UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): February 3, 2016

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (814) 278-7267

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

Item 1.01 Entry into a Material Definitive Agreement.

On February 3, 2016, Rex Energy Corporation (the “Company”) entered into a Ninth Amendment to the Amended and Restated Credit Agreement (the “Ninth Amendment”) with the guarantors party thereto, Royal Bank of Canada, as administrative agent for the lenders, and the lenders signatory thereto, amending certain provisions of that certain Amended and Restated Credit Agreement, dated as of March 27, 2013 (as amended, modified or supplemented, the “Credit Agreement”) to, among other things, (i) decrease the Company’s borrowing base from $350 million to $200 million; (ii) permit the Company to issue new senior secured second lien Notes (the “New Notes”) in an amount up to $480 million inclusive of accrued and unpaid interest payable on the settlement date on the principal amount of any senior unsecured notes that are exchanged for New Notes in connection with an exchange offering; (iii) amend the calculation of the Company’s maximum 3.0x Ratio of Net Senior Secured Debt to EBITDAX to exclude undrawn letters of credit related to firm transportation contracts and the New Notes; (iv) increase the requirement for mortgages on oil and gas properties from 80% to 90%; and (v) increase the Company’s drawn pricing by 75 bps across the grid with a flat 50 bps undrawn fee.

The foregoing description of the Ninth Amendment does not purport to be complete and is qualified in its entirety by reference to the complete text of the Ninth Amendment. A copy of the Ninth Amendment will be filed with the Company’s Quarterly Report on Form 10-Q for the quarter ending March 31, 2016.

Item 2.02 Results of Operations and Financial Condition.

The Company provides an update on its core operations, production, hedging and liquidity under “Item 7.01 Regulation FD Disclosure” below. In addition, the Company has furnished the report of Netherland, Sewell & Associates, Inc. related to estimates of reserves and future revenue, as of December 31, 2015, to the Company’s interest in certain oil and gas properties located in the Appalachian and Illinois Basins of the United States.

In accordance with General Instruction B.2 of Form 8-K, the information under this heading, including the related Exhibit 99.1 attached hereto, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth in such a filing.

Item 7.01 Regulation FD Disclosure.

The Company provides the update below on its core operations, production, hedging and liquidity.

The financial information below with respect to the three months and year ended December 31, 2015 are unaudited estimates of the Company’s performance during such periods. Non-financial information, such as production and reserves information, is also unaudited. The Company’s audited financial statements as of and for the year ended December 31, 2015 will be included with the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 (the “2015 Annual Report”). The audited financial statements included in the 2015 Annual Report may vary materially from the unaudited estimated financial results provided below. In addition, estimates for the three months and year ended December 31, 2015 are not necessarily indicative of any future period.

Operating Results

For the year ended December 31, 2015, the Company’s production increased to 195.8 MMcfe per day, a 26.8% increase from the year ended December 31, 2014. During the fourth quarter of 2015, production decreased by approximately 5.1% to 186.1 MMcfe per day compared to 196.0 MMcfe per day during the fourth quarter of 2014. Production during the year ended December 31, 2015 was positively impacted by strong drilling results in the Appalachian Basin. Fourth quarter 2015 production decreased, however, because the Company allocated capital to developing its Moraine East project area. The Company has drilled 16 wells in this project area, 12 of which it has also completed. The Company anticipates placing these wells into service during the first quarter of 2016 when the necessary pipeline and infrastructure is expected to be completed.

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Operating revenues from continuing operations for the year ended December 31, 2015 are expected to be between $169.0 million and $174.0 million, as compared to operating revenues of $298.0 million for the year ended December 31, 2014. Commodity revenues, including settlements from derivatives, are expected to be between $224.0 million and $229.0 million for the year ended December 31, 2015, compared to approximately $303.8 million for the year ended December 31, 2014. Operating revenues from continuing operations for the fourth quarter of 2015 are expected to be between $32.0 million and $37.0 million, as compared to operating revenues of $70.2 million during the same period in 2014. Commodity revenues, including settlements from derivatives, for the fourth quarter of 2015 are expected to be between $48.0 million and $53.0 million as compared to $80.4 million for the same period in 2014. The decreases in operating and commodity revenues during 2015, as compared to 2014, were primarily attributable to substantially lower commodity prices, partially offset by higher production in our Appalachian region.

