	8,752	$	4,317	$	4,435			102.7	%
Consolidated sales	$	138,707	$	225,511	$	(86,804	)		-38.5	%
Consolidated derivatives realized (a)	$	54,859	$	5,969	$	48,890			819.1	%
Total condensate, NGL and gas revenue and derivatives realized	$	193,566	$	231,480	$	(37,914	)		-16.4	%
Total Mcfe Production		67,099,370		51,515,516		15,583,854			30.3	%
Average Realized Price per Mcfe, including the effects of derivatives	$	2.88	$	4.49	$	(1.61	)		-35.8	%

Average realized price received for condensate, NGLs and natural gas during 2015 was $2.88 per Mcfe, a decrease of 35.8%, or $1.61 per Mcfe, from the prior year. The average realized price for condensate, including the effects of derivatives, in 2015 decreased 17.6% or $13.72 per barrel, whereas the average realized price for natural gas, including the effects of derivatives, decreased 25.1%, or $0.87 per Mcf, from 2014. The average realized price for NGLs, including the effects of derivatives, in 2015 decreased 58.1%, or $21.55 per barrel, from 2014. Our derivative activities effectively increased net realized prices by $0.82 per Mcfe in 2015 and $0.12 per Mcfe in 2014.

Production volume for 2015 increased 30.3%, or 15.6 Bcfe, from 2014 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities in the Appalachian Basin. We placed into service 33.0 gross (17.6 net) wells within the Appalachian Basin, primarily targeting the Marcellus and Utica Shales, during 2015.

Overall, our production for 2015 averaged approximately 183.8 Mmcfe per day, of which 3.6% was attributable to condensate, 29.9% was attributable to NGLs and 66.5% was attributable to natural gas.

Statements of Operations for the years ended December 31, 2015 and 2014 are as follows:

	For the Year Ended December 31,
($ in Thousands)	2015			2014			Change			%
Statement of Operations Data:
Operating Revenue:
Natural Gas, NGL and Condensate Sales	$	138,707		$	225,510		$	(86,803	)		-38.5	%
Other Revenue		42			118			(76	)		-64.4	%
Total Operating Revenue		138,749			225,628			(86,879	)		-38.5	%
Operating Expenses:
Production and Lease Operating Expense		93,892			69,547			24,345			35.0	%
General and Administrative Expense		26,694			31,917			(5,223	)		-16.4	%
(Gain) Loss on Disposal of Assets		(540	)		218			(758	)		-347.7	%
Impairment Expense		283,244			20,225			263,019			1300.5	%
Exploration Expense		2,617			6,813			(4,196	)		-61.6	%
Depreciation, Depletion, Amortization & Accretion		85,844			65,817			20,027			30.4	%
Other Operating Expense		5,603			312			5,291			1695.8	%
Total Operating Expenses		497,354			194,849			302,505			155.3	%
Income (Loss) from Operations		(358,605	)		30,779			(389,384	)		-1265.1	%
Other Income (Expense):
Interest Expense		(47,783	)		(36,945	)		(10,838	)		29.3	%
Gain on Derivatives, Net		60,176			38,876			21,300			54.8	%
Other Income (Expense)		(129	)		73			(202	)		-276.7	%
Loss on Equity Method Investments		(411	)		(813	)		402			-49.4	%
Total Other Income		11,853			1,191			10,662			895.2	%
Income (Loss) from Continuing Operations Before Income Tax		(346,752	)		31,970			(378,722	)		-1184.6	%
Income Tax Expense		(6,030	)		(15,460	)		9,430			-61.0	%
Income (Loss) from Continuing Operations		(352,782	)		16,510			(369,292	)		-2236.8	%
Loss from Discontinued Operations, Net of Income Taxes		(8,251	)		(59,160	)		50,909			-86.1	%
Net Loss		(361,033	)		(42,650	)		(318,383	)		746.5	%
Net Income Attributable to Noncontrolling Interests		2,245			4,039			(1,794	)		-44.4	%
Net Loss Attributable to Rex Energy		(363,278	)		(46,689	)		(316,589	)		678.1	%
Preferred Stock Dividends		(9,660	)		(2,335	)		(7,325	)		313.7	%
Net Loss Attributable to Common Shareholders	$	(372,938	)	$	(49,024	)	$	(323,914	)		660.7	%

Production and Lease Operating Expense increased approximately $24.3 million, or 35.0%, in 2015 from 2014. Since the first quarter of 2012, we have entered into several new transportation and marketing agreements to enhance our ability to sell our natural gas and NGLs. For the year ended December 31, 2015, these transportation and marketing agreements accounted for approximately 84.7% of our Production and Lease Operating Expense, as compared to 79.6% in 2014. 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. On a per unit of production basis, our lifting costs increased to $1.40 per Mcfe during 2015 from $1.35 in 2014.

General and Administrative Expense of approximately $26.7 million for 2015 decreased approximately $5.2 million, or 16.4%, from 2014. The year-over-year decrease is predominately due to several cost control measures taken including reductions in bonus compensation, reductions in head count, decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers. On a per unit of production basis, our G&A expenses decreased to $0.40 per Mcfe during 2015 from $0.62 per Mcfe during 2014.

Impairment Expense increased to $283.2 million in 2015 from $20.2 million in 2014. 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 $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 the 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.

The impairments were identified through an analysis of market conditions and future development plans that were in existence as of December 31, 2015, 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 as of December 31, 2015. 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.

Approximately $9.8 million of the impairment incurred during 2014 was attributable to proved properties and other fixed assets in the Appalachian Basin of that approximately $5.9 million of impairment was incurred for our salt water disposal well in Ohio due to the regulatory and environmental climate and the uncertainty of future viability of the disposal well. We also incurred approximately $3.6 million of impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the estimated future decrease in natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $10.4 million in unproved property impairments in the Appalachian Basin related to expiring leases that will not be developed.

Exploration Expense of condensate, NGL and natural gas properties for 2015 decreased approximately $4.2 million from $6.8 million in 2014. Approximately $1.0 million of the expense incurred during 2015 is attributable to geological and geophysical expenditures and approximately $1.4 million is attributable to delay rental payments predominately associated with properties in the Appalachian Basin. An additional $0.2 million was due to dry hole for one property in the Appalachian Basin. Approximately $3.7 million of the expense incurred during 2014 is attributable to geological and geophysical expenditures and delay rental payments associated with properties in the Appalachian Basin. Approximately $3.1 million of the expense incurred during 2014 was attributable to dry hole expense related to six exploratory projects in the Appalachian Basin were abandoned at various stages.

Depletion, Depreciation, Amortization and Accretion Expense of approximately $85.5 million for 2015 increased approximately $20.0 million, or 30.4%, from 2014. Contributing to the increase in DD&A expense were lower reserves, which were triggered by the ongoing lower commodity pricing environment, and increased production when compared to the same period in 2014.

Interest Expense for 2015 was approximately $47.8 million as compared to $37.0 million for 2014. The increase in interest expense was primarily due to the issuance of $325.0 million in aggregate principal amount of 2022 Notes in July 2014, as well as the outstanding balance on our senior credit facility for second half of 2015. We discuss our outstanding senior notes and senior credit facility later in this report, and in Note 9, Long-Term Debt, to our Consolidated Financial Statements.

Gain on Derivatives, net for 2015 was a gain of approximately $60.2 million as compared to a gain of approximately $38.9 million for 2014. The gain in 2015 included cash receipts for commodity and interest rate derivatives of $55.8 million while the gain in 2014 included cash payments of approximately $7.3 million related to commodity and interest rate derivatives. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil, NGL and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while gains would suggest the opposite. Our derivative program is designed to provide us with greater predictability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.

Income Tax Expense for 2015 was approximately $6.0 million as compared to $15.5 million in 2014. Our effective tax rate in 2015 was approximately -1.7% as compared to 48.4% in 2014. As of December 31, 2015, we had a significant level of future tax benefits, some of which are not expected to be fully utilized, therefore limiting our ability to recognize further tax benefits.

Preferred Stock Dividends for 2015 totaled approximately $9.7 million as compared to $2.3 million in 2014. In August 2014, we completed an offering of Series A Preferred Stock, on which we paid a dividend of $145.00 per preferred share in November 2014. Quarterly dividends of approximately $2.4 million were paid in 2015. 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 in accordance with the terms of the Series A Preferred Stock 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 2015 was approximately $372.9 million, as compared to approximately $49.0 million for 2014 as a result of the factors discussed above.

Our primary financial resource is our base of condensate, natural gas and NGL reserves. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, cash flows from operations, borrowings under our senior credit facility and net proceeds from debt and equity offerings have been used to fund exploration and development of our oil and gas interests. During 2016, we spent approximately $36.2 million of capital on drilling projects, facilities and related equipment and acquisitions of acreage. Our 2016 capital program was funded with net cash flow from operations, net proceeds from the disposition of our assets in the Illinois Basin and from borrowings under our revolving credit facility. Offsetting some of the cost associated with our capital expenditure program in 2016 were our joint ventures with ArcLight and BSP. Our 2017 capital expenditure plan of between $70.0 and $80.0 million is expected to be funded primarily by cash flow from operations, joint venture proceeds, non-core asset sales and borrowings under our revolving credit facility.

As of December 31, 2016, we had approximately $3.7 million of cash on hand. In January 2017, we received approximately $24.1 million of proceeds in conjunction with the closing of the sale of our Warrior South assets in Ohio. The remaining proceeds of approximately $5.0 million are expected to be received in January 2018. At December 31, 2016, outstanding borrowings under our revolving credit facility consisted of $117.7 million of borrowings and an additional $46.5 million of undrawn letters of credit, of which approximately $46.0 million are related to our firm transportation contracts. Upon the initial closing of the Warrior South sale, we subsequently paid our revolving credit facility down to approximately $94.7 million. The next borrowing base redetermination will occur on or about April 1, 2017.

Our ability to fund our capital expenditures is dependent upon the level of product prices and the success of our exploration program in replacing existing condensate, NGL and natural gas reserves. If commodity prices decline further, operating cash flows may decrease and our lenders may reduce the borrowing base, thus reducing the funds available to fund future capital expenditures. If we are unable to replace our condensate, NGL and natural gas reserves through acquisition, development and exploration, we may also suffer a reduction in operating cash flows and access to funds under the revolving credit facility. We have the ability to add commodity derivatives to our portfolio at prevailing market rates to mitigate a portion of the decrease in operating cash flows should commodity prices decline. At December 31, 2016, we were in compliance with all required debt covenants under our revolving credit facility.

Due to the elongated depression of commodity prices, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Preferred Stock; we have not paid a quarterly dividend since that time. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. As a result of not declaring and paying quarterly dividends on our Series A Preferred Stock, we are no longer 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 securities with the SEC (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital. We may need to take additional actions in the future to address current industry trends and maintain our ability to pay expenses and service our indebtedness, including, but not limited to, selling assets or raising capital by issuing additional debt or equity securities.

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, 2016, the Company’s Fixed Charge Coverage Ratio was 1.02:1 As a result, we anticipate that our ability to incur debt, pay dividends or make certain other restricted payments will be subject to the more restrictive provisions of the Indentures for the foreseeable future. As of December 31, 2016, we were limited to incurring an additional $169.9 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 $227.5 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 $402.4

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 revolving credit facility contains a number of restrictive covenants and limitations that impose significant operating and financial restrictions on us. In particular, our financial covenants require us to maintain a minimum consolidated current ratio of 1.0 to 1.0 and a maximum ratio of net senior-secured debt to EBITDAX, a non-GAAP measure, of 2.75 to 1.0. Failure to comply with either of these covenants could have an adverse effect on our business. If an event of default under our revolving credit facility occurs and remains uncured, the lenders thereunder:

Our revolving credit facility 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 and a minimum “Total PDP PV-9” to net senior secured debt 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. In order to improve our liquidity positions to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, and may require the consent of one or more third parties, including one or more of the following (i) refinancing of existing debt, (ii) debt-for-debt or debt for equity exchanges, (iii) joint venture opportunities, (iv) minimizing capital expenditures, (v) improving cash flows from operations, (vi) effectively managing working capital (vii) adding hedging positions, (viii) asset sales, and (ix) in- and out-of-court restructuring transactions. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transaction can be consummated within the period needed to meet certain obligations.

Financial Condition and Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

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

Net cash provided by (used in) 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 provided by operating activities decreased by approximately $131.8 million in 2015 when compared to 2014, to $30.9 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 in our Appalachian Basin operations.

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 used in investing activities decreased by approximately $404.6 million in 2015 when compared to 2014, to $155.4 million. This decrease was primarily attributed to lower capital activity levels related to the currently depressed commodity price environment, 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.

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 on our revolving line of credit which was partially offset by the suspension of our preferred stock dividend payments. Net cash provided by financing activities in 2015 decreased by approximately $306.0 million when compared to 2014, to $107.6 million. The decrease in cash provided is primarily due to proceeds of $325.0 million related to our offering of 2022 Notes and proceeds of $155.0 million related to our offering of Series A Preferred Stock in 2014, which were partially offset by an increase in net borrowings on our revolving credit facility. During 2014, we received combined proceeds of approximately $473.2 million from our preferred stock offering and private offering of 2022 Notes.

As market conditions warrant and subject to our contractual restrictions in our revolving credit facility 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 shares of our common stock or outstanding debt, including our senior unsecured notes, by tender offer 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 volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, 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, 2016 and 2015 were $0.1 million and $0.2 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 condensate, NGL and natural gas 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 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 oil, NGL and natural gas prices are based on forward strip prices for NYMEX oil and Henry Hub natural gas and other related indices. 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 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 oil, NGL and natural gas 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 $74.6 million, $283.2 million and $20.2 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2016, 2015 and 2014, 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 oil, NGLs and natural gas 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, 2016 and 2015, NSAI prepared a consolidated 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 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 engineer estimates 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.

