Market Overview

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

Share:
  • 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 Corporation (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. 

  1Q2017 Full-Year 2017
Production 173.0 – 175.0 MMcfe/d 194.0 – 204.0 MMcfe/d
LOE ($/Mcfe) -- $1.70 - $1.80
Cash G&A ($/Mcfe) -- $0.20 - $0.25
Net Operational Capital Expenditures(1) -- $70.0 - $80.0 million
(1) Land acquisition expense and capitalized interest are not included in the net operational capital expenditures budget estimate

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.

 
REX ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in Thousands, Except Share and Per Share Data)
 
ASSETS December 31, 2016
(Unaudited)
  December 31, 2015
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 Debt Exchanges 641,762     663,089  
Premium 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  
       
Stockholder 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 Owners' Equity $ 893,923     $ 1,071,931  
               


REX ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in Thousands, Except per Share Data)
 
  For the Three Months Ended
December 31,
  For the Twelve Months Ended
December 31,
  2016     2015     2016     2015  
OPERATING REVENUE              
Natural Gas, Condensate and NGL Sales $ 48,022     $ 27,363     $ 139,000     $ 138,707  
Other Revenue 5     12     17     42  
TOTAL OPERATING REVENUE 48,027     27,375     139,017     138,749  
OPERATING EXPENSES              
Production and Lease Operating Expense 28,694     22,246     104,699     93,892  
General and Administrative Expense 5,384     6,441     20,621     26,694  
(Gain) Loss on Disposal of Assets 164     (7 )   (4,121 )   (540 )
Impairment Expense 29,275     73,364     74,619     283,244  
Exploration Expense 224     843     2,178     2,617  
Depreciation, Depletion, Amortization and Accretion 16,503     18,475     62,874     85,844  
Other Operating Expense (Income) (176 )   275     10,754     5,603  
TOTAL OPERATING EXPENSES 80,068     121,637     271,624     497,354  
LOSS FROM OPERATIONS (32,041 )   (94,262 )   (132,607 )   (358,605 )
OTHER INCOME (EXPENSE)              
Interest Expense (9,404 )   (11,706 )   (43,519 )   (47,783 )
Gain (Loss) on Derivatives, Net (24,261 )   14,689     (32,515 )   60,176  
Other Expense (2,152 )   (247 )   (2,124 )   (129 )
Debt Exchange Expense (15 )   --     (9,063 )   --  
Gain on Extinguishment of Debt 497     --     24,627     --  
Loss on Equity Method Investments --     --     --     (411 )
TOTAL OTHER INCOME (EXPENSE) (35,335 )   2,736     (62,594 )   11,853  
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX (67,376 )   (91,526 )   (195,201 )   (346,752 )
Income Tax Expense (8,221 )   (6,030 )   (2,436 )   (6,030 )
NET LOSS FROM CONTINUING OPERATIONS (75,597 )   (97,556 )   (197,637 )   (352,782 )
Income (Loss) From Discontinued Operations, Net of Income Taxes 8,203     (481 )   20,922     (8,251 )
NET LOSS (67,394 )   (98,037 )   (176,715 )   (361,033 )
Net Income Attributable to Noncontrolling Interests --     --     --     2,245  
NET LOSS ATTRIBUTABLE TO REX ENERGY (67,394 )   (98,037 )   (176,715 )   (363,278 )
Preferred Stock Dividends (650 )   (2,415 )   (5,091 )   (9,660 )
Effect of Preferred Stock Conversions 668     --     72,984     --  
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (67,376 )   $ (100,452 )   $ (108,822 )   $ (372,938 )
Earnings per common share:              
Basic – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders $ (0.78 )   $ (1.84 )   $ (1.63 )   $ (6.66 )
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders 0.09     (0.01 )   0.26     (0.19 )
Basic – Net Loss Attributable to Rex Energy Common Shareholders $ (0.69 )   $ (1.85 )   $ (1.37 )   $ (6.85 )
Basic – Weighted Average Shares of Common Stock Outstanding 97,398     54,342     79,256     54,392  
Diluted – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders $ (0.78 )   $ (1.84 )   $ (1.63 )   $ (6.66 )
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Energy  Common Shareholders 0.09     (0.01 )   0.26     (0.19 )
Diluted – Net Loss Attributable to Rex Energy Common Shareholders $ (0.69 )   $ (1.85 )   $ (1.37 )   $ (6.85 )
Diluted – Weighted Average Shares of Common Stock Outstanding 97,398     54,342     79,256     54,392  


REX ENERGY CORPORATION
CONSOLIDATED OPERATIONAL HIGHLIGHTS
UNAUDITED
 
    Three Months Ending   Twelve Months Ending
    December 31,   December 31,
    2016
  2015   2016
  2015
Oil, Natural Gas, NGL and Ethane sales (in thousands):                        
Natural gas sales   $ 24,844     $ 15,083   $ 73,275     $ 83,140
Natural gas liquids (C3+) sales     13,824       7,917     35,877       32,789
Ethane sales     4,989       2,552     16,484       8,710
Condensate sales     4,366       1,811     13,364       14,068
Cash-settled derivatives:                        
Natural gas     2,068       9,323     26,348       32,573
Natural gas liquids (C3+)     (1,126 )     3,204     4,914       10,384
Ethane     (255 )     1,103     (14 )     42
Condensate     (547 )     3,054     1,644       11,860
Total oil, gas, NGL and Ethane sales including cash settled derivatives   $ 48,163     $ 43,054   $ 171,892     $ 193,566
                         