For the year ended December 31, 2015, the average realized prices for oil, natural gas, C3+ NGLs and ethane, including the effects of cash settled derivatives, totaled approximately $52.27 per barrel, $2.59 per Mcf, $21.19 per barrel and $6.81 per barrel, respectively. For the year ended December 31, 2014, the average realized prices for oil, natural gas, C3+ NGLs and ethane, including the effects of cash settled derivatives, totaled $86.33 per barrel, $3.46 per Mcf, $47.59 per barrel and $7.83 per barrel, respectively. For the fourth quarter of 2015, the average realized prices for oil, natural gas, C3+ NGLs and ethane, including the effects of cash settled derivatives, totaled approximately $49.84 per barrel, $2.34 per Mcf, $24.45 per barrel and $6.39 per barrel, respectively. For the fourth quarter of 2014, the average realized prices for oil, natural gas, C3+ NGLs and ethane, including the effects of cash settled derivatives, totaled $74.31 per barrel, $2.85 per Mcf, $43.01 per barrel and $7.97 per barrel, respectively.

Lease operating expense from continuing operations is expected to be between $117.0 and $122.0 million for the year ended December 31, 2015 as compared to $100.3 million for the year ended December 31, 2014. Lease operating expense from continuing operations for the fourth quarter of 2015 is expected to be between $26.0 million and $31.0 million as compared to $30.9 million for the same period in 2014.

Cash general and administrative expenses from continuing operations (“Cash G&A”), a non-GAAP measure reconciled herein under “Reconciliation of Non-GAAP Financial Measures”, are expected to be between $22.0 million and $23.0 million for the year ended December 31, 2015 as compared to $30.5 million for the year ended December 31, 2014. For the fourth quarter of 2015, the Company expects Cash G&A from continuing operations to be between $4.0 million and $5.0 million as compared to $7.5 million for the same period in 2014. The decrease in Cash G&A in 2015 as compared to 2014 was primarily due to cost reduction measures implemented by the Company in 2015. The Company expects that Cash G&A will further decline in 2016 in light of the depressed commodity price environment and continued focus on cost control measures.

The Company expects to record impairment expense for the year ended December 31, 2015 between $340.0 million to $350.0 million as compared to $132.6 million for the year ended December 31, 2014. For the fourth quarter of 2015, the Company expects to record impairment expense between $75.0 million and $85.0 million as compared to $132.6 million for the same period in 2014. The impairment expenses recorded in 2015 and 2014 were largely attributable to the depressed commodity price environment. The impairments were identified through an analysis of market conditions, available capital and future development plans with respect to the evaluated properties, each as they existed at the end of the relevant period, which indicated that the carrying value of the evaluated assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. The Company follows the successful efforts method of accounting and, therefore, its impairment tests are largely based on estimates of future commodity prices, changes in development and operating costs, taxes, operational efficiencies, changes in technology and access to capital, which makes predicting any future write-downs difficult and uncertain.

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Approximately 92% and 79% of the impairment expense recorded during the year ended December 31, 2015 and the fourth quarter of 2015, respectively, were related to project areas outside of the Butler Operating Area. Within the Butler Operated Area, the impairments that were recognized were primarily attributable to anticipated future lease expirations. To quantify the impact of continued low commodity prices or further declines in future prices, as of December 31, 2015, approximately 76% of the carrying value of the Company’s evaluated oil and natural gas properties were located in the Butler Operated Area. As of December 31, 2015, estimated future cash flows for these properties exceeded net book value by over 100%, indicating 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 the Company to experience a write-down with respect to these properties. The remaining evaluated properties that are outside of the Butler Operated Area are more sensitive to the current commodity price environment and could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated properties totaled between $125.0 million and $145.0 million.

For the year ended December 31, 2015, the Company expects net loss from continuing operations attributable to common shareholders to be between $365.0 million and $385.0 million as compared to a net loss from continuing operations attributable to common shareholders of $49.0 million during the year ended December 31, 2014. For the fourth quarter of 2015, the Company expects net loss from continuing operations attributable to common shareholders to be between $90.0 million and $110.0 million as compared to a net loss from continuing operations attributable to common shareholders of $71.7 million for the same period in 2014. The increases in net loss from continuing operations attributable to common shareholders during 2015, as compared to 2014, can be primarily attributed to lower commodity prices and lower production in the Illinois Basin.