Condensate, NGL and natural gas revenue is recognized when the condensate, NGL or natural gas 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 oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil, NGLs and natural gas 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. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser.

To the extent actual quantities and values of oil, 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 Consolidated Balance Sheets and Oil, Natural Gas and NGL Sales on the Statements of Operations.

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.

income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2016, 2015 and 2014 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.

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.

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.

In August 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The new guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote

disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We adopted this ASU on January 1, 2016. In conjunction with the adoption of ASU 2015-03, we reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. Adoption did not have an impact on Net Income or Accumulated Deficit.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU superseded the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:

4) Allocate the transaction price to the performance obligations in the contract.

5) Recognize revenue when (or as) the entity satisfies a performance obligation.

An entity should apply the amendments in this ASU using one of the following two methods:

2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.

In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period after December 15, 2017. Early adoption is not permitted. We continue to evaluate the available adoption methods. We are currently analyzing the potential impact of the standard on each of our revenue contracts by identifying differences between current recognition policies and the guidance set forth in the standard. As of December 31, 2016 we were still evaluating the potential impact of this standard on our results of operations and internal control environment.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. The ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are required to classify all deferred tax assets and liabilities as noncurrent. The amendments apply to all organizations that present a classified balance sheet. We adopted this ASU on January 1, 2016. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Deferred Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero. Adoption did not have an impact on Net Income or Accumulated Deficit.

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 this guidance and do not believe it will have a material impact due to our minimal number of operating leases.

In March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. Under this update, several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public companies, the amendments are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. We elected to early adopt ASU 2016-09 effective January 1, 2016 utilizing a modified retrospective approach. An income tax benefit of approximately $1.3 million representing previously unrecognized tax benefits originating from our deferred compensation plans was recognized as of January 1, 2016 through a cumulative adjustment to retained earnings. As the deferred tax asset generated by the cumulative effect adjustment was subject to a full valuation allowance, there is no cumulative effect to retained earnings as a result of the adoption of ASU 2016-09. With the adoption of ASU 2016-09 we are electing to continue our current process of estimating the number of forfeitures of equity based awards in accounting for our deferred compensation plans. As such, this election has no cumulative effect on retained earnings. We have elected to present the cash flow statement on a prospective transition method and no prior periods have been adjusted. As required by ASU 2016-09, we have adjusted our earnings per share calculation model to exclude the tax effect of any anticipated windfall benefits or shortfalls, when projecting proceeds available for share repurchases.

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 oil and natural gas.

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 year ended December 31, 2016, the net realized gain on oil, natural gas and NGL derivatives was approximately $32.9 million. For the year ended December 31, 2015, the net realized gain on oil, natural gas and NGL derivatives was approximately $54.9 million. For the year ended December 31, 2016, our total net loss on oil, natural gas and NGL derivatives was approximately $34.3 million, as compared to a net gain of approximately $59.2 million on oil, NGL and natural gas derivatives for 2015. 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 oil, NGL and natural gas derivative positions at December 31, 2016, 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, 2016, 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, 2016.

The following summarizes our contractual financial obligations for continuing operations at December 31, 2016 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities.

	Payment Due by Period (in thousands)
	2017		2018		2019		2020		2021		Thereafter		Total
Senior Notes (a)	$	—	$	—	$	—	$	595,529	$	—	$	5,648	$	601,177
Operating Leases		997		565		563		422		—		—		2,547
Other Loans and Notes Payable		764		807		118,614		1,104		554		—		121,843
Derivative Obligations (b)		24,375		6,309		230		190		—		—		31,104
Firm Commitments (c)		62,345		64,854		64,068		62,805		59,806		562,214		876,092
Asset Retirement Obligations (d)		2,965		514		12		374		6		5,994		9,866
Total Contractual Obligations	$	91,446	$	73,049	$	183,487	$	660,424	$	60,366	$	573,856	$	1,642,629

At December 31, 2016, we had $117.7 million in borrowings outstanding under our revolving credit facility. The interest rates on outstanding balances during 2016 on our revolving credit facility averaged 3.8%. At December 31, 2016, we had $7.6 million in aggregate principal amount of 2020 Notes outstanding, bearing interest at 8.875% annually, $5.6 million in aggregate principal amount of 2022 Notes outstanding bearing interest at 6.25% annually, and $588.0 million in aggregate principal amount of New Notes outstanding, bearing interest at 1% annually through September 30, 2017 and 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, oil, natural gas and NGLs. Conversely, increases in the market prices for oil, natural gas and NGLs can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2016 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 gas from average 2016 prices would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2017 by approximately $13.0 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, swaptions, deferred put spreads, cap swaps, call protected swaps 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 oil, natural gas and NGLs. 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, 2016 of $4.1 million.

At December 31, 2016, the following commodity derivative contracts were outstanding:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2017 - Deferred Premium Put		15,000	Bbls	$	—	$	51.00	$	—	$	—		$	(9	)
2017 - Swaps		81,000	Bbls		—		—		—		53.30			(220	)
2017 - Collars		48,000	Bbls		—		45.00		57.20		—			(86	)
2017 - Three-Way Collars		93,000	Bbls		40.16		49.68		61.50		—			(132	)
2018 - Swaps		60,000	Bbls		—		—		—		54.00			(146	)
2018 - Three-Way Collars		60,000	Bbls		43.00		52.00		62.30		—			(58	)
		357,000	Bbls										$	(651	)
Natural Gas
2017 - Swaps		11,000,000	Mcf	$	—	$	—	$	—	$	3.11		$	(4,468	)
2017 - Swaptions		—	Mcf		—		—		—		3.15			(1,258	)
2017 - Cap Swaps		3,900,000	Mcf		2.35		—		—		2.81			(3,303	)
2017 - Three-Way Collars		17,510,000	Mcf		2.33		3.01		3.87		—			(2,246	)
2017 - Calls		3,000,000	Mcf		—		—		3.64		—			(1,478	)
2017 - Basis Swaps - Dominion South		14,745,000	Mcf		—		—		—		(0.86	)		(53	)
2017 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(355	)
2017 - Collars		1,700,000	Mcf		—		2.54		3.20		—			(873	)
2018 - Swaps		5,510,000	Mcf		—		—		—		3.25			(797	)
2018 - Swaptions		—	Mcf		—		—		—		3.15			(167	)
2018 - Collars		450,000	Mcf		—		3.20		3.65		—			(115	)
2018 - Three-Way Collars		8,775,000	Mcf		2.30		2.89		3.58		—			(1,786	)
2018 - Basis Swaps - Dominion South		16,242,500	Mcf		—		—		—		(0.82	)		(193	)
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(355	)
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(491	)
2019 - Basis Swaps - Dominion South		16,242,500	Mcf		—		—		—		(0.81	)		(230	)
2020 - Basis Swaps - Dominion South		13,542,000	Mcf		—		—		—		(0.80	)		(189	)
		147,627,000	Mcf										$	(18,357	)
NGLs
2017 C3 + NGL Swaps		1,337,000	Bbls	$	—	$	—	$	—	$	28.14		$	(8,197	)
2017 Ethane Swaps		840,000	Bbls		—		—		—		10.50			(1,698	)
2018 C3 + NGL Swaps		852,000	Bbls		—		—		—		28.98			(2,082	)
2018 Ethane Swaps		300,000	Bbls		—		—		—		13.02			(118	)
		3,329,000	Bbls										$	(12,095	)

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, 2016, we had commodity derivative contracts relating to production through 2021.

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, 2016, we had approximately $117.7 million outstanding under our senior credit facility, which is subject to variable rates of interest, and had $601.2 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, 2016 of approximately $718.9 million, a 1.0% change in interest rates would impact our interest expense by approximately $7.2 million.

We entered into fixed-to-variable interest rate swaps during 2015 and 2014; however, there were no arrangements in place as of December 31, 2016 and 2015. 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 years ended December 31, 2015 and 2014, we received cash payments of approximately $0.9 million and $1.3 million, respectively 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, 2016 and 2015, and the related consolidated statements of operations, changes in noncontrolling interests and stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

	December 31, 2016			December 31, 2015
ASSETS
Current Assets
Cash and Cash Equivalents	$	3,697		$	1,091
Accounts Receivable		25,448			17,274
Taxes Receivable		211			18
Short-Term Derivative Instruments		1,873			34,260
Inventory, Prepaid Expenses and Other		2,546			3,059
Assets Held for Sale		—			53,151
Total Current Assets		33,775			108,853
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		1,053,461			943,092
Unevaluated Oil and Gas Properties		215,794			262,992
Other Property and Equipment		21,401			20,363
Wells and Facilities in Progress		21,964			141,100
Pipelines		18,029			14,024
Total Property and Equipment		1,330,649			1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(475,205	)		(430,528	)
Net Property and Equipment		855,444			951,043
Other Assets		2,492			2,501
Long-Term Derivative Instruments		2,212			9,534
Total Assets	$	893,923		$	1,071,931
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	40,712		$	36,785
Current Maturities of Long-Term Debt		764			402
Accrued Liabilities		37,207			40,608
Short-Term Derivative Instruments		25,025			2,486
Liabilities Related to Assets Held for Sale		—			36,320
Total Current Liabilities		103,708			116,601
Long-Term Derivative Instruments		7,227			5,556
Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs		113,785			109,386
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges		641,762			663,089
Premium (Discount) on Senior Notes, Net		(3,601	)		2,344
Other Long-Term Debt		3,409			—
Other Deposits and Liabilities		8,671			3,156
Future Abandonment Cost		8,736			11,568
Total Liabilities	$	883,697		$	911,700
Commitments and Contingencies (See Note 7)
Stockholders’ Equity
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 3,987 issued and outstanding on December 31, 2016 and 16,100 shares issued and outstanding on December 31, 2015.	$	1		$	1
Common Stock, $.001 par value per share, 200,000,000 shares authorized and 97,870,608 shares issued and outstanding on December 31, 2016 and 55,741,229 shares issued and outstanding on December 31, 2015		95			54
Additional Paid-In Capital		650,584			623,863
Accumulated Deficit		(640,454	)		(463,687	)
Total Stockholders’ Equity		10,226			160,231
Total Liabilities and Stockholders’ Equity	$	893,923		$	1,071,931

	Year Ended December 31,
	2016			2015			2014
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	139,000		$	138,707		$	225,511
Other Revenue		17			42			118
TOTAL OPERATING REVENUE		139,017			138,749			225,629
OPERATING EXPENSES
Production and Lease Operating Expense		104,699			93,892			69,547
General and Administrative Expense		20,621			26,694			31,917
(Gain) Loss on Disposal of Assets		(4,121	)		(540	)		218
Impairment Expense		74,619			283,244			20,225
Exploration Expense		2,178			2,617			6,813
Depreciation, Depletion, Amortization and Accretion		62,874			85,844			65,817
Other Operating Expense		10,754			5,603			312
TOTAL OPERATING EXPENSES		271,624			497,354			194,849
INCOME (LOSS) FROM OPERATIONS		(132,607	)		(358,605	)		30,780
OTHER INCOME (EXPENSE)
Interest Expense		(43,519	)		(47,783	)		(36,945	)
Gain (Loss) on Derivatives, Net		(32,515	)		60,176			38,876
Other Income (Expense)		(2,124	)		(129	)		73
Debt Exchange Expense		(9,063	)		—			—
Gain on Extinguishments of Debt		24,627			—			—
Loss on Equity Method Investments		—			(411	)		(813	)
TOTAL OTHER INCOME (EXPENSE)		(62,594	)		11,853			1,191
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		(195,201	)		(346,752	)		31,971
Income Tax Expense		(2,436	)		(6,030	)		(15,460	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		(197,637	)		(352,782	)		16,511
Income (Loss) From Discontinued Operations, Net of Income Taxes		20,922			(8,251	)		(59,161	)
NET LOSS		(176,715	)		(361,033	)		(42,650	)
Net Income Attributable to Noncontrolling Interests		—			2,245			4,039
NET LOSS ATTRIBUTABLE TO REX ENERGY	$	(176,715	)	$	(363,278	)	$	(46,689	)
Preferred Stock Dividends		(5,091	)		(9,660	)		(2,335	)
Effect of Preferred Stock Conversions		72,984			—			—
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(108,822	)	$	(372,938	)	$	(49,024	)
Earnings per common share:
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(1.63	)	$	(6.66	)	$	0.27
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.26		$	(0.19	)		(1.19	)
Basic – Net Loss Attributable to Rex Energy Common Shareholders	$	(1.37	)	$	(6.85	)	$	(0.92	)
Basic – Weighted Average Shares of Common Stock Outstanding		79,256			54,392			53,150
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders	$	(1.63	)	$	(6.66	)	$	0.27
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders		0.26			(0.19	)		(1.19	)
Diluted – Net Loss Attributable to Rex Energy Common Shareholders	$	(1.37	)	$	(6.85	)	$	(0.92	)
Diluted – Weighted Average Shares of Common Stock Outstanding		79,256			54,392			53,150

