Rex Energy Reports Fourth Quarter and Full Year 2016 Operational and Financial Results

• Improved well design in Warrior North results in increased EURs and rate of returns
• In Warrior North, placed four-well Vaughn pad into sales; 5-day average sales rate per well of 1.5 Mboe/d and 65% liquids
• Liquids production accounted for 44% of total commodity revenues for the fourth quarter of 2016
• Realized C3+ NGL pricing for fourth quarter of 2016 was 56% of WTI before hedging
• Increased 2017 realized C3+ NGL pricing, before hedging, to 50% - 55% of WTI oil prices
• Production from continuing operations for the fourth quarter of 2016 was 194.9 MMcfe/d, a 12% year-over-year increase, including 38% from liquids
• 2016 net operational capital expenditures of $29.5 million came in below previous expectations of $35.5 million

STATE COLLEGE, Pa., March 07, 2017 (GLOBE NEWSWIRE) -- Rex Energy Corp. (Nasdaq:REXX) today announced its fourth quarter and full-year 2016 operational and financial results.

Operational Update

Warrior North Area

In the Warrior North Area, the company drilled seven gross (2.5 net) wells in 2016, with ten gross (4.1 net) wells fracture stimulated and 13 gross (5.1 net) wells placed into sales. The company had no wells drilled and awaiting completion as of December 31, 2016.

The company recently placed the four-well Vaughn pad into sales. The Vaughn wells were drilled to an average lateral length of approximately 7,200 feet and completed in an average of 37 stages with average sand concentrations of 2,600 pounds per foot. The wells produced at an average 24-hour sales rate per well, assuming full ethane recovery, of 1.5 Mboe/d, consisting of 3.1 MMcf/d of natural gas, 639 bbls/d of NGLs and 315 bbls/d of condensate. The wells went on to produce an average 5-day sales rate per well, assuming full ethane recovery, of 1.3 Mboe/d, consisting of 2.8 MMcf/d of natural gas, 579 bbls/d of NGLs and 289 bbls/d of condensate. The four Vaughn wells were drilled on the eastern portion of the Warrior North Area, where condensate yields have historically been lower than seen in other areas of the field.

Warrior North - Well Level Economics / Type Curve Update

The company has updated its well-level economics for the Warrior North Area. In the Warrior North Area, the company has adjusted its well-level economics to reflect its increased average lateral length, strong well performance, reduced cycle times and adjustments in expected realized prices. In summary, the rate of return assuming a $3.00 Henry Hub natural gas index price and $55.00 WTI oil index price has increased from 28% to 47% in the Warrior North Area. In addition, several of the company’s most recent Warrior North wells are performing above the company’s year-end 2016 type curve for the Warrior North Area. The updated results, as well as a comparison to previous results, are included on slide 23 of the company’s updated March corporate presentation.

Legacy Butler Operated Area

In the Legacy Butler Operated Area, the company drilled two gross (1.4 net) wells in 2016, with two gross (1.4 net) wells fracture stimulated and two gross (1.4 net) wells placed into sales. The company had no wells drilled and awaiting completion as of December 31, 2016.

In 2017, the company plans to drill the four-well Wilson pad in the Legacy Butler Operated Area, with an estimated average lateral length of 9,200 feet. The four-well Wilson pad is adjacent to the two-well Geyer pad, which was drilled to an average lateral length of 4,200 feet and placed into sales in August 2016. The two-well Geyer pad had an average 5-day sales rate per well of approximately 7.1 MMcfe/d. The four wells on the Wilson pad are expected to be placed into sales in the third quarter of 2017.

Moraine East Area

In the Moraine East Area, the company drilled 11.0 gross (4.5 net) wells in 2016, with six gross (2.7 net) wells fracture stimulated and 18 gross (8.7 net) wells placed into sales. The company had nine gross (3.8 net) wells drilled and awaiting completion as of December 31, 2016.