Production during the period:                        
Natural gas (Mcf)     11,125,475       10,446,424     44,684,571       44,606,753
Natural gas liquids (C3+) (Bbls)     500,114       454,963     1,996,075       2,026,321
Ethane (Bbls)     532,841       416,496     2,111,321       1,319,582
Condensate (Bbls)     101,239       57,141     360,384       402,867
Total (Mcfe)1     17,930,639       16,018,024     71,491,251       67,099,373
                         
Production – average per day:                        
Natural gas (Mcf)     120,929       113,548     122,089       122,210
Natural gas liquids (C3+) (Bbls)     5,436       4,945     5,454       5,552
Ethane (Bbls)     5,792       4,527     5,769       3,615
Condensate (Bbls)     1,100       621     985       1,104
Total (Mcfe)1     194,898       174,109     195,331       183,834
                         
Average price per unit:                        
Realized natural gas price per Mcf – as reported   $ 2.23     $ 1.44   $ 1.64     $ 1.86
Realized impact from cash settled derivatives per Mcf     0.19       0.89     0.59       0.73
Net realized price per Mcf   $ 2.42     $ 2.33   $ 2.23     $ 2.59
                         
Realized NGL (C3+) price per Bbl – as reported   $ 27.64     $ 17.40   $ 17.97     $ 16.18
Realized impact from cash settled derivatives per Bbl2     (2.25 )     7.04     2.46       5.12
Net realized price per Bbl   $ 25.39     $ 24.44   $ 20.43     $ 21.30
                         
Realized ethane price per Bbl – as reported   $ 9.36     $ 6.13   $ 7.81     $ 6.60
Realized impact from cash settled derivatives per Bbl     (0.48 )     0.26     (0.01 )     0.10
Net realized price per Bbl   $ 8.88     $ 6.39   $ 7.80     $ 6.70
                         
Realized condensate price per Bbl – as reported   $ 43.13     $ 31.69   $ 37.08     $ 34.92
Realized impact from cash settled derivatives per Bbl     (5.40 )     53.45     4.56       29.44
Net realized price per Bbl   $ 37.73     $ 85.14   $ 41.64     $ 64.36
                         
LOE/Mcfe   $ 1.60     $ 1.39   $ 1.46     $ 1.40
Cash G&A/Mcfe   $ 0.24     $ 0.32   $ 0.25     $ 0.31
1 Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe.
Includes the effect of derivatives not classified as discontinued operations
 



REX ENERGY CORPORATION
COMMODITY DERIVATIVES – HEDGE POSITION AS OF 3/2/2017
 
    2017       2018  
Oil Derivatives (Bbls)          
Swap Contracts          
Volume   81,000       60,000  
Price $ 53.30     $ 54.00  
Deferred Premium Puts          
Volume   15,000       --  
Floor $ 51.00       --  
Collar Contracts          
Volume   48,000       18,000  
Ceiling $ 57.20     $ 60.00  
Floor $ 45.00     $ 53.00  
Collar Contracts with Short Puts          
Volume   93,000       60,000  
Ceiling $ 61.50     $ 62.30  
Floor $ 49.68     $ 52.00  
Short Put $ 40.16     $ 43.00  
Natural Gas Derivatives (Mcf)          
Swap Contracts          
Volume   14,900,000       9,160,000  
Price $ 3.03     $ 3.19  
Swaption Contracts          
Volume   2,400,000       --  
Price $ 3.33     $ --  
Put Spread Contracts          
Volume   --       --  
Floor $ --     $ --  
Short Put $ --     $ --  
Collar Contracts with Short Puts          
Volume   17,510,000       8,775,000  
Ceiling $ 3.87     $ 3.58  
Floor $ 3.01     $ 2.89  
Short Put $ 2.33     $ 2.30  
Call Contracts          
Volume   8,380,100       16,489,900  
Ceiling $ 4.51     $ 4.64  
Collar Contracts          
Volume   1,700,000       450,000  
Ceiling $ 3.20     $ 3.65  
Floor $ 2.54     $ 3.20  
Natural Gas Liquids (Bbls)          
Swap Contracts          
Propane (C3)          
Volume   962,000       600,000  
Price $ 23.25     $ 25.56  
Butane (C4)          
Volume   240,000       180,000  
Price $ 29.15     $ 32.97  
Isobutane (IC4)          
Volume   117,000       96,000  
Price $ 29.94     $ 33.71  
Natural Gasoline (C5+)          
Volume   364,000       192,000  
Price $ 48.01     $ 49.35  
Ethane          
Volume   840,000       420,000  
Price $ 10.47     $ 13.02  
Natural Gas Basis (Mcf)          
Swap Contracts          
Dominion Appalachia          
Volume   15,435,000       18,980,000  
Price $ (0.86 )   $ (0.82 )
Texas Gas Zone 1          
Volume   14,600,000       14,600,000  
Price $ (0.13 )   $ (0.13 )
NYMEX Heating Oil (Gallon)          
Swap Contracts          
Volume   --       --  
Price $ --     $ --  
               

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.