	Common Stock					Preferred Stock
	Shares			Par Value		Shares			Par Value		Additional Paid- In Capital			Accumulated Deficit			Rex Energy Stockholders' Equity			Noncontrolling Interests			Total Stockholders’ Equity
BALANCE December 31, 2013		54,186		$	54		—		$	—	$	456,554		$	(41,725	)	$	414,883		$	2,042		$	416,925
Non-Cash Compensation		—			—		—			—		5,769			—			5,769			—			5,769
Issuance of Restricted Stock, Net of Forfeitures		(58	)		—		—			—		—			—			—			—			—
Stock Option Exercise		47			—		—			—		515			—			515			—			515
Capital Distributions		—			—		—			—		—			—			—			(1,840	)		(1,840	)
Issuance of Preferred Stock		—			—		16			1		154,988			—			154,989			—			154,989
Dividends Declared on Preferred Stock ($145.00 per preferred share)		—			—		—			—		—			(2,335	)		(2,335	)		—			(2,335	)
Net Income (Loss)		—			—		—			—		—			(46,689	)		(46,689	)		4,039			(42,650	)
BALANCE December 31, 2014		54,175		$	54	$	16		$	1	$	617,826		$	(90,749	)	$	527,132		$	4,241		$	531,373
Non-Cash Compensation		—			—		—			—		6,469			—			6,469			—			6,469
Issuance of Restricted Stock, Net of Forfeitures		1,566			—		—			—		—			—			—			—			—
Capital Distributions		—			—		—			—		—			—			—			(830	)		(830	)
Sale of Consolidated Subsidiary		—			—		—			—		(432	)		—			(432	)		(5,656	)		(6,088	)
Dividends Declared on Preferred Stock ($600.00 per preferred share)		—			—		—			—		—			(9,660	)		(9,660	)		—			(9,660	)
Net Income (Loss)		—			—		—			—		—			(363,278	)		(363,278	)		2,245			(361,033	)
BALANCE December 31, 2015		55,741		$	54	$	16		$	1	$	623,863		$	(463,687	)	$	160,231		$	—		$	160,231
Non-Cash Compensation		—			—		—			—		2,919			—			2,919			—			2,919
Issuance of Common Stock in Debt Exchange		8,413			8		—			—		6,404			—			6,412			—			6,412
Issuance of Common Stock for Debt Extinguishments		23,523			23		—			—		17,355			—			17,378			—			17,378
Preferred Stock Dividends Settled in Common Shares		62			—		—			—		52			(52	)		—			—			—
Issuance of Restricted Stock, Net of Forfeitures		820			1		—			—		—			—			1			—			1
Conversion of Preferred Stock to Common Stock		9,312			9		(12	)		—		(9	)		—			—			—			—
Net Loss		—			—		—			—		—			(176,715	)		(176,715	)		—			(176,715	)
BALANCE December 31, 2016		97,871		$	95		4		$	1	$	650,584		$	(640,454	)	$	10,226		$	-		$	10,226

	For the Years Ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(176,715	)	$	(361,033	)	$	(42,650	)
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities
Loss on Equity Method Investments		—			411			813
Non-cash Expenses		24,124			7,649			6,789
Depreciation, Depletion, Amortization and Accretion		67,975			104,822			98,171
(Gain) Loss on Derivatives		32,515			(60,176	)		(38,876	)
Cash Settlements of Derivatives		32,571			55,793			7,281
Dry Hole Expense		905			330			4,064
Deferred Income Tax Benefit		—			—			(25,992	)
Impairment Expense		78,162			345,775			132,684
Gain on Extinguishment of Debt		(24,627	)		—			—
(Gain) Loss on Disposal of Assets		(34,651	)		(521	)		589
Gain on Sale of Water Solutions		—			(57,778	)		—
Changes in operating assets and liabilities
Accounts Receivable		(6,414	)		21,679			(13,620	)
Inventory, Prepaid Expenses and Other Assets		906			(568	)		(1,359	)
Accounts Payable and Accrued Liabilities		2,795			(22,955	)		37,274
Other Assets and Liabilities		(1,950	)		(2,543	)		(2,462	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(4,404	)		30,885			162,706
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from Joint Venture Acreage Management		—			58			263
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		40,884			77,226			546
Proceeds from Joint Venture		19,461			16,611			—
Acquisitions of Undeveloped Acreage		(6,712	)		(28,242	)		(169,423	)
Acquisitions of Oil and Gas Properties and Equipment		(48,982	)		(221,099	)		(391,422	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		4,651			(155,446	)		(560,036	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		71,400			229,314			209,895
Repayments of Long-Term Debt and Lines of Credit		(65,230	)		(108,335	)		(263,152	)
Repayments of Loans and Other Notes Payable		(828	)		(1,519	)		(2,721	)
Proceeds from Senior Notes, Net of Discounts and Premiums		—			—			325,000
Debt Issuance Costs		(2,983	)		(1,414	)		(6,824	)
Proceeds from the Issuance of Preferred Stock, Net		—			—			154,988
Proceeds from the Exercise of Stock Options		—			—			515
Distributions by the Partners of Consolidated Subsidiary		—			(830	)		(1,840	)
Dividends Paid on Preferred Stock		—			(9,660	)		(2,335	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		2,359			107,556			413,526
NET INCREASE (DECREASE) IN CASH		2,606			(17,005	)		16,196
CASH AND CASH EQUIVALENTS – BEGINNING		1,091			18,096			1,900
CASH AND CASH EQUIVALENTS – ENDING	$	3,697		$	1,091		$	18,096
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS	$	3,697		$	1,091		$	17,978
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE	$	—		$	—		$	118
SUPPLEMENTAL DISCLOSURES
Interest Paid, net of capitalized interest		30,805			47,628			26,874
Cash Paid (Received) for Income Taxes		29			(502	)		(4,643	)
Capital Expenditures for Development of Oil & Gas Properties and Equipment Attributable to Discontinued Operations		1,346			14,210			41,612
NON-CASH ACTIVITIES
Fair value of contingent consideration receivable - sale of Illinois Basin		(2,936	)		—			—
Decrease in Accrued Liabilities for Capital Expenditures		712			(11,703	)		3,477
Decrease in Senior Notes, Net of Issuance Costs due to Debt to Equity Conversions		(47,182	)		—			—
Decrease in Bond Interest Payable due to Debt to Equity Conversions		(892	)		—			—
Increase in Common Stock outstanding due to Debt to Equity Conversions		17,378			—			—

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.

For purposes of compliance with Accounting Standards Update (“ASU”) 2015-3, which we adopted on January 1, 2016, we have reclassified approximately $2.1 million from Other Assets to Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs and approximately $11.9 million from Other Assets to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015. In addition, we adopted ASU 2015-17 on January 1, 2016, which eliminates the need to show deferred tax liabilities and assets as current and noncurrent. Our Consolidated Balance Sheet as of December 31, 2015 included $12.5 million in Long-Term Tax Assets and $12.5 million in Current Deferred Tax Liability. Reclassifying our Current Deferred Tax Liability to noncurrent allowed us to net our noncurrent asset and noncurrent liability together resulting in a net deferred tax balance of zero (see Recent Accounting Pronouncements in Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements for additional information). For purposes of consistency, we have reclassified $350.0 million and $325.0 million from 8.875% Senior Notes due 2020 and 6.25% Senior Notes due 2022, respectively, to Senior Notes, Net of Issuance Costs on our Consolidated Balance Sheets as of December 31, 2015.

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

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 and 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 years ended December 31, 2015 and 2014. As of December 31, 2016 and 2015, 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 assets and liabilities of our Illinois Basin operations have been classified as Held for Sale in the accompanying Consolidated Balance Sheets as of December 31, 2015 and the results of operations of our Illinois Basin operations have been classified as Discontinued Operations in the accompanying Consolidated Statements of Operations for the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016, we have a derivative asset of $2.9 million recorded, 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 oil, NGL and natural gas 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, 2016 and 2015, our Cash and Cash Equivalents consisted of only cash.

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 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, 2016 and 2015 were $0.1 million and $0.2 million, respectively.

At December 31, 2016, we carried approximately $22.2 million in production receivable, of which approximately $17.5 million were production receivables due from our three largest purchasers. At December 31, 2015, we carried approximately $9.9 million in production receivables, of which approximately $8.4 million were production receivables due from three purchasers. In addition, we carried approximately $2.7 million in receivables at December 31, 2016 and $3.2 million at December 31, 2015 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 condensate and NGLs held in terminal tanks located in the field. Condensate and NGL 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 oil, NGL and natural gas 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 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. 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, 2016, 2015 and 2014, we capitalized interest costs of $2.7 million, $7.7 million and $7.3 million, respectively.

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 oil, NGL and natural gas 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 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 oil, NGL and natural gas 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.

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.

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, 2016 and 2015, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated 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 condensate, 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 engineer estimates 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, 2016, 2015 and 2014 totaled approximately $1.0 million, $1.0 million and $0.7 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2016 and 2015, approximately $1.1 million and $0.4 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Liabilities on our Consolidated Balance Sheets. During 2016 and 2015, we recognized an increase of $1.9 million and $2.4 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.

Condensate, NGL and natural gas revenue is recognized when the condensate, NGL or natural gas 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 and NGL sales, title is transferred to the purchaser when the condensate or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of condensate, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for condensate, NGLs and natural gas 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. The point of sale for our condensate, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for condensate and NGL production held in stock tanks before delivery to the purchaser.

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 Natural Gas, NGL and Condensate Sales on the Statements of Operations.

In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, after December 15, 2017. Early adoption is not permitted. We continue to evaluate the available adoption methods. We are currently analyzing the potential impact of the standard on each of our revenue contracts by identifying differences between current recognition policies and the guidance set forth in the standard. As of December 31, 2016 we were still evaluating the potential impact of this standard on our results of operations and internal control environment.

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 condensate, natural gas and NGLs. 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.

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 2016, 2015 and 2014 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, 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.

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 FASB issued 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, 2016, we had 97,870,608 common shares outstanding, 1,181,100 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially

dilutive securities. The total common shares outstanding include 2,427,494 restricted stock awards, of which approximately 617,479 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share, to our Consolidated Financial Statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The new guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.

4) Allocate the transaction price to the performance obligations in the contract.

5) Recognize revenue when (or as) the entity satisfies a performance obligation.

An entity should apply the amendments in this ASU using one of the following two methods:

2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.

In March 2016, ASU 2014-09 was updated with ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (ASU 2016-08), which provides further clarification on the principal versus agent evaluation. ASU 2014-09 is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet and is effective for annual reporting periods, and interim periods within that reporting period, after December 15, 2017. Early adoption is not permitted. We continue to evaluate the available adoption methods. We are currently analyzing the potential impact of the standard on each of our revenue contracts by identifying differences between current recognition policies and the guidance set forth in the standard. As of December 31, 2016 we were still evaluating the potential impact of this standard on our results of operations and internal control environment..

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.

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.

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 Holdings, LLC and its subsidiaries (“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. 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, 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 20 of these additional wells. We expect total consideration for this transaction to be $175.0 million with approximately $126.1 million committed as of December 31, 2016. BSP has paid approximately $82.4 million for their interest in elected wells as of December 31, 2016. The remainder of the proceeds will be received as additional wells are drilled to total depth or placed in sales. BSP earns an assignment of 15%-20% working interest in acreage located within each of the units they participate. As of December 31, 2016, 30 of the 42 committed wells were in line and producing, eight wells were drilled and awaiting completion and four wells were in progress of being drilled.

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.

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 and received the additional proceeds of approximately $38.5 million at closing in August. 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. No proceeds were received for the quarter ending December 31, 2016, as WTI prices did not meet the necessary threshold. 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.

As described in Note 3 above, we sold Water Solutions pursuant to a purchase and sale agreement with American Water.

As of December 31, 2016 and 2015, 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.

	December 31,
($ in Thousands)	2016		2015			2014
Revenues:
Field Services Revenue	$	—	$	33,086		$	58,627
Total Operating Revenue		—		33,086			58,627
Costs and Expenses:
General and Administrative Expense		—		1,961			4,081
Depreciation, Depletion, Amortization and Accretion		—		78			3,703
Impairment Expense		—		—			67
Field Service Operating Expense		—		25,981			44,369
Gain on Disposal of Asset		—		(44	)		(55	)
Interest Expense		—		487			628
Other (Income) Expense		—		(57,589	)		66
Total Costs and Expenses (Income)		—		(29,126	)		52,859
Income from Discontinued Operations Before Income Taxes		—		62,212			5,768
Income Tax Expense		—		(24,227	)		(768	)
Income from Discontinued Operations, net of taxes		—	$	37,985		$	5,000

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.

The carrying value of assets and liabilities of our Illinois Basin operations that are classified as Held for Sale in the accompanying Consolidated Balance Sheets at December 31, 2015 are as follows:

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, 2016, 2015, and 2014.

	December 31,
($ in Thousands)	2016			2015			2014
Revenues:
Oil Sales	$	11,282		$	33,244		$	72,359
Total Operating Revenue		11,282			33,244			72,359
Costs and Expenses:
Production and Lease Operating Expense		11,033			25,099			30,556
General and Administrative Expense		1,002			2,741			4,219
(Gain) Loss on Disposal of Assets		(30,530	)		63			426
Impairment Expense		3,543			62,531			112,394
Exploration Expense		143			394			2,633
Depreciation, Depletion, Amortization and Accretion		5,100			18,900			28,650
Interest Expense		4			23			32
Other (Income) Expense		65			(14	)		(16	)
Total Costs and Expenses		(9,640	)		109,737			178,894
Income (Loss) from Discontinued Operations Before Income Taxes		20,922			(76,493	)		(106,535	)
Income Tax Benefit		—			30,257			42,374
Income (Loss) from Discontinued Operations, net of taxes	$	20,922		$	(46,236	)	$	(64,161	)
Production:
Crude Oil (Bbls)		310,388			729,251			806,162

RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly own 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.