The company recently finished completing the four-well Baird pad, which was drilled to an average lateral length of approximately 7,140 feet. The pad is expected to be placed into sales at the end of the first quarter of 2017. The company has also finished drilling the six-well Shields pad, which was drilled to an average lateral length of approximately 7,750 feet. The Shields pad is expected to be placed into sales in the third quarter of 2017. The company is currently drilling the third of four wells on the Mackrell pad, which is expected to be drilled to an average lateral length of approximately 7,630 feet. The Mackrell pad is expected to be placed into sales in second half of 2017.

The six-well Shields pad and the four-well Mackrell pad will be the first wells drilled on the eastern portion of the Moraine East Area. This area is characterized by a thicker Upper Marcellus formation and the brittle nature of the formation allows for more effective completions. In addition, the Shields pad and the Mackrell pad are on trend with the the two-well Lynn pad, which was drilled in the Legacy Butler perated Area. The two wells were drilled to an average lateral length of approximately 2,725 feet and had average 5-day sales rates per well of 6.9 MMcfe/d.

2017 C3+ Natural Gas Liquids Pricing Improvement

During the fourth quarter of 2016, realized C3+ NGL prices, before the effects of hedging, averaged approximately 56% of WTI oil prices. The improvement in pricing was driven largely by the recent improvement in Mont Belvieu prices as well as improved differentials for NGLs in the northeast. Due to these improvements, the company now expects full-year 2017 realized C3+ NGL prices to average approximately 50% - 55% of WTI, an improvement over the previous guidance of 43% - 48%.

Fourth Quarter Financial Results

Unless otherwise noted, results of continuing operations are presented excluding the results of the company’s Illinois Basin assets, which have been classified as discontinued operations, for all periods presented. Fourth quarter and full-year 2016 production includes approximately 9.0 MMcfe/d related to the company’s recently divested Warrior South assets.

Operating revenue from continuing operations for the three months ended December 31, 2016 was $48.0 million, which represents an increase of 75% as compared to the same period in 2015. Commodity revenues, including settlements from derivatives, were $48.2 million, an increase of 12% as compared to the same period in 2015. Commodity revenues from natural gas liquids (NGLs) and condensate, including settlements from derivatives, represented 44% of total commodity revenues for the three months ended December 31, 2016.

Lease operating expense (LOE) from continuing operations was $28.7 million, or $1.60 per Mcfe for the quarter, a 15% increase as compared to the fourth quarter of 2015. The increase on a per unit basis is related to the commencement of the company’s Gulf Coast transportation during the fourth quarter of 2016 which was partially offset by decreased natural gas basis differentials. General and administrative expenses from continuing operations were $5.4 million for the fourth quarter of 2016, a 25% decrease on a per unit basis as compared to the same period in 2015. Cash general and administrative expenses from continuing operations, a non-GAAP measure, were $4.3 million for the fourth quarter of 2016, a 25% decrease on a per unit basis as compared to the same period in 2015.

Full-Year 2016 Financial Results

Operating revenue from continuing operations for full-year 2016 were $139.0 million, which remained flat as compared to 2015 operating revenue. Commodity revenue, including settlements from derivatives, were $171.9 million, a decrease of 11% from full-year 2015. Commodity revenue from natural gas liquids (NGLs) and condensate, including settlements from derivatives, represented 42% of total commodity revenues for full-year 2016.

LOE from continuing operations was $104.7 million, or $1.46 per Mcfe for 2016, a 4% year-over-year increase on a per unit basis as compared to full-year 2015. The increase is due to the commencement of the company’s Gulf Coast transportation during the fourth quarter of 2016. The increase in per unit LOE was partially offset by the decrease in natural gas basis differentials related to the Gulf Coast transport. General and administrative expenses from continuing operations were $20.6 million for full-year 2016, a 28% decrease on per unit basis as compared to full-year 2015. Cash general and administrative expenses from continuing operations, a non-GAAP measure, were $17.5 million for full-year 2016, a 19% decrease on per unit basis as compared to full-year 2015.

Reconciliations of G&A to cash G&A for the three months and twelve months ended December 31, 2016, as well as a discussion of the uses of this measure, are presented in the appendix of this release.