For the year ended December 31, 2015, the Company expects its EBTIDAX from continuing operations, a non-GAAP measure, to be between 50% and 55% lower than full-year 2014 EBITDAX. EBITDAX from continuing operations for the fourth quarter of 2015 is expected to be between 58% and 63% lower than the fourth quarter of 2014. The anticipated decreases to EBITDAX from continuing operations were directly attributable to the downward pressure on commodity prices during 2015.

For the year ended December 31, 2015, the Company drilled or participated in the drilling of 39.0 gross (26.5 net) wells. The Company placed into sales 36.0 gross (16.1 net) wells and ended the year with 22.0 gross (16.4 net) wells in inventory that are awaiting completion or a pipeline connection. Of the wells drilled and placed into service during 2015, 34.0 gross (23.0 net) wells were drilled and 33.0 gross (13.6 net) wells were placed into service in the Appalachian Basin. All of the wells currently awaiting completion or pipeline connection are located in the Appalachian Basin.

The Company has reduced its cost to drill and complete a 5,000’ lateral in the Butler Operated Area by 9% to $4.8 million from the previously reported $5.3 million. In addition, the Company has reduced its cost to drill and complete a 6,000’ lateral in the Butler Operated Area by 10% to $5.3 million from the previously reported $5.9 million. In both cases, the reduced well costs are attributable to operational efficiencies and negotiated cost concessions from our drilling and completion service providers.

The table below summarizes certain data for the Company’s core operating areas at December 31, 2015:

During the fourth quarter of 2015, the Company added a third outlet for its ethane volumes by entering into a new sales agreement to sell 2,000 barrels per day of ethane produced in the Butler Operated Area via the Mariner East I pipeline project. The new Mariner East I arrangement supplements the previous

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ethane sales contracts for the ATEX and Mariner West pipelines, providing access to both domestic and international markets. As part of the new sales agreement, the Company will also sell a combined 3,000 barrels per day of propane and butane via the Mariner East II pipeline. The Company has also amended its agreements for production from the Warrior North project area to gain access to the Mariner East I pipeline for ethane volumes and to the midstream provider’s super system, which provides the Company the ability to sell residue gas to the premium Mid-West markets.

Reserves

Proved oil, natural gas and NGL reserves as of December 31, 2015 totaled approximately 680 Bcfe, a decrease of approximately 656 Bcfe, or 49%, from total proved reserves reported at year-end 2014. The proved reserves estimates as of December 31, 2015 were prepared by the Company’s independent reservoir engineers, Netherland, Sewell & Associates. PV-10, a non-GAAP measure reconciled herein under “Reconciliation of Non-GAAP Financial Measures”, was approximately $300.7 million for the year ended December 31, 2015, as compared to $1.2 billion for the year ended December 31, 2014.

The following table summarizes the Company’s changes in proved reserves between the period of December 31, 2014 and December 31, 2015 in Bcfe:

The following table summarizes the Company’s proved reserves and Finding and Development Costs as of December 31, 2014 and December 31, 2015:

Below is a reconciliation of changes in the Company’s proved reserves between December 31, 2014 and December 31, 2015. For reference, SEC pricing for the twelve months ended December 31, 2015 was the West Texas Intermediate posted price of $46.79 per barrel for oil and Henry Hub spot price of $2.587 per MMbtu for natural gas, adjusted for contractual agreements. SEC pricing for the twelve months ended December 31, 2014 was the West Texas Intermediate posted price of $91.48 per barrel for oil and Henry Hub spot price of $4.35 per MMbtu for natural gas, adjusted for contractual agreements.

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The following table summarizes the Company’s total proved reserves by region as of December 31, 2015:

Below is a summary of the number of net wells by proved reserve classification for the Company’s Appalachian Basin as of December 31, 2015:

Included in the Company’s 2014 reserve report were 197 proved undeveloped locations scheduled for development between 2015 and 2021, of which 20 were scheduled for development in 2015. During 2015, 11 of the 197 PUD locations were completed and converted to proved developed producing reserves. This equated to a conversion of approximately 5.6% of the Company’s proved undeveloped locations to proved developed producing reserves. The depressed commodity price environment has significantly impacted our development plans, leading to the removal of the majority of the Company’s remaining proved undeveloped locations from the 2015 reserves report. At all times, development plans and changes thereto are based on a comprehensive analysis of what the Company believes to be the most relevant factors in determining such plans. While the Company does take into

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consideration NYMEX strip pricing at year-end when scheduling future development, for the December 31, 2015 reserve report, the Company 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, the Company made decisions about initial scheduling and subsequent rescheduling of its development plans. The ultimate objective for every such evaluation and analysis is to align the Company’s development and capital expenditures plans to focus on projects that management believes will provide the greatest returns.