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 2016 and 2015. RW Gathering recorded net losses from continuing operations of $2.0 million for each of the years ended December 31, 2016, 2015 and 2014. 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 applying the equity method of accounting for our share of the net losses due to our investment being reduced to zero.

At times during the years ended December 31, 2016 and 2015, 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 six high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our senior credit 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, 2016, we carried approximately $22.2 million in production receivables, of which approximately $17.5 million were production receivables due from three purchasers. At December 31, 2015, we carried approximately $9.9 million in production receivables, of which approximately $8.4 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.

As of December 31, 2016 and 2015, we did not have any reserves established for future legal obligations. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we currently believe that no reserve is needed, 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 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 future losses that are not currently accrued. Based on currently available information, we believe that it is remote that future costs, if any, 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 might be 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, 2016 and 2015, we had posted $46.5 million and $41.0 million, respectively, in various letters of credit to secure our drilling and related operations. Approximately $46.0 million of the letters of credit outstanding at December 31, 2016 are related to firm natural gas transportation agreements.

At December 31, 2016 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $0.9 million, $1.0 million and $0.8 million for the years ended December 31, 2016, 2015 and 2014, 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 $16.3 million in 2017, $16.3 million in 2018, $16.3 million in 2019, $16.4 million in 2020, $16.3 million in 2021 and $80.4 million thereafter, assuming our average working interest in the region of approximately 52.4%. For the years ended December 31, 2016, 2015 and 2014, we incurred capacity reservation charges of $3.2 million, $0.6 million and $0.2 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 2017 and beyond, we expect that our capacity reservation fees will decrease.

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 $2.7 million in 2017 and $1.8 million in 2018, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations for the year ended December 31, 2015. Approximately $2.5 million of this amount was paid in January 2015 and $2.3 million of this amount was paid in January 2016.

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 $402.4 million.

For the years ended December 31, 2016, 2015 and 2014, we incurred expenses related to the transportation, processing and marketing our condensate, natural gas and natural gas liquids of approximately $91.7 million, $79.5 million and $55.4 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 will 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. The fee for each unconventional natural gas well is determined using the following matrix with vertical unconventional natural gas wells being charged 20%:

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, 2016, we did not pay Charlie Brown for use of the aircraft. For each of the years ended December 31, 2015 and 2014 we paid Charlie Brown approximately $0.1 million 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.

Charlie Brown II has a loan from Graystone Bank to purchase the aircraft that was originally $1.5 million at its inception in June 2007. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan required payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II has been required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The company and Shaner Hotel each guarantee up to fifty percent, or $0.8 million, of the principal balance of the loan. The balance of this loan as of December 31, 2016 and 2015 was approximately $0.9 million and $1.0 million, respectively. For the years ended December 31, 2016, 2015 and 2014, we paid Charlie Brown II approximately $0.2 million, $0.3 million and $0.2 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.

As of December 31, 2016, there were negligible amounts due to or from us to any Shaner affiliated entities.

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 amount of $35,000 which began on April 1, 2013 and end on December 31, 2017, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The term of the lease may be extended for up to three five-year extensions or the property may be purchased outright by our exercise of a purchase option at the end of the initial five-year lease term. For the year 2016, 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.

We own a 40% interest in RW Gathering which owns gas-gathering assets to 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, $0.7 million and $0.7 million for the years ended December 31, 2016, 2015 and 2014, respectively, in compression expenses that were charged to us from Williams Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2016, 2015 and 2014, there were no receivables or payables in relation to RW Gathering due to or from us.

We incurred approximately $6.1 million and $20.1 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) and 2014, respectively. Of the amounts incurred, we eliminated approximately $4.7 million and $16.2 million in consolidation for the years 2015 and 2014, respectively. As of December 31, 2015, we had no payables owed to Water Solutions for work performed during the periods 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.

We maintain a revolving credit facility, evidenced by a credit agreement dated March 27, 2013 and most recently updated on July 1, 2016 (the “Senior Credit Facility”) with Royal Bank of Canada, as Administrative Agent and lenders from time to time parties thereto. Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. As of December 31, 2016, the borrowing base under the Senior Credit Facility was $190.0 million. The borrowing base under the Senior Credit Facility may be increased to up to $400.0 million with consent of the lenders and other conditions prescribed in the agreement upon re-determinations of the borrowing base. Effective January 11, 2017, in connection with the twelfth amendment, our Senior Credit Facility was amended to reduce letter of credit commitment to the greater of a) $50.0 million less reductions or terminations of surety letters of credit on or after the twelfth amendment effective date in excess of $10.0 million in aggregate and b) $40.0 million. As of December 31, 2016, we had $46.5 million in outstanding undrawn letters of credit. For additional information on our most recent Senior Credit Facility amendments, see Note 26, Subsequent Events, to our Consolidated Financial Statements.

The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition or divestiture of proved developed producing oil and gas reserves with a purchase or sale price for such reserves greater than 10% of the then borrowing base. Our next scheduled redetermination will occur on or about April 1, 2017. As of December 31, 2016, loans made under the Senior Credit Facility were set to mature on September 12, 2019. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of December 31, 2016, we had $117.7 million borrowings outstanding and there were $111.5 million borrowings outstanding as of December 31, 2015. Our Senior Credit Facility restricts the amount of cash and cash equivalents that we can hold on our Consolidated Balance Sheet to a maximum of $15.0 million. Any excess must be used to pay down the outstanding loans; however, we retain the right to redraw such amounts so long as availability exists under our borrowing base.

Subsequent to our February 3, 2016 amendment, and at our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” or the “Alternate Base Rate,” plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of (i) the rate per annum as determined by the administrative agent by reference to the rate set by ICE Benchmark Administration for deposits in dollars for a period equal to the applicable interest period (the “LIBO Rate”), multiplied by (ii) the statutory reserve rate. The Alternate Base Rate is equal to the greatest of (a) Royal Bank of Canada’s prime rate in effect at its principal office in Toronto, Canada, (b) the weighted average of the rates on overnight Federal funds transactions published on the next succeeding business day by the Federal Reserve Bank of New York (the “Federal Funds Effective Rate”), plus 0.5%, and (c) the Adjusted LIBO Rate for a one month interest period plus 1.0%. The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 225 to 325 basis points, and in the case of loans bearing interest at the Alternate Base Rate, ranges from 125 to 225 basis points, in each case, determined based upon our borrowing base utilization at such date of determination. Upon the occurrence and continuance of an event of default, all outstanding loans shall bear interest at a per annum rate equal to 200 basis points plus the then effective rate of interest. Interest is payable on the last day of each applicable interest period.

Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. As of December 31, 2016, we were in compliance with these swap agreement restrictions. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million or 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.

The Senior Credit Facility 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 (for further information, see Note 2, Summary of Significant Accounting Policies, Note 6, Concentrations of Credit Risk, and Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements). Borrowings under the Senior Credit Facility have been used to finance our working capital needs and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under the Senior Credit Facility are secured by mortgages on the oil and gas properties of our subsidiaries located in the states of Pennsylvania and Ohio. As a result of the March 14, 2016 amendment to our Senior Credit Facility, we are required to maintain liens on 95% of the total value of all our oil and gas properties, with certain properties within our Moraine East operated area and our Warrior North operated area requiring liens on 100% of such properties.

The Senior Credit Facility requires we meet certain financial requirements, on a quarterly basis, including a minimum consolidated current ratio, a maximum “Net Senior Secured Debt” to EBITDAX ratio and minimum “Total PDP PV-9” to net senior secured debt ratio (all terms in quotations as defined in the Senior Credit Facility). EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, including our lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash and non-recurring activities. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, including the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day (the “Current Ratio”), must not be less than 1.0 to 1.0. Our current ratio as of December 31, 2016 was approximately 1.0 to 1.0. Due to the level of our current ratio being at the low end of the required minimum of 1.0 to 1.0, we received advanced confirmation of compliance with this metric from our Senior Credit Facility syndication. We believe that our current ratio will continue to improve over the course of the next twelve months in conjunction with the execution of our current development plan. Subsequent to December 31, 2016, we received approximately $24.1 million in proceeds related to our sale of assets in our Warrior South prospect in Ohio, which has provided additional liquidity in advance of the execution of our development plans. Additionally, as of the last day of any fiscal quarter, our ratio of “Net Senior Secured Debt” to EBITDAX for the trailing twelve months must not exceed 2.75 to 1.0. Our ratio of “Net Senior Secured Debt” to EBITDAX as of December 31, 2016 was approximately 2.62 to 1.0. Beginning September 30, 2016, we were also required to meet a minimum ratio of “Total PDP PV-9” at the “Forward Strip Commodity Prices” as of each date of determination to “Net Senior Secured Debt” (the “PDP Coverage Ratio”) of at least 1.65 to 1.0. Our PDP Coverage Ratio as of December 31, 2016 was approximately 4.10 to 1.0. Our Senior Credit Facility also contains a requirement limiting our aggregate trailing twelve month net capital expenditures during any fiscal quarter in 2016 and 2017 at $65 million unless our PDP Coverage Ratio exceeds 2.0 to 1.0. Management currently anticipates being in compliance with these financial covenants as of December 31, 2017 and beyond.

In order to improve our liquidity positions to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions, which in certain cases may involve current investors, affiliates of the Company, or other financing or strategic counterparties, and may require the consent of one or more third parties, including one or more of the following (i) refinancing of existing debt, (ii) 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 will be raised from any transactions or that any such transactions can or will be consummated within the period needed to meet our obligations.

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 Senior Secured Second Lien Notes (the “New Notes”) and (ii) an aggregate of 10.1 million shares of our common stock (the “Shares”). We accounted for these transactions as troubled debt restructurings. As a result of the Exchanges, the future undiscounted cash flows of the New 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. The effective interest rate of the New Notes is 6.06% compared to the stated initial rate of 1.0%, increasing to 8.0% effective April 1, 2018. 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 New Notes and (ii) an aggregate of 8.4 million shares, which had a fair value of $6.5 million upon issuance. An additional $0.5 million aggregate principal amount of New 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. 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. The New Notes will bear interest at a rate of 1.0% per annum for the first three semi-annual interest payments after issuance and 8.0% per annum thereafter, commencing with the payment due April 1, 2018, 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 for 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 with certain holders of our Existing Notes, as well as holders or our New Notes. In all cases we accounted for the exchanges as troubled debt restructurings. We completed an exchange with a single holder representing a troubled debt restructuring with a modification of terms, wherein the holder exchanged a portion of their notes for a privately negotiated amount of our common shares. $43.5 million of our New Notes were tendered and subsequently cancelled, in exchange for common shares with a fair value of $10.9 million. As the future undiscounted cash flows of the holder’s remaining New Notes was greater than our carrying amount of the debt, no gain was recognized. We have reduced the principal amount of the New Notes outstanding by the fair value of the equity given in the exchange, and a new interest rate has been established. The effective interest rate of the remaining notes outstanding due to this holder is 1.16%, compared to the stated rate of 1.0%, and increasing to 8.0% effective April 1, 2018.

We completed exchanges with several holders of our Existing Notes and our New Notes, which were accounted for as troubled debt restructurings, with full extinguishment of debt. $28.7 million in aggregate principal amount of our remaining Existing Notes and $2.2 million in aggregate principal of our outstanding New Notes, in exchange for the issuance of an aggregate of approximately 13.2 million shares of our unrestricted common stock. The exchanged notes were subsequently cancelled, resulting in a gain to the Company for the year ended December 31, 2016 of $24.6 million, or $0.25 per common share, presented as Gain on Extinguishments of Debt in our Consolidated Statement of Operations.

We may redeem, at specified redemption prices, some or all of the New Notes at any time on or after April 1, 2018. We may also redeem up to 35% of the New 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 New Notes from the holders.

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

Our Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise. For additional information on our guarantor and non-guarantor subsidiaries, see Note 25, Condensed Consolidating Financial Information, to our Consolidated Financial Statements.

As of December 31, 2016, we had approximately $638.2 million of Senior Notes outstanding, which is inclusive of a net discount of $3.6 million and deferred financing costs of $15.9 million. As of December 31, 2015, we had approximately $677.3 million of Senior Notes outstanding, which is inclusive of a net premium of $2.3 million and deferred financing costs of $15.3 million. The amortization of our net discount in 2016 and net premium in 2015, which follows the effective interest method, resulted in reductions to our interest expense for 2016 and 2015, of approximately $5.2 million and $0.4 million, respectively.

Each series of the Senior Notes are governed by an indenture (collectively, the “Indentures”), which 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 to1.00. As of December 31, 2016, the Company’s Fixed Charge Coverage Ratio was 1.02 to 1.00. We expect our Fixed Charge Coverage Ratio to improve based on our projections of decreased interest expense related to the New Notes. As of December 31, 2016, we were limited to incurring an additional $166.3 million in additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default. In certain circumstances, the individual Trustees or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at December 31, 2016 and December 31, 2015:

The following is the principal maturity schedule for total debt outstanding as of December 31, 2016:

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 oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL 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, 2016, 2015 and 2014, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, call protected swaps, 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.

Swaption agreements provide options to counterparties to extend swaps into subsequent years. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. 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 six 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 received net cash settlements of $32.6 million, $54.9 million and $6.0 million in relation to our commodity derivatives for the years ended December 31, 2016, 2015 and 2014 respectively.

As of December 31, 2016, we had over 65.0% of our 2016 condensate production volumes hedged through 2017, over 75.0% of our 2016 natural gas production volumes hedged through 2017 and over 50.0% of our 2016 NGL production volumes hedged through 2017. Including the effects of derivatives added since December 31, 2016, of our 2016 natural gas production over 80.0% is hedged through 2017 and over 60.0% of our 2016 NGL production hedged through 2017. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future development or the natural decline of our condensate, NGL and gas production.