Production Results and Price Realizations

Fourth quarter 2016 production volumes from continuing operations were 194.9 MMcfe/d, an increase of 12% over the fourth quarter of 2015, consisting of 120.9 MMcf/d of natural gas, 5.4 MBbls/d of C3+ NGLs, 5.8 Mbbls/d of ethane and 1.1 Mbbls/d of condensate. NGLs (including ethane) and condensate accounted for 38% of net production for the fourth quarter of 2016. For full-year 2016, production volumes increased by 6% over 2015 to 195.3 MMcfe/d, consisting of 122.1 MMcf/d of natural gas, 5.5 MBbls/d of C3+ NGLs, 5.8 Mbbls/d of ethane and 1.0 Mbbls/d of condensate. NGLs (including ethane) and condensate accounted for 37% of net production during 2016.

Including the effects of cash-settled derivatives, realized prices for the three months ended December 31, 2016 were $2.42 per Mcf for natural gas, $25.39 per barrel for NGLs (C3+), $8.88 per barrel for ethane and $37.73 per barrel for condensate. Before the effects of hedging, realized prices for the three months ended December 31, 2016 were $2.23 per Mcf for natural gas, $27.64 per barrel for NGLs (C3+), $9.36 per barrel for ethane and $43.13 per barrel for condensate.

Including the effects of cash-settled derivatives, realized prices for the twelve months ended December 31, 2016 were $2.23 per Mcf for natural gas, $20.43 per barrel for NGLs (C3+), $7.80 per barrel for ethane and $41.64 per barrel for condensate. Before the effects of hedging, realized prices for the twelve months ended December 31, 2016 were $1.64 per Mcf for natural gas, $17.97 per barrel for NGLs (C3+), $7.81 per barrel for ethane and $37.08 per barrel for condensate.

Full-Year 2016 Capital Investments

For the full-year 2016, net operational capital investments were approximately $29.5 million. These capital investments funded the drilling of 20.0 gross (8.4 net) wells, fracture stimulation of 18.0 gross (8.2 net) wells, placing 34.0 gross (16.2 net) wells into sales and other projects related to drilling and completing wells in the Appalachian Basin.

Liquidity Update

During the first quarter of 2017, Rex Energy completed the sale of its Warrior South asset for approximately $30 million; in conjunction with the completion of the sale, the company received approval from its bank lenders to maintain the existing $190 million borrowing base. With the additional liquidity from the sale of the Warrior South asset, the company was able to add additional wells to the Shields pad and the Wilson pads. The Shields pad and the Wilson pad are targeting the highest quality areas of the Moraine East Area and the Legacy Butler Operated Area. The additional wells per pad will add to greater efficiencies to the overall well pad costs.

First Quarter and Full-Year 2017 Guidance

The following table outlines Rex Energy’s guidance for the first quarter of 2017 and full-year 2017. First quarter 2017 production, adjusting for the Warrior South asset sale, would have been approximately 182.0 – 184.0 MMcfe/d. However, the company experienced delays in the completion of the four-well Vaughn pad and the four-well Baird pad during the first quarter of 2017, which resulted in a reduction of 5% to the company’s expected first quarter 2017 production. Given that the majority of the wells in the 2017 development plan will be placed into sales in the second half of the year, the company continues to expect full-year 2017 average daily production to be in the range of 194.0 – 204.0 MMcfe/d.

Conference Call Information

Management will host a live conference call and webcast on Wednesday, March 8, 2017 at 10:00 a.m. Eastern to review fourth quarter and full year 2016 financial results and operational highlights. The telephone number to access the conference call is (866) 437-1772.

About Rex Energy Corporation

Headquartered in State College, Pennsylvania, Rex Energy is an independent oil and gas exploration and production company with its core operations in the Appalachian Basin. The company’s strategy is to pursue its higher potential exploration drilling prospects while acquiring oil and natural gas properties complementary to its portfolio.