Anticipated capital expenditures related to proved undeveloped locations of approximately $19.0 million is significantly lower than in prior years. This reduction is largely due to the current commodity price environment and the related impact on the economic viability of our proved undeveloped locations from 2014 and prior years, as described above. The Company has evaluated the impact on its proved undeveloped reserves based on spot commodity prices of $32.53 per barrel of oil and $2.152 per MMbtu of gas February 1, 2016, due to the differences between SEC pricing and spot pricing on this date. This analysis includes only the impact of the change in pricing and does not contemplate changes in development costs, operating expenses, taxes, operational efficiencies, changes in technologies and access to capital. Based on spot commodity pricing at February 1, 2016, the Company’s proved undeveloped reserves would have been approximately 39.5% less than the results obtained using the SEC-mandated beginning-of-the-month average prices for the trailing 12-months for the year ended December 31, 2015. The Company’s number of proved undeveloped locations would have decreased from seven gross (5.2 net) locations to four gross (2.6 net) locations and projected future development costs related to the development of proved undeveloped locations would have been reduced from approximately $19.0 million to approximately $9.1 million.

Liquidity

The Company’s primary financial resource is its base of oil, natural gas and NGL reserves. The Company’s working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease its exploration and development expenditures. Historically, cash flows from operations, borrowings under the revolving credit facility and net proceeds from debt and equity offerings have been used to fund exploration and development of the Company’s oil and gas interests. During 2015, the Company spent between $190.0 million and $210.0 million of capital on drilling projects, facilities and related equipment and acquisitions of acreage, net of its joint development partner’s 35% working interest related to the drilling of 32 wells and the completion of 28 wells in Butler County, Pennsylvania, and excluding the capital expenditures of Water Solutions Holdings, LLC, which was sold in July 2015. The Company’s 2015 capital program was funded with proceeds from offerings completed in 2014 of senior notes due 2022 and preferred stock, net cash flow from operations, net proceeds from the disposition of Water Solutions Holdings, LLC of approximately $66.8 million and from borrowings under its revolving credit facility. The Company is in the process of establishing its 2016 plan and expects to release a 2016 capital budget of between $45.0 million and $65.0 million during the first quarter of 2016, which is expected to result in production growth of between 5% and 10%. Additionally, the Company continues to pursue a joint venture or joint development arrangement for its Moraine East operating area in Butler County, which, if consummated, would likely impact planned 2016 capital expenditures.

As of February 1, 2016, the Company had approximately $25.9 million of cash on hand. The Company expects to receive additional cash of approximately $18.5 million from one of its joint development partners during the first quarter of 2016 related to their working interest in 12 wells in Butler County, Pennsylvania, that were drilled and completed during 2015. As of February 1, 2016, the Company had approximately $835.3 million of indebtedness outstanding, including outstanding borrowings under the Company’s revolving credit facility consisting of $158.0 million of borrowings and an additional $41.0 million of undrawn letters of credit, of which approximately $35.2 million are related to the Company’s Gulf Coast firm transportation contracts. The Company is currently in discussions regarding the transfer of its credit support requirements related to Gulf Coast firm transportation to its purchasers. Pro forma for the Company’s new $200.0 borrowing base, the Company has approximately $1.0 million available for borrowings under the revolving credit facility. The Company’s ability to fund its capital expenditures is dependent upon the level of commodity prices and the success of its exploration program in replacing existing oil, NGL and natural gas reserves. If commodity prices decline further, operating cash flows may decrease and the Company’s

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lenders may further reduce the borrowing base, thus reducing the funds available to fund future capital expenditures. If the Company is unable to replace its oil, NGL and natural gas reserves through acquisition, development and exploration, it may also suffer a reduction in operating cash flows and access to funds under the revolving credit facility. At December 31, 2015, the Company was in compliance with all required debt covenants under its revolving credit facility. If the Company is unable to improve its liquidity position it may trigger non-compliance with required debt covenants in the future and otherwise adversely impact our ability to operate.

Due to the current depressed commodity price environment, in January 2016 the Company suspended payment of its quarterly dividend on shares of its Series A Convertible Perpetual Preferred Stock. The Company has the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. The Company may need to take additional actions in the future to address current industry trends and maintain its ability to pay its expenses and service its indebtedness, including, but not limited to, selling assets or raising capital by issuing additional debt or equity securities.