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, 2016, the contract had a fair value of approximately $2.9 million. 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, 2016, we had approximately $117.7 million in borrowings outstanding under our Senior Credit Facility, which is subject to variable rates of interest, and had $601.2 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 and 2014, however there were no arrangements in place as of December 31, 2016 and 2015. 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 years ended December 31, 2015 and 2014, we received cash payments of approximately $0.9 million and $1.3 million, respectively, 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, 2016, 2015 and 2014:

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 $28.2 million as of December 31, 2016, and a net asset of $35.8 million at December 31, 2015. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2016 consisted of the following:

Period	Volume			Put Option		Floor		Ceiling		Swap			Fair Market Value ($ in Thousands)
Oil
2017 - Deferred Premium Put		15,000	Bbls	$	—	$	51.00	$	—	$	—		$	(9	)
2017 - Swaps		81,000	Bbls		—		—		—		53.30			(220	)
2017 - Collars		48,000	Bbls		—		45.00		57.20		—			(86	)
2017 - Three-Way Collars		93,000	Bbls		40.16		49.68		61.50		—			(132	)
2018 - Swaps		60,000	Bbls		—		—		—		54.00			(146	)
2018 - Three-Way Collars		60,000	Bbls		43.00		52.00		62.30		—			(58	)
		357,000	Bbls										$	(651	)
Natural Gas
2017 - Swaps		11,000,000	Mcf	$	—	$	—	$	—	$	3.11		$	(4,468	)
2017 - Swaptions		—	Mcf		—		—		—		3.15			(1,258	)
2017 - Cap Swaps		3,900,000	Mcf		2.35		—		—		2.81			(3,303	)
2017 - Three-Way Collars		17,510,000	Mcf		2.33		3.01		3.87		—			(2,246	)
2017 - Calls		3,000,000	Mcf		—		—		3.64		—			(1,478	)
2017 - Basis Swaps - Dominion South		14,745,000	Mcf		—		—		—		(0.86	)		(53	)
2017 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(355	)
2017 - Collars		1,700,000	Mcf		—		2.54		3.20		—			(873	)
2018 - Swaps		5,510,000	Mcf		—		—		—		3.25			(797	)
2018 - Swaptions		—	Mcf		—		—		—		3.15			(167	)
2018 - Collars		450,000	Mcf		—		3.20		3.65		—			(115	)
2018 - Three-Way Collars		8,775,000	Mcf		2.30		2.89		3.58		—			(1,786	)
2018 - Basis Swaps - Dominion South		16,242,500	Mcf		—		—		—		(0.82	)		(193	)
2018 - Basis Swaps - Texas Gas		14,600,000	Mcf		—		—		—		(0.13	)		(355	)
2018 - Calls		5,810,000	Mcf		—		—		3.97		—			(491	)
2019 - Basis Swaps - Dominion South		16,242,500	Mcf		—		—		—		(0.81	)		(230	)
2020 - Basis Swaps - Dominion South		13,542,000	Mcf		—		—		—		(0.80	)		(189	)
		147,627,000	Mcf										$	(18,357	)
NGLs
2017 C3 + NGL Swaps		1,337,000	Bbls	$	—	$	—	$	—	$	28.14		$	(8,197	)
2017 Ethane Swaps		840,000	Bbls		—		—		—		10.50			(1,698	)
2018 C3 + NGL Swaps		852,000	Bbls		—		—		—		28.98			(2,082	)
2018 Ethane Swaps		300,000	Bbls		—		—		—		13.02			(118	)
		3,329,000	Bbls										$	(12,095	)

The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015 is summarized below.

	December 31,			December 31,
($ in Thousands)	2016			2015
Short-Term Derivative Assets:
Crude Oil—Collars	$	—		$	1,078
Crude Oil—Deferred Put Spread		—			852
Crude Oil—Three-Way Collars		—			577
NGL—Swaps		—			10,250
Natural Gas—Swaps		206			9,010
Natural Gas—Cap Swaps		61			1,977
Natural Gas—Basis Swaps		232			70
Natural Gas—Three-Way Collars		151			6,183
Natural Gas—Collars		—			1,728
Natural Gas—Swaption		—			798
Natural Gas—Put Spread		—			1,737
Contingent Consideration - Sale of Illinois Basin		1,223			—
Total Short-Term Derivative Assets	$	1,873		$	34,260
Long-Term Derivative Assets:
NGL—Swaps	$	—		$	344
Natural Gas—Cap Swaps		—			2,294
Natural Gas—Swaps		206			1,593
Natural Gas—Basis Swaps		293			195
Natural Gas—Three-Way Collars		—			5,108
Contingent Consideration - Sale of Illinois Basin		1,713			—
Total Long-Term Derivative Assets	$	2,212		$	9,534
Total Derivative Assets	$	4,085		$	43,794
Short-Term Derivative Liabilities:
Refined Product —Swaps		—			(376	)
Crude Oil—Collars		(86	)		—
Crude Oil—Deferred Premium Put		(9	)		—
Crude Oil—Three-Way Collars		(132	)		—
Crude Oil—Swaps		(220	)		—
NGL—Swaps		(9,895	)		—
Natural Gas—Three-Way Collars		(2,397	)		(31	)
Natural Gas—Cap Swaps		(3,364	)		—
Natural Gas—Collars		(873	)		—
Natural Gas—Basis Swaps		(640	)		(1,585	)
Natural Gas—Call		(1,478	)		—
Natural Gas—Swaption		(1,258	)		(202	)
Natural Gas—Swaps		(4,673	)		(292	)
Total Short - Term Derivative Liabilities	$	(25,025	)	$	(2,486	)
Long-Term Derivative Liabilities:
Crude Oil—Three-Way Collars		(58	)		—
Crude Oil—Swaps		(146	)		—
NGL—Swaps		(2,200	)		—
Natural Gas—Swaps		(1,004	)		—
Natural Gas—Collars		(115	)		—
Natural Gas—Swaption		(167	)		(297	)
Natural Gas—Basis Swaps		(1,260	)		(4,186	)
Natural Gas—Call		(491	)		(989	)
Natural Gas—Three-Way Collars		(1,786	)		(84	)
Total Long-Term Derivative Liabilities	$	(7,227	)	$	(5,556	)
Total Derivative Liabilities	$	(32,252	)	$	(8,042	)

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, 2016 and 2015, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.

Our Level 3 fair value measurements have been historically comprised of our natural gas basis swap contracts. As of December 31, 2016, these fair values transferred to Level 2 based on the observability of the inputs in calculating the fair value. Basis differential markets have become more heavily traded thus allowing the observable inputs to extend the full term of our contracts. The fair values recorded as of December 31, 2015 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of December 31, 2015 are included in the table below.

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, 2016 and 2015, 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, 2016 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, 2016 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, 2016 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, 2016 and 2015 (in thousands):

Changes in fair value on our Level 3 commodity derivative contracts outstanding for the years ended December 31, 2016 and 2015, resulted in an increase of approximately $7.2 million and a decrease of approximately $2.5 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.

We recorded an other than temporary impairment of $74.6 million related to proved properties, unproved properties and other non-revenue producing equipment. We utilize quoted futures prices and other observable market data in determining the fair value. 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:

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, 2016 and 2015:

	For the Years Ended December 31,
($ in Thousands)	2016			2015 (a)
Tax effects of temporary differences for:
Assets:
Asset retirement obligation	$	3,955		$	17,831
Deferred compensation plans		1,581			3,111
Compensation Accruals		762			767
Unrealized loss on derivatives		11,760			—
Tax basis of oil and gas properties in excess of book basis		—			8,965
Net operating loss carryforwards		79,531			123,488
Deferred Financing Costs (b)		182,519			—
Gas Transportation Capacity Commitments		3,031			—
Deferred revenue timing differences		443			969
Organization costs		391			456
Percentage depletion carryforward		2,717			2,673
AMT credits		2,131			292
Timing differences - tax partnerships		1,046			4,166
Other		331			372
Valuation allowances		(212,041	)		(148,159	) (c)
Total Deferred Tax Assets net of Valuation Allowances	$	78,157		$	14,931
Liabilities:
Book basis of oil and gas properties in excess of tax basis		(77,690	)		—
Unrealized gain on derivatives		—			(14,144	)
Other		(467	)		(787	)
Total Deferred Tax Liabilities	$	(78,157	)	$	(14,931	)

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. 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 ending 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. Therefore, an income tax benefit of approximately $1.3 million was recognized as of January 1, 2016 through a cumulative adjustment to retained earnings. As the deferred tax asset generated by the cumulative effect adjustment was subject to a 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, 2016, 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 $212.0 million for deferred tax assets for which the company may be unable to realize the tax benefit. For the year ended December 31, 2015, 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 $148.2 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, 2016, we had available unused gross federal net operating loss carryforwards of $152.2 million and gross state net operating loss carryforwards of $416.5 million that may be applied against future taxable income that expire from 2023 through 2036. 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, 2016, 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, 2016 and 2015.

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, 2011.

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, 2016, we excluded stock options to purchase 1.2 million shares of our common stock due to our Net Loss from Continuing Operations. For each of the years ended December 31, 2015 and 2014, we excluded stock options to purchase 0.4 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2016, 2015 and 2014, we excluded performance-based restricted stock of 0.6 million shares, 1.1 million shares and 0.8 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, 2016 and 2015, we excluded the assumed conversion of preferred stock equating to approximately 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):

	Year Ended December 31,			Year Ended December 31,			Year Ended December 31,
(in thousands, except per share amounts)	2016			2015			2014
Numerator:
Net Income (Loss) From Continuing Operations	$	(197,637	)	$	(352,782	)	$	16,511
Net Income (Loss) From Discontinued Operations, Less Noncontrolling Interests		20,922			(10,496	)		(63,200	)
Less: Preferred Stock Dividends		(5,091	)		(9,660	)		(2,335	)
Effect of Preferred Stock Conversions		72,984			—			—
Net Loss Attributable to Common Shareholders	$	(108,822	)	$	(372,938	)	$	(49,024	)
Denominator:
Weighted Average Common Shares Outstanding - Basic		79,256			54,392			53,150
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		79,256			54,392			53,150
Earnings per Common Share Attributable to Rex Energy Common Shareholders(a):
Basic — Net Income (Loss) From Continuing Operations	$	(1.63	)	$	(6.66	)	$	0.27
— Net Income (Loss) From Discontinued Operations		0.26			(0.19	)		(1.19	)
— Net Loss Attributable to Rex Energy Common Shareholders	$	(1.37	)	$	(6.85	)	$	(0.92	)
Diluted — Net Income (Loss) From Continuing Operations	$	(1.63	)	$	(6.66	)	$	0.27
— Net Income (Loss) From Discontinued Operations		0.26			(0.19	)		(1.19	)
— Net Loss Attributable to Rex Energy Common Shareholders	$	(1.37	)	$	(6.85	)	$	(0.92	)

Our common stock is currently traded on The NASDAQ Capital Market under the trading symbol “REXX”. We have authorized capital stock of 200,000,000 shares of common stock and 100,000 shares of preferred stock. As of December 31, 2016 and 2015, we had 97,870,608 and 55,741,229 shares of common stock outstanding, respectively. During the year ended December 31, 2016, we issued approximately 8.4 million shares of our common stock in conjunction with the Exchange completed on March 31,

2016, and approximately 23.5 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, 2016 and 2015, 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 and 16,100, respectively. During the year ended December 31, 2016, 12,113 shares of Series A Preferred Stock were converted into an aggregate of approximately 9.3 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. No dividend was declared by our board of directors in 2016. As of December 31, 2016, accumulated dividends in arrears totaled $5.0 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. 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 555.56 shares of our common stock per share (5.5556 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, 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 attributable to three customers with the largest single purchaser accounting for $76.0 million, or 52.0%. For the year ended December 31, 2014, approximately $206.1 million, or 92.2%, of our commodity sales from continuing operations were derived from four customers, with the largest customer being responsible for approximately $96.4 million, or 43.1%, 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 and were suspended during 2016. Our contributions to the plan attributable to continuing operations were negligible for the year ended December 31, 2016 and were approximately $0.5 million and $0.5 million for the years ended December 31, 2015 and 2014, respectively.

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 5,979,470 shares under the Plan, with 2,385,791 and 1,144,297 still available as of December 31, 2016 and 2015, 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, 2016, we issued 888,922 options to purchase shares of our common stock to 34 employees. During the year ended December 31, 2015, we issued 80,000 options to purchase shares of our common stock to three employees.

	Number of Shares			Weighted-Average Exercise Price		Weighted-Average Remaining Term (in years)		Aggregate Intrinsic Value (in thousands)
Options outstanding December 31, 2013		449,087		$	10.85
Granted		—			—
Exercised		(46,526	)		11.09
Cancelled/Forfeited		—			—
Options outstanding December 31, 2014		402,561		$	10.82
Granted		80,000			4.48
Exercised		—			—
Cancelled/Forfeited		(38,889	)		11.23
Options Outstanding December 31, 2015		443,672		$	9.64
Granted		888,922			1.66
Exercised		—			—
Cancelled/Forfeited		(151,494	)		5.72
Options Outstanding December 31, 2016		1,181,100		$	4.14		4.8	$	—
Options Exercisable December 31, 2016		313,505		$	10.31		1.2	$	—

Stock-based compensation expense from continuing operations relating to stock options for the years ended December 31, 2016, and 2014 was $0.4 million and $0.1 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, 2016 and 2015. The intrinsic value of stock options exercised for the years ended December 31, 2014 was $0.3 million, respectively. The total tax benefit for the years ended December 31, 2016 and 2015 was negligible and for the year ended December 31, 2014 was approximately $0.1 million.