Forward-Looking Statements

Except for historical information, statements made in this release, including those relating to the timing and nature of development plans; drilling and completion schedules; anticipated fracture stimulation activities; expected dates for placement of wells into sales; anticipated hedging strategies and potential results thereof; and our financial guidance for full year 2017, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may contain words such as "expected", "expects", "scheduled", "planned", "plans", "anticipates" or similar words, and are based on management's experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We believe these statements and the assumptions and estimates contained in this release are reasonable based on information that is currently available to us. However, management's assumptions and the company's future performance are subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can or will meet the goals, expectations, and projections included in this release. Any number of factors could cause our actual results to be materially different from those expressed or implied in our forward looking statements, including (without limitation):

• economic conditions in the United States and globally;
• domestic and global supply and demand for oil, NGLs and natural gas;
• realized prices for oil, natural gas and NGLs and volatility of those prices;
• the adequacy and availability of capital resources, credit and liquidity, including, but not limited to, access to additional borrowing capacity and our inability to generate sufficient cash flow from operations to fund our capital expenditures and meeting working capital needs;
• our ability to comply with restrictions imposed by our senior credit facility and other existing and future financing arrangements;
• our ability to service our outstanding indebtedness
• impairments of our natural gas and oil asset values due to declines in commodity prices;
• conditions in the domestic and global capital and credit markets and their effect on us;
• new or changing government regulations, including those relating to environmental matters, permitting or other aspects of our operations;
• the willingness and ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls;
• the geologic quality of our properties with regard to, among other things, the existence of hydrocarbons in economic quantities;
• uncertainties inherent in the estimates of our oil, NGL and natural gas reserves;
• our ability to increase oil, NGL and natural gas production and income through exploration and development;
• drilling and operating risks;
• counterparty credit risks;
• the success of our drilling techniques in both conventional and unconventional reservoirs;
• the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future;
• the number of potential well locations to be drilled, the cost to drill, and the time frame within which they will be drilled;
• the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;
• the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services;
• the effects of adverse weather or other natural disasters on our operations;
• competition in the oil and gas industry in general, and specifically in our areas of operations;
• changes in our drilling plans and related budgets;
• the success of prospect development and property acquisitions;
• the success of our business and financial strategies, and hedging strategies;
• uncertainties related to the legal and regulatory environment for our industry and our own legal proceedings and their outcome;
• our ability to cure the deficiencies with respect to the continued listing standards of The NASDAQ Capital Market or any other exchange on which our securities trade; and
• other factors discussed under “Item 1A. Risk Factors” in our Annual Report on Form 10-K and any updates to those Risk Factors.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on the company's risks and uncertainties is available in our filings with the Securities and Exchange Commission and we strongly encourage investors to review those filings.

APPENDIX
REX ENERGY CORPORATION
NON-GAAP MEASURES

EBITDAX

“EBITDAX” means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives, non-recurring gains and losses, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives and gains on asset dispositions, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

• Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure;
• The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis;
• Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and
• The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, 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 consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because 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 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 that EBITDAX assists our lenders and investors in comparing our 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. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, 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.

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

Adjusted Net Income

“Adjusted Net Income” means, for any period, the sum of net income (loss) from continuing operations before income taxes for the period plus the following expenses, charges or income, in each case, to the extent deducted from or added to net income in the period: unrealized losses from financial derivatives, non-cash compensation expense, dry hole expenses, disposals of assets, impairment and other one-time or non-recurring charges, minus all gains from unrealized financial derivatives, disposal of assets and deferred income tax benefits, added to net income. Adjusted Net Income is used as a financial measure by Rex Energy's management team and by other users of its financial statements, to analyze its financial performance without regard to non-cash deferred taxes and non-cash unrealized losses or gains from oil and gas derivatives. Adjusted Net Income is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring the company's performance.

Rex Energy reports Adjusted Net Income because it believes that this measure is commonly reported and widely used by investors as an indicator of a company's operating performance. You should carefully consider the specific items included in the company's computation of this measure. You are cautioned that Adjusted Net Income 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 net income determined under GAAP and Adjusted Net Income.

The following table presents a reconciliation of Rex Energy’s net income from continuing operations to its adjusted net income for each of the periods presented ($ in thousands):

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 has reported 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):

For more information contact:

Investor Relations
(814) 278-7130
InvestorRelations@rexenergycorp.com