The Company has senior unsecured notes due 2020 and 2022 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 the Company’s 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 September 30, 2015, the Company’s Fixed Charge Coverage Ratio was 1.66. The Company expects its Fixed Charge Coverage Ratio to be less than 2.25:1 for the remainder of 2016. As a result, the Company anticipates that its ability to incur debt, pay dividends or make certain other restricted payments will be subject to the more restrictive provisions of the Indentures for those periods. The Indentures also contain customary events of default. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.

In connection with certain marketing, transportation and processing agreements that have been entered into, the Company may be obligated to pay minimum fees in connection with these agreements of between $175.0 million and $185.0 million over the next five years, depending on the corresponding levels of production. Also in connection with certain of these agreements, the Company concurrently entered into a guaranty whereby it has guaranteed the payment of obligations under the specified agreements up to a maximum of approximately $421.8 million over the life of the agreements, which range from 2 to 20 years.

In connection with the senior notes due 2020 and 2022, the Company has interest payments due each year of approximately $51.4 million payable semi-annually.

Volatility of Oil, NGL and Natural Gas Prices

The Company’s revenues, growth rate, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of its properties, are substantially dependent upon prevailing prices of oil, NGLs and natural gas. To mitigate some of the commodity price risk, the Company periodically engages in limited derivative activities including price swaps and costless collars in order to establish some price floor protection.

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The following table describes the Company’s current derivative positions as of February 1, 2016:

REX ENERGY CORPORATION

COMMODITY DERIVATIVES – HEDGE POSITION AS OF FEBRUARY 1, 2016

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Reconciliation of Non-GAAP Financial Measures

Finding and Development Cost

Finding and development cost per unit of production is a non-GAAP metric used by the industry, investors and analysts to measure the Company’s ability to establish a long-term trend of adding reserves at a reasonable cost. Drill-bit finding and development cost is defined as the sum of total capital deployed, less lease acquisitions and other related expenditures, divided by total extensions and discoveries. All-in finding and development cost is defined as the sum of total capital deployed divided by the sum of extensions, discoveries, acquisitions, divestitures, conversions, and revisions, less the prior period’s production. The calculations presented by the Company are based on unaudited costs incurred excluding estimated abandonment costs. For purposes of consistency with current calculations, we have revised certain amounts relating to prior period capital deployed and finding and development cost. All financial results are unaudited.

A tabular presentation of drill-bit and all-in capital deployed is included below ($ in millions):

A tabular presentation of drill-bit finding and development cost is included below ($ in millions):

PV-10

PV-10 is a non-GAAP metric used by the industry, investors and analysts to estimate 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. The following table shows the reconciliation of PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable GAAP measure, for the years ended December 31, 2014 and 2015. 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 as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

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Cash General and Administrative Expenses

Cash general and administrative expenses (“Cash G&A”) is the difference between GAAP G&A and non-cash G&A, which is primarily comprised of non-cash compensation expense. Rex Energy reports Cash G&A because it believes that this measure is commonly reported and widely used by management and investors as an indicator of overhead efficiency without regard to non-cash expenditures, such as stock compensation. Cash G&A is not a calculation based on GAAP financial measures and should not be considered as an alternative to GAAP G&A in measuring the Company’s performance. You should carefully consider the specific items included in the Company’s computation of this measure. You are cautioned that Cash G&A as reported by Rex Energy may not be comparable in all instances to that reported by other companies.

To compensate for these limitations, the Company believes it is important to consider both Cash G&A and GAAP G&A. The following table presents a reconciliation of Rex Energy’s GAAP G&A to its Cash G&A for each of the periods presented ($ in thousands):

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In accordance with General Instruction B.2 of Form 8-K, the information under this heading, including the related Exhibit 99.1 attached hereto, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth in such a filing.

Forward-Looking Statements

This Current Report on Form 8-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. Forward-looking statements are based on current beliefs and expectations and involve certain assumptions or estimates that involve various risks and uncertainties, such as financial market conditions, changes in commodities prices and the other risks discussed in detail in the Company’s filings with the Securities and Exchange Commission. Readers should not place undue reliance on any such forward-looking statements, which are made only as of the date hereof. The Company has no duty, and assumes no obligation, to update forward-looking statements as a result of new information, future events or changes in the Company’s expectations.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: February 3, 2016

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EXHIBIT INDEX

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