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, 2016 and 2015 are as follows:

A summary of the status of our issued and outstanding stock options as of December 31, 2016 is as follows:

		Outstanding				Exercisable
Exercise Price		Number Outstanding At 12/31/16		Weighted-Average Exercise Price		Number Exercisable At 12/31/16		Weighted-Average Exercise Price
$	0.97		37,500	$	0.97		—	$	—
$	1.69		753,428	$	1.69		—	$	—
$	4.05		40,000	$	4.05		—	$	—
$	4.90		40,000	$	4.90		3,333	$	4.90
$	5.04		46,041	$	5.04		46,041	$	5.04
$	9.50		75,000	$	9.50		75,000	$	9.50
$	9.99		129,583	$	9.99		129,583	$	9.99
$	10.42		29,548	$	10.42		29,548	$	10.42
$	22.34		30,000	$	22.34		30,000	$	22.34
			1,181,100	$	4.14		313,505	$	10.31

The weighted average remaining contractual term for options exercisable at December 31, 2016 was 1.2 years and the aggregate intrinsic value was negligible. The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2015 were 2.1 years and negligible, respectively. As of December 31, 2016, unrecognized compensation expense related to stock options was $0.3 million.

During the year ended December 31, 2016, the Compensation Committee issued 1,423,091 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. During the year ended December 31, 2015, the Compensation Committee issued 2,236,839 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2016 and 2015 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 Capital Market 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 and 2014 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 and 2014 were $2.56 and $10.15 per share, respectively. 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, 2016, 2015 and 2014 was $2.7 million, $5.8 million and $5.4 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 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of December 31, 2016, total unrecognized compensation cost related to the restricted common stock grants was approximately $1.6 million to be recognized over a weighted average of 1.4 years. The total fair value of restricted common stock awards that vested in 2016 was approximately $0.6 million as compared to $2.0 million for restricted common stock awards that vested in 2015.

A summary of the restricted stock activity for the years ended December 31, 2016, 2015 and 2014 is as follows:

For the years ended December 31, 2016, 2015 and 2014, we incurred impairment expense from continuing operations of approximately $74.6 million, $283.2 million and $20.2 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 $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. The impairments were identified through an analysis of market conditions and future development plans that were in existence 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 depressed estimated future commodity prices during the first half of 2016. 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, 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.

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 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 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.

During 2014, we recorded impairment expense of $20.2 million. Approximately $9.8 million of the impairment incurred during 2014 was attributable to proved properties and other fixed assets in the Appalachian Basin, including approximately $5.9 million of impairment for our salt water disposal well in Ohio. This was due to the regulatory and environmental climate and the uncertainty of future viability of the disposal well. Approximately $3.6 million of the remaining proved property impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the estimated future decrease in natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $10.4 million in unproved property impairments related to expiring leases 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 the years ended December 31, 2016, 2015 and 2014 ($ in thousands):

As of December 31, 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):

	2016		2015		2014
Consolidated Entities:
Acquisition of Properties
Proved	$	—	$	—	$	161
Unproved		6,671		27,933		165,655
Exploration Costs(a)		24,650		157,067		306,752
Development Costs(a)		11,166		17,336		35,996
Subtotal		42,487		202,336		508,564
Asset Retirement Obligations		1,927		2,739		1,792
Total Costs Incurred	$	44,414	$	205,075	$	510,356
Share of Equity Method Investments:
Acquisition of Properties
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration Costs		—		—		—
Development Costs(a)		793		824		438
Total	$	793	$	824	$	438

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, 2016, 2015 and 2014. 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, analogy to similar properties and volumetric calculations. 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, 2016, 2015 and 2014. 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 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.

Our revisions in 2014 included a negative adjustment of approximately 58.5 Bcfe related to PUD locations that were not developed within five years, negative revisions of 1.6 Bcfe related to commodity pricing, positive revisions of 17.6 Bcfe related to favorable operating expenses and positive technical revisions of 38.0 Bcfe. The negative revisions were related to PUD locations that were previously booked in our Butler County, Pennsylvania region. The positive technical revisions included 51.0 Bcfe in our Butler County, Pennsylvania area related to positive well performance which was partially offset by negative revisions related to well performance in our Warrior South prospect and our non-operated Westmoreland County, Pennsylvania area of approximately 15.5 Bcfe.

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, 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 Bcf of natural gas. During 2014, we had extensions, discoveries and other additions of 1.7 MMBOE of oil, 31.2 MMBOE of NGLs and 326.5 Bcf 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, 2016, 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 proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2016, 2015 and 2014 ($ 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):

	2016			2015			2014
Consolidated Entities (in thousands):
Revenues
Oil and Natural Gas Sales	$	139,017		$	138,749		$	225,629
Expenses
Production and Lease Operating Expense		104,699			93,892			69,547
Impairment Expense		74,619			283,244			20,225
Exploration Expense		2,178			2,617			6,813
Depletion, Depreciation, Amortization and Accretion		62,874			85,844			65,817
Total Costs		244,370			465,597			162,402
Pre-Tax Operating Income (Loss)		(105,353	)		(326,848	)		63,227
Income Tax Expense (a)		(1,317	)		(5,687	)		(30,602	)
Results of Operations for Oil and Gas Producing Activities	$	(106,670	)	$	(332,535	)	$	32,625
Share of Equity Method Investments (in thousands):
Expenses
Depletion, Depreciation, Amortization and Accretion	$	813		$	812		$	805
Total Costs		813			812			805
Pre-Tax Operating Loss		(813	)		(812	)		(805	)
Income Tax (Expense) Benefit (a)		(10	)		(14	)		390
Results of Operations for Oil and Gas Producing Activities	$	(823	)	$	(826	)	$	(415	)
Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities	$	(107,493	)	$	(333,361	)	$	32,210

In September 2006, the United States Department of Justice (“DOJ”), the EPA and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) through our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, we entered a consent decree to resolve the enforcement action. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. It also required us to implement a Directed Inspection and Maintenance Plan, and to annually reassess such plan. The consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.

In 2010 and again in 2014, we proposed and the EPA, DOJ and Illinois EPA approved revisions to the Directed Inspection and Maintenance Plan. There were no material changes to the Directed Inspection and Maintenance Plan in 2015 or through September 30, 2016, and we were compliant with all reporting requirements for those periods.

In August 2016, we sold all of our assets in the Illinois Basin (see Note 4 Discontinued Operations/Assets Held for Sale ), including all assets that were subject to and covered under the consent decree. We notified the EPA, DOJ and Illinois EPA of the transaction as required by the consent decree and prepared and submitted all necessary reports for the three month-period ending September 30, 2016. As the consent decree relates specifically to a subset of the assets included in the sale of the Illinois Basin assets, all future responsibility for compliance with the terms of the consent decree transferred to the new owner from and after the closing of the sale transaction.

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 those 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. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 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 Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte 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, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated.

In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case. In July 2015, the trial court denied plaintiffs’ motion for class certification. Plaintiffs served notice of their appeal of that decision in August 2015 and filed the appeal in September 2015. In June 2016, we and the plaintiffs each presented our arguments on the appeal before a three-judge panel of the Pennsylvania Superior Court. In January 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. We promptly filed an application with the Pennsylvania Superior Court for rehearing of the arguments en banc. In the event the Superior Court does not agree to rehear the case, we will evaluate our alternatives, including a potential application for allowance to appeal to the Pennsylvania Supreme Court.

We continue to vigorously defend against each of 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, if any.

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			25,139			9,563			29,276
Other Costs and Expenses		67,696			59,037			40,953			94,349
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	$	(0.98	)	$	0.24		$	(0.19	)	$	(0.78	)
Basic — Discontinued Operations		(0.13	)		(0.02	)		0.24			0.08
Basic — Net Income (Loss)	$	(1.11	)	$	0.22		$	0.05		$	(0.69	)
Basic — Weighted Average Shares Outstanding		56,003			71,804			90,803			97,398
Diluted — Continuing Operations	$	(0.98	)	$	0.24		$	(0.19	)	$	(0.78	)
Diluted — Discontinued Operations		(0.13	)		(0.02	)		0.24			0.08
Diluted — Net Income (Loss)	$	(1.11	)	$	0.22		$	0.05		$	(0.69	)
Diluted — Weighted Average Shares Outstanding		56,003			71,804			90,803			97,398

	2015
	March			June			September			December
Revenues	$	45,934		$	35,784		$	29,656		$	27,375
Impairment Expense		6,848			117,839			85,193			73,364
Other Costs and Expenses		54,079			69,287			33,354			51,567
Net Loss From Continuing Operations		(14,993	)		(151,342	)		(88,891	)		(97,556	)
Net Loss From Discontinued Operations, Net of Income Taxes		(1,524	)		(461	)		(5,785	)		(481	)
Net Loss		(16,517	)		(151,803	)		(94,676	)		(98,037	)
Net Income (Loss) Attributable to Noncontrolling Interests		1,297			949			(1	)		—
Net Loss Attributable to Rex Energy		(17,814	)		(152,752	)		(94,675	)		(98,037	)
Preferred Stock Dividends		(2,415	)		(2,415	)		(2,415	)		(2,415	)
Net Loss Attributable to Common Shareholders	$	(20,229	)	$	(155,167	)	$	(97,090	)	$	(100,452	)
Loss per Common Share Attributable to Rex Energy Common Shareholders:
Basic — Continuing Operations	$	(0.32	)	$	(2.84	)	$	(1.69	)	$	(1.84	)
Basic — Discontinued Operations		(0.05	)		(0.03	)		(0.11	)		(0.01	)
Basic — Net Loss	$	(0.37	)	$	(2.87	)	$	(1.80	)	$	(1.85	)
Basic — Weighted Average Shares Outstanding		54,370			54,118			53,936			54,342
Diluted — Continuing Operations	$	(0.32	)	$	(2.84	)	$	(1.69	)	$	(1.84	)
Diluted — Discontinued Operations		(0.05	)		(0.03	)		(0.11	)		(0	)
Diluted — Net Loss	$	(0.37	)	$	(2.87	)	$	(1.80	)	$	(1.85	)
Diluted — Weighted Average Shares Outstanding		54,370			54,118			53,936			54,342

As of December 31, 2016, we had $601.2 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, 2016:

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, 2016, 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, 2016 and 2015, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2016.

	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		650			—			1,223			—			1,873
Inventory, Prepaid Expenses and Other		2,521			—			25			—			2,546
Total Current Assets		29,474			—			4,301			—			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
Other Assets		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		500			—			1,712			—			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
Senior Secured Line of Credit, Net of Issuance Costs		—			—			113,785			—			113,785
Senior Notes, Net of Issuance Costs and Deferred Gain on Exchanges		—			—			641,762			—			641,762
Discount on Senior Notes – Net		—			—			(3,601	)		—			(3,601	)
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		—			—			95			—			95
Additional Paid-In Capital		177,144			—			650,584			(177,144	)		650,584
Accumulated Earnings (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
INCOME (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		0
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) Benefit		(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 INCOME (LOSS)		(146,290	)		(54	)		(176,715	)		146,344		(176,715	)
Preferred Stock Dividends		—			—			(5,091	)		—		(5,091	)
Effect of Preferred Stock Conversions		—			—			72,984			—		72,984
NET INCOME (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 Income (Loss)	$	(146,290	)	$	(54	)	$	(176,715	)	$	146,344		$	(176,715	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Non-Cash Expenses (Income)		(212	)		3			24,333			—			24,124
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
Dry Hole Expense		905			—			—			—			905
Gain on Extinguishment of Debt		—			—			(24,627	)		—			(24,627	)
(Gain) Loss on Sale of Assets		(34,697	)		46			—			—			(34,651	)
Impairment Expense		78,160			2			78,162			(78,162	)		78,162
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		(1,950	)		—			—			—			(1,950	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(3,946	)		(806	)		(67,834	)		68,182			(4,404	)
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		3,628			(94	)		64,648			(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 (USED IN) INVESTING ACTIVITIES		7,379			806			64,648			(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	)
Dividends Paid on Preferred Stock														—
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(828	)		—			3,187			—			2,359
NET (DECREASE) 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
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,089		$	—	$	2		$	—		$	1,091
Accounts Receivable		17,225			—		49			—			17,274
Taxes Receivable		—			—		18			—			18
Short-Term Derivative Instruments		34,260			—		—			—			34,260
Assets Held for Sale		52,111			1,040		—			—			53,151
Inventory, Prepaid Expenses and Other		3,034			—		25			—			3,059
Total Current Assets		107,719			1,040		94			—			108,853
Property and Equipment (Successful Efforts Method)
Evaluated Oil and Gas Properties		950,062			—		—			(6,970	)		943,092
Unevaluated Oil and Gas Properties		262,992			—		—			—			262,992
Other Property and Equipment		20,363			—		—			—			20,363
Wells and Facilities in Progress		141,370			—		—			(270	)		141,100
Pipelines		16,161			—		—			(2,137	)		14,024
Total Property and Equipment		1,390,948			—		—			(9,377	)		1,381,571
Less: Accumulated Depreciation, Depletion and Amortization		(434,046	)		—		—			3,518			(430,528	)
Net Property and Equipment		956,902			—		—			(5,859	)		951,043
Deferred Financing Costs and Other Assets—Net		2,501			—		—			—			2,501
Intercompany Receivables		—			—		1,070,548			(1,070,548	)		—
Investment in Subsidiaries – Net		(1,907	)		—		243,331			(241,424	)		—
Long-Term Derivative Instruments		9,534			—		—			—			9,534
Total Assets	$	1,074,749		$	1,040	$	1,313,973		$	(1,317,831	)	$	1,071,931
LIABILITIES AND EQUITY
Current Liabilities
Accounts Payable	$	36,785		$	—	$	—		$	—		$	36,785
Current Maturities of Long-Term Debt		402			—		—			—			402
Accrued Liabilities		28,883			—		11,725			—			40,608
Short-Term Derivative Instruments		2,486			—		—			—			2,486
Liabilities Related to Assets Held For Sale		36,289			31		—			—			36,320
Total Current Liabilities		104,845			31		11,725			—			116,601
Long-Term Derivative Instruments		5,556			—		—			—			5,556
Senior Secured Line of Credit and Other Long-Term Debt, Net of Issuance Costs		18			—		109,368			—			109,386
Senior Notes, Net of Issuance Costs		—			—		663,089			—			663,089
Premium on Senior Notes – Net		—			—		2,344			—			2,344
Other Deposits and Liabilities		3,156			—		—			—			3,156
Future Abandonment Cost		11,159			409		—			—			11,568
Intercompany Payables		1,070,095			453		—			(1,070,548	)		—
Total Liabilities		1,194,829			893		786,526			(1,070,548	)		911,700
Stockholders’ Equity
Preferred Stock		—			—		1			—			1
Common Stock		—			—		54			—			54
Additional Paid-In Capital		177,143			—		619,777			(173,057	)		623,863
Accumulated Earnings (Deficit)		(297,223	)		147		(92,385	)		(74,226	)		(463,687	)
Total Stockholders’ Equity		(120,080	)		147		527,447			(247,283	)		160,231
Total Liabilities and Stockholders’ Equity	$	1,074,749		$	1,040	$	1,313,973		$	(1,317,831	)	$	1,071,931

	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
INCOME (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		0
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 Benefit		(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 Tax		(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 by Operating Activities
Loss on Equity Method Investments		411			—			—			—			411
Non-Cash Expenses (Income)		(201	)		(334	)		8,184			—			7,649
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
Dry Hole Expense		199			136			—			(5	)		330
Gain on Sale of Assets		(477	)		(44	)		—			—			(521	)
Gain on Sale of Water Solutions		—			—			(57,778	)		—			(57,778	)
Impairment Expense		345,892			1,396			345,892			(347,405	)		345,775
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 BY (USED IN) OPERATING ACTIVITIES		103,325			36,717			(67,034	)		(42,123	)		30,885
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		96,763			(37,424	)		(100,298	)		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 BY (USED IN) INVESTING ACTIVITIES		(119,215	)		(44,956	)		(33,398	)		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	)
Distributions by the Partners of Consolidated Subsidiary		—			(830	)		—			—			(830	)
Dividends Paid on Preferred Stock		—			—			(9,660	)		—			(9,660	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(999	)		8,126			100,429			—			107,556
NET (DECREASE) IN CASH		(16,889	)		(113	)		(3	)		0			(17,005	)
CASH – BEGINNING		17,978			113			5			—			18,096
CASH - ENDING	$	1,089		$	0		$	2		$	0		$	1,091

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations		Consolidated Balance
OPERATING REVENUE
Natural Gas, NGL and Condensate Sales	$	225,511		$	—		$	—		$	—	$	225,511
Other Revenue		118			—			—			—		118
TOTAL OPERATING REVENUE		225,629			—			—			—		225,629
OPERATING EXPENSES
Production and Lease Operating Expense		69,547			—			—			—		69,547
General and Administrative Expense		26,105			75			5,737			—		31,917
Loss on Disposal of Assets		218			—			—			—		218
Impairment Expense		14,269			5,956			—			—		20,225
Exploration Expense		6,813			—			—			—		6,813
Depreciation, Depletion, Amortization and Accretion		65,816			1			—			—		65,817
Other Operating Expense		312			—			—			—		312
TOTAL OPERATING EXPENSES		183,080			6,032			5,737			—		194,849
INCOME (LOSS) FROM OPERATIONS		42,549			(6,032	)		(5,737	)		—		30,780
OTHER INCOME (EXPENSE)
Interest Expense		(110	)		—			(36,835	)		—		(36,945	)
Gain on Derivatives, Net		37,359			—			1,517			—		38,876
Other Income (Expense)		73			—			—			—		73
Loss From Equity Method Investments		(813	)		—			—			—		(813	)
Income (Loss) From Equity in Consolidated Subsidiaries		(3,131	)		3,131			(25,250	)		25,250		—
TOTAL OTHER INCOME (EXPENSE)		33,378			3,131			(60,568	)		25,250		1,191
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX		75,927			(2,901	)		(66,305	)		25,250		31,971
Income Tax (Expense) Benefit		(38,230	)		2,917			19,853			—		(15,460	)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		37,697			16			(46,452	)		25,250		16,511
Income (Loss) From Discontinued Operations, Net of Income Taxes		(63,582	)		4,658			(237	)		—		(59,161	)
NET INCOME (LOSS)		(25,885	)		4,674			(46,689	)		25,250		(42,650	)
Net Income Attributable to Noncontrolling Interests of Discontinued Operations		—			4,039			—			—		4,039
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY	$	(25,885	)	$	635		$	(46,689	)	$	25,250	$	(46,689	)
Preferred Stock Dividends		—			—			(2,335	)		—		(2,335	)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$	(25,885	)	$	635		$	(49,024	)	$	25,250	$	(49,024	)

	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Rex Energy Corporation (Note Issuer)			Eliminations			Consolidated Balance
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss)	$	(25,885	)	$	4,674		$	(46,689	)	$	25,250		$	(42,650	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities
Loss on Equity Method Investments		813			—			—			—			813
Non-Cash Expenses (Income)		(273	)		278			6,784			—			6,789
Depreciation, Depletion, Amortization and Accretion		94,643			4,217			—			(689	)		98,171
Deferred Income Tax Benefit		(9,928	)		(1,649	)		(14,415	)		—			(25,992	)
Gain on Derivatives		(37,359	)		—			(1,517	)		—			(38,876	)
Cash Settlements of Derivatives		5,969			—			1,312			—			7,281
Dry Hole Expense		3,797			267			—			—			4,064
(Gain) Loss on Sale of Assets		644			(55	)		—			—			589
Impairment Expense		126,662			6,022			—			—			132,684
Changes in operating assets and liabilities
Accounts Receivable		(11,450	)		(6,090	)		4,686			(766	)		(13,620	)
Inventory, Prepaid Expenses and Other Assets		(1,283	)		(74	)		(2	)		—			(1,359	)
Accounts Payable and Accrued Liabilities		23,768			3,488			9,252			766			37,274
Other Assets and Liabilities		(2,127	)		(335	)		—			—			(2,462	)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		167,992			10,743			(40,589	)		24,561			162,706
CASH FLOWS FROM INVESTING ACTIVITIES
Intercompany Loans to Subsidiaries		401,412			(756	)		(371,768	)		(28,888	)		—
Proceeds from Joint Venture Acreage Management		263			—			—			—			263
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets		254			292			—			—			546
Acquisitions of Undeveloped Acreage		(168,713	)		(710	)		—			—			(169,423	)
Capital Expenditures for Development of Oil and Gas Properties and Equipment		(382,889	)		(12,861	)		—			4,328			(391,422	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(149,673	)		(14,035	)		(371,768	)		(24,560	)		(560,036	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-Term Debt and Lines of Credit		—			38,895			171,000			—			209,895
Repayments of Long-Term Debt and Lines of Credit		—			(33,152	)		(230,000	)		—			(263,152	)
Repayments of Loans and Other Notes Payable		(1,727	)		(994	)		—			—			(2,721	)
Proceeds from Senior Notes, net of Discounts and Premiums		—			—			325,000			—			325,000
Debt Issuance Costs		—			(8	)		(6,816	)		—			(6,824	)
Proceeds from Issuance of Preferred Stock, Net		—			—			154,988			—			154,988
Proceeds from the Exercise of Stock Options		—			—			515			—			515
Purchase of Non-Controlling Interests		—			(1,840	)		—			—			(1,840	)
Dividends Paid on Preferred Stock		—			—			(2,335	)		—			(2,335	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,727	)		2,901			412,352			—			413,526
NET INCREASE (DECREASE) IN CASH		16,592			(391	)		(5	)		—			16,196
CASH – BEGINNING		1,386			504			10			—			1,900
CASH - ENDING	$	17,978		$	113		$	5		$	—		$	18,096

On January 11, 2017, we, together with MFC Drilling, Inc. (“MFC”), ABARTA Oil & Gas Co., Inc. (“ABARTA”) (Rex, MFC, and ABARTA, together, the “Sellers”) sold substantially all of our jointly owned oil and gas interests in Noble, Guernsey, and Belmont Counties, Ohio, to Antero Resources Corporation (“Antero”). These interests comprised Rex’s 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 Rex, 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 will be held in escrow and will be released in January 2018, net of post-closing adjustments. Net book value of the assets at December 31, 2016 was approximately $27.9 million. The sale assets included 14 gross wells with associated production of 15 Mmcfe/d, with 9 Mmcfe/d net to Rex, and approximately 6,200 gross acres, with 4,100 acres net to Rex. This acreage was considered non-core to Rex. We used the proceeds from the transaction to pay down our revolving line of credit and for general corporate purposes.

Effective as of January 11, 2017, the company entered into a Twelfth Amendment (the “Twelfth Amendment”) to the Amended and Restated Credit Agreement dated as of March 27, 2013 (as amended, modified or supplemented, the “Credit Agreement”) among the company; each of the guarantors; Royal Bank of Canada, as administrative agent for the lenders; and the other lenders signatory thereto.

The Twelfth Amendment amended certain provisions of the Credit Agreement to, among other things, (i) provide that there was to be no adjustment to the borrowing base upon the completion of the sale of assets in the Warrior South Area, with the effect that the borrowing base remained at $190,000,000 pending the next redetermination; and (ii) reduce the commitment level for letters of credit within the Credit Agreement to the greater of (a) forty million dollars ($40,000,000) and (b) (x) fifty million dollars ($50,000,000) minus (y) an amount equal to the portion of the face amount of all Surety LCs (as defined in the Credit Agreement) reduced or terminated on or after the Twelfth Amendment Effective Date in excess of $10,000,000 in the aggregate.

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, 2016, 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, 2016 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, 2016. Management reviewed the results of their assessment with our Audit Committee. The effectiveness of our internal control over financial reporting as of December 31, 2016 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 and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Rex Energy Corporation’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’s Annual Report on Internal Control over Financial Reporting within Item 9A. Controls and Procedures Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Rex Energy Corporation and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in noncontrolling interests and stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016, and our report dated March 15, 2017 expressed an unqualified opinion on those consolidated financial statements.

The information required by this item is incorporated by reference to such information as set forth in our definitive Proxy Statement (the “2017 Proxy Statement”) for our 2017 annual meeting of stockholders. The 2017 Proxy statement will be filed with the SEC not later than 120 days subsequent to December 31, 2016.

The information required by this item is incorporated herein by reference to the 2017 Proxy Statement for the 2017 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2016.

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.

PART I
Item 1.	Business	6
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	33
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	38
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	39
Item 6.	Selected Financial Data	41
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	71
Item 8.	Financial Statements and Supplementary Data	73
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	133
Item 9A.	Controls and Procedures	133
Item 9B.	Other Information	135
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	135
Item 11.	Executive Compensation	135
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	135
Item 13.	Certain Relationships and Related Transactions and Director Independence	135
Item 14.	Principal Accountant Fees and Services	135
PART IV
Item 15.	Exhibits and Financial Statement Schedules	136
Item 16.	Form 10-K Summary	143
GLOSSARY SIGNATURES

	For the Years Ended December 31, ($ in thousands)
	2017 (Estimated)		2016 (Actual)
Capital Expenditures
Drilling & Completion	$	73,000	$	24,021
Midstream		1,500		2,317
Other Field Assets		2,500		1,564
Other Corporate Expenditures		500		273
Total Capital Expenditures¹	$	77,500	$	28,175

	Net Reserves
Category	Condensate (Barrels)		NGL (Barrels)		Gas (Mcf)
Proved Developed		1,859,200		44,527,300		365,909,000
Proved Developed Non-Producing		6,700		297,100		1,732,300
Proved Undeveloped		—		—		—
Total Proved		1,865,900		44,824,400		367,641,300

	2016		2015		2014
Description
Proved Developed Reserves
Oil and Condensate (Bbls)		1,865,900		1,544,000		1,310,000
Natural Gas (Mcf)		367,641,300		389,754,400		365,673,300
NGLs (Bbls)		44,824,400		37,941,900		29,215,000
Proved Undeveloped Reserves
Oil and Condensate (Bbls)		—		372,500		1,314,900
Natural Gas (Mcf)		—		16,708,400		473,511,800
NGLs (Bbls)		—		2,404,700		44,037,500
Total Estimated Proved Reserves (Mcfe)^{1, 2}		647,783,100		660,041,400		1,294,449,500
Standardized Measure (millions)³	$	165.6	$	255.6	$	1,025.4
PV-10 Value (millions)³	$	175.5	$	272.7	$	1,039.4

Proved Undeveloped Reserves (Mcfe)	For the Year Ended December 31, 2016
Beginning proved undeveloped reserves		33,371,600
Sales of Reserves in Place		—
Undeveloped reserves converted to developed		(33,371,600	)
Revisions		—
Extensions and discoveries		—
Ending proved undeveloped reserves		—

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

	Production and Revenue For the Years Ended December 31, ($ in thousands)
	2016		2015		2014
Revenue	$	139,000	$	138,707	$	225,511
Condensate Production (Bbls)¹		360,384		402,867		334,944
Natural Gas Production (Mcf)		44,684,571		44,606,753		37,011,177
C3+ NGL Production (Bbls)		1,996,075		2,026,321		1,531,131
Ethane (Bbls)		2,111,321		1,319,582		551,315
Total Production (Mcfe)²		71,491,251		67,099,373		51,515,517
Condensate Average Sales Price	$	37.08	$	34.92	$	74.84
Natural Gas Average Sales Price	$	1.64	$	1.86	$	3.42
C3+ NGL Average Sales Price	$	17.97	$	16.18	$	45.47
Ethane Average Sales Price	$	7.81	$	6.60	$	7.83
Average Production Cost per Mcfe³	$	1.45	$	1.39	$	1.33

	Undeveloped Acreage¹				Developed Acreage²				Total Acreage				Producing Gas Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Appalachian Basin
Pennsylvania		80,161		72,468		158,258		103,324		238,419		175,792		515		187
Ohio		3,538		3,100		17,677		14,655		21,215		17,755		44		32
Total		83,699		75,568		175,935		117,979		259,634		193,547		559		219

	Expiring Acreage
	Gross		Net
Year Ending December 31,
2017		55,394		44,905
2018		26,671		18,978
2019		13,733		9,113
2020		819		607
2021		1,845		218
Thereafter		382		323
Total		98,844		74,144

2016	High		Low
First Quarter	$	2.43	$	0.49
Second Quarter	$	1.44	$	0.54
Third Quarter	$	0.74	$	0.45
Fourth Quarter	$	0.64	$	0.23

2015	High		Low
First Quarter	$	5.27	$	2.47
Second Quarter	$	5.74	$	3.62
Third Quarter	$	5.60	$	1.85
Fourth Quarter	$	3.34	$	0.89

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c)
Equity compensation plans approved by stockholders		1,181,100	$	4.14		2,385,791
Equity compensation plans not approved by stockholders		—	$	—		—

	Rex Energy		DJ U.S. E&P Index		S&P
December 31, 2011	$	100	$	100	$	100
December 31, 2012	$	88	$	105	$	113
December 31, 2013	$	134	$	136	$	147
December 31, 2014	$	35	$	120	$	164
December 31, 2015	$	7	$	90	$	163
December 31, 2016	$	3	$	110	$	178

Calendar Quarter Ending	West Texas Intermediate Average Price per Bbl
3/31/2017	$	56.25
6/30/2017	$	58.25
9/30/2017	$	60.25
12/31/2017	$	60.75
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,
	2016		% of Total			2015		% of Total			2014		% of Total
Sources of Revenue ($ in thousands)
Revenue from Condensate Sales	$	13,364		9.6	%	$	14,068		10.1	%	$	25,067		11.1	%
Revenue from Natural Gas Sales		73,275		52.7	%		83,140		59.9	%		126,500		56.1	%
Revenue from C3+ NGL Sales		35,877		25.8	%		32,789		23.6	%		69,626		30.9	%
Revenue from Ethane Sales		16,484		11.9	%		8,710		6.3	%		4,317		1.9	%
Other		17		0.0	%		42		0.0	%		118		0.1	%
Total	$	139,017		100.0	%	$	138,749		100.0	%	$	225,628		100.0	%

	Performance Measurements
	For the Years Ended December 31,
	2016		2015		2014
EBITDAX ($ in thousands)	$	45,272	$	78,787	$	136,422
Lease Operating Expense per Mcfe	$	1.46	$	1.40	$	1.35
Total Estimated Proved Reserves (Bcfe)		647.8		680.4		1,336.8
General and Administrative Expenses per Mcfe	$	0.29	$	0.40	$	0.62

	<$2.25(a)		$2.26 - $2.99(a)		$3.00 - $4.99(a)		$5.00 - $5.99(a)		>$5.99(a)
Year One	$	40,200	$	45,300	$	50,300	$	55,300	$	60,400
Year Two	$	30,200	$	35,200	$	40,200	$	45,300	$	55,300
Year Three	$	25,200	$	30,200	$	30,200	$	40,200	$	50,300
Year 4 – 10	$	10,100	$	15,100	$	20,100	$	20,100	$	20,100
Year 11 – 15	$	5,000	$	5,000	$	10,100	$	10,100	$	10,100

		Page
Report of Independent Registered Public Accounting Firm		74
Consolidated Balance Sheets at December 31, 2016 and 2015		75
Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014		76
Consolidated Statements of Changes in Noncontrolling Interests and Stockholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014		77
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014		78
Notes to the Consolidated Financial Statements		79

	December 31, 2016 (in thousands)			December 31, 2015 (in thousands)
Beginning Balance	$	11,934		$	8,061
Asset Retirement Obligation Incurred		575			1,063
Asset Retirement Obligation Settled		(671	)		(449	)
Asset Retirement Obligation Cancelled or Sold Properties		(4,876	)		(136	)
Asset Retirement Obligation Revision of Estimated Obligation		1,918			2,428
Asset Retirement Obligation Accretion Expense		985			967
Total Future Abandonment Costs	$	9,865		$	11,934

	As of December 31, 2015
	Range (price per Mcf)	Weighted Average (price per Mcf)			Fair Value (in thousands)
Natural Gas Basis Differential Forward Curve - Dominion South	($0.27) - ($1.08)	$	(0.74	)	$	(5,468	)
Natural Gas Basis Differential Forward Curve - Texas Gas	($0.05) - ($0.17)	$	(0.12	)	$	(38	)

				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	)	$	—

				Fair Value Measurements at December 31, 2015 Using:
($ in Thousands)	Total Carrying Value as of December 31, 2015			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives	$	35,752		$	—	$	41,258		$	(5,506	)

($ in Thousands)	Year Ended December 31, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Income (Loss) from continuing operations before noncontrolling interests and income taxes	$	(195,201	)	$	(346,752	)	$	31,971
Statutory U.S. income tax rate		35.0	%		35.0	%		35.0	%
Tax expense recognized using statutory U.S. income tax rate	$	(68,320	)	$	(121,363	)	$	11,190
State income taxes, net of federal income tax benefit		(3,632	)		(17,137	)		1,626
Change in estimated future state rates		(400	)		(212	)		(743	)
Permanent differences		2,264			1,784			1,014
Change in valuation allowances		72,784			143,566			2,450
Other		(260	)		(608	)		(77	)
Total income tax expense	$	2,436		$	6,030		$	15,460
Effective income tax rate		-1.25	%		-1.74	%		48.4	%

Year of Expiration	Net Operating Loss Carryforwards (in thousands)
2023		1
2024		—
2025		—
2026		455
2027		968
2028		—
2029		—
2030		—
2031		1,522
2032		—
2033		12,653
2034		6,241
2035		45,296
2036		12,395
Total		79,531

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			Year Ended December 31, 2014
Expected Dividend Yield		0.0	%		0.0	%
Risk-Free Interest Rate		1.0	%		0.8	%
Expected Volatility – Rex Energy		58.6	%		50.4	%
Expected Volatility – Peer Group	29.8%-85.0%			28.4%-65.7%
Market Index		35.6	%		35.3	%
Expected Life	Three Years			Three Years

	Number of Shares			Weighted-Average Grant Date Fair Value
Restricted stock awards, as of January 1, 2014		2,172,639		$	14.16
Awards		131,610			8.76
Vested		(595,085	)		13.09
Forfeitures		(189,863	)		14.60
Restricted stock awards, as of December 31, 2014		1,519,301		$	14.05
Awards		2,236,839			3.35
Vested		(606,359	)		9.39
Forfeitures		(670,373	)		11.33
Restricted stock awards, as of December 31, 2015		2,479,408		$	6.27
Awards		1,423,091			0.91
Vested		(872,061	)		7.33
Forfeitures		(602,944	)		6.73
Restricted stock awards, as of December 31, 2016		2,427,494		$	2.63

	2016
	Oil (MBbls)			NGL (MBbls)			Natural Gas (MMcf)			(MMcf) Equivalents
Estimated Proved Reserves-Beginning of Period		5,317.1			40,346.6			406,462.8			680,445.0
Extensions, Discoveries and Additions		373.5			2,183.7			11,084.6			26,427.8
Revisions of Previous Estimates		323.9			8,262.0			7,629.3			59,144.7
Sales of Reserves		(3,788.1	)		(1,860.5	)		(12,917.7	)		(46,809.3	)
Production		(360.4	)		(4,107.4	)		(44,618.1	)		(71,424.9	)
Estimated Proved Reserves-End of Period		1,866.0			44,824.4			367,640.9			647,783.3

		Page
Index to Financial Statements		73

Report of Independent Registered Public Accounting Firms		74

Consolidated Balance Sheets at December 31, 2016 and 2015		75

Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014		76

Consolidated Statements of Changes in Noncontrolling Interests and Stockholder’s Equity (Deficit) for the Years Ended December 31, 2016, 2015 and 2014		77

Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014		78

Notes to the Consolidated Financial Statements		79

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				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).
2.3				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).
2.4				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).
2.5				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).
2.6				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).
2.7				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).
2.8				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).

2.9				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 8-K filed with the SEC on October 9, 2015).

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 8-K 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.
3.1				Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.2				Certificate of Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007).
3.3				Certificate of Designations, Preferences, Rights and Limitations of 6.00% Convertible Perpetual Preferred Stock, Series A, of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on August 18, 2014).
3.4				Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K as filed with the SEC on May 11, 2012).
3.5				Amendment to the Amended and Restated Bylaws of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K as filed with the SEC on August 18, 2014).
3.6*				Certificate of Amendment to Certificate of Incorporation of Rex Energy Corporation.
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				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).
4.3				Form of 8.875% Senior Notes due 2020 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on December 12, 2012, and incorporated herein by reference).
4.4				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).
4.5				Form of 6.250% Senior Notes due 2022 (included in Exhibit 4.1 to our Current Report on Form 8-K filed with the SEC on July 17, 2014, and incorporated herein by reference).
4.6				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).

4.7				Form of Depositary Receipt Representing the Depositary Shares (included as Exhibit A to Exhibit 4.7) (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on August 18, 2014).

4.8				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).

4.9				Form of 1.00%/8.00% Senior Secured Second Lien Note due 2020 (incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed with the SEC on March 31, 2016).

4.10				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).

4.11				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).


10.47+			Separation Agreement and Complete Release by and between Michael L. Hodges and Rex Operating Corp. dated January 1, 2015 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 11, 2015).

10.48			Seventh Amendment to Amended and Restated Credit Agreement effective as of December 16, 2014, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on May 11, 2015).

10.49+			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).

10.50+			Separation Agreement and Complete Release by and between Patrick M. McKinney and Rex Operating Corp. dated August 1, 2015 (incorporated by reference to Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on August 4, 2015).

10.51			Waiver to Amended and Restated Credit Agreement effective as of June 15, 2015, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q filed with the SEC on August 10, 2015).

10.52			Eighth Amendment to Amended and Restated Credit Agreement effective as of September 4, 2015, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the SEC on November 9, 2015).

10.53			Collateral Agreement, dated as of March 31, 2016, the Grantors named therein and Wilmington Savings Fund Society, FSB, as trustee (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on March 31, 2016).

10.54			Intercreditor Agreement, dated as of March 31, 2016, among Royal Bank of Canada, as First Lien RBL Agent, Wilmington Savings Fund Society, FSB, as Second Lien Agent, each permitted additional first lien representative, each permitted third lien representative, Rex Energy Corporation and the Subsidiaries named therein (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on March 31, 2016).

10.55			Ninth Amendment to Amended and Restated Credit Agreement effective as of February 3, 2016, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 10, 2016).

10.56			Tenth Amendment to Amended and Restated Credit Agreement effective as of March 14, 2016, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on May 10, 2016).

10.57			Eleventh Amendment to Amended and Restated Credit Agreement effective as of July 1, 2016, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the SEC on August 5, 2016).

10.58			Purchase and Sale Agreement dated June 14, 2016 by and among 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 as Seller, and Campbell Development Group, LLC as Purchaser (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on August 5, 2016).

10.59			Amendment No. 1 to Employment Agreement by and between Thomas C. Stabley, Rex Energy Corporation and Rex Energy Operating Corp., dated as of December 30, 2016 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 30, 2016).
12.1*			Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend.
21.1*			Subsidiaries of the Registrant.

				REX ENERGY CORPORATION
		By:		/s/ THOMAS C. STABLEY
				Thomas C. Stabley
				Chief Executive Officer

/s/ LANCE T. SHANER Lance T. Shaner	Chairman of the Board	March 15, 2017
/s/ THOMAS C. STABLEY Thomas C. Stabley	Chief Executive Officer and Director (Principal Executive Officer)	March 15, 2017
/s/ THOMAS G. RAJAN Thomas G. Rajan	Chief Financial Officer (Principal Financial Officer)	March 15, 2017
/s/ CURTIS J. WALKER	Chief Accounting Officer (Principal Accounting Officer)	March 15, 2017
Curtis J. Walker	Chief Accounting Officer (Principal Accounting Officer)	March 15, 2017
/s/ ERIC L. MATTSON Eric L. Mattson	Director	March 15, 2017
/s/ JOHN A. LOMBARDI John A. Lombardi	Director	March 15, 2017
/s/ JOHN J. ZAK John J. Zak	Director	March 15, 2017
/s/ JACK N. AYDIN	Director	March 15, 2017
Jack N. Aydin	Director	March 15, 2017