    Three Months Ended
December 31,

(Unaudited)
  Twelve Months Ended
December 31, 
(Unaudited)
    2016     2015     2016     2015  
Net Loss From Continuing Operations   $ (75,597 )   $ (97,556 )   $ (197,637 )   $ (352,782 )
Add Back (Less) Non-Recurring Costs (Income)1   (372 )   --     (6,760 )   4,774  
Add Back Depletion, Depreciation, Amortization and Accretion   16,503     18,475     62,874     85,844  
Add Back Non-Cash Compensation Expense   1,072     1,378     3,078     5,791  
Add Back Interest Expense   9,404     11,706     43,519     47,783  
Add Back Impairment Expense   29,275     73,364     74,619     283,244  
Add Back Exploration Expenses   224     843     2,178     2,617  
Add Back (Less) (Gain) Loss on Disposal of Assets2   164     (4 )   (4,121 )   (537 )
Add Back (Less) (Gain) Loss on Financial Derivatives   24,261     (14,689 )   32,515     (60,176 )
Add Back Cash Settlement of Derivatives   86     15,691     32,571     55,793  
Add Back Non-Cash Portion of Equity Method Investments   --     --     --     406  
Add Back Income Tax Expense   8,221     6,030     2,436     6,030  
EBITDAX From Continuing Operations   $ 13,241     $ 15,238     $ 45,272     $ 78,787  
Income (loss) from Discontinued Operations   $ 8,203     $ (481 )   $ 20,922     $ (8,251 )
Net Income Attributable to Noncontrolling Interests   --     --     --     (2,245 )
Income (Loss) From Discontinued Operations Attributable to Rex Energy   8,203     (481 )   20,922     (10,496 )
Add Back Depletion, Depreciation, Amortization and Accretion   1     3,481     5,101     18,978  
Add Back (Less) Non-Cash Compensation Expense (Income)   (52 )   238     (159 )   659  
Add Back Interest Expense   --     3     4     510  
Add Back Impairment Expense   --     7,734     3,543     62,531  
Add Back Exploration Expense (Income)   --     (74 )   143     394  
Add (Less) Back (Gain) Loss on Disposal of Asset2   5     (760 )   (30,530 )   (57,748 )
Add Back (Less) Non-Cash Portion of Noncontrolling Interests   --     1     --     (208 )
Less Income Tax Benefit   (7,852 )   (8,688 )   --     (6,030 )
Add EBITDAX From Discontinued Operations   $ 305     $ 1,454     $ (976 )   $ 8,590  
EBITDAX (Non-GAAP)   $ 13,546     $ 16,692     $ 44,296     $ 87,377  
 
1 For the year ended December 31, 2016, non-recurring income includes approximately $24.6 million related to the extinguishment of debt, partially offset by approximately $9.1 million in debt exchange expenses, approximately $0.5 million in fees incurred related to the BSP transaction and approximately $8.3 million in expense related to a firm transportation agreement. For the three months ended December 31, 2016, non-recurring income includes amounts related to additional gains related to the extinguishment of debt. For the year ended December 31, 2015, non-recurring costs include net fees incurred to terminate two drilling rig contracts earlier than their original term
2 Includes gain on sale of Water Solutions Holdings of approximately $57.8 million for the year ended December 31, 2015

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):

  Three Months Ended
    Twelve Months Ended
  December 31,
(Unaudited)
    December 31, 
(Unaudited)

    2016       2015         2016       2015  
Loss From Continuing Operations Before Income Taxes, as reported $ (67,376 )   $ (97,556 )     $ (195,201 )   $ (346,752 )
Gain (Loss) on Derivatives, Net   24,261       (14,689 )       32,515       (60,176 )
Cash Settlement of Derivatives   86       15,691         32,571       55,793  
Add Back (Less) Losses (Gains) from Financial Derivatives   24,347       1,002         65,086       (4,383 )
Add Back Non-Recurring Costs1   (372 )     --         (6,760 )     4,774  
Add Back Impairment Expense   29,275       73,364         74,619       283,244  
Add Back Dry Hole Expense   32       --         880       191  
Add Back (Less) Non-Cash Compensation Expense (Income)   1,072       1,378         3,078       5,791  
Add Back (Less) (Gain) Loss on Disposal of Assets   164       (4 )       (4,121 )     (537 )
Loss From Continuing Operations Before Income Taxes, adjusted $ (12,858 )   $ (21,816 )     $ (62,419 )   $ (57,672 )
Less Income Tax Benefit, adjusted2   5,143       8,726         24,968       23,069  
Adjusted Net Loss From Continuing Operations $ (7,715 )   $ (13,090 )     $ (37,451 )   $ (34,603 )
                         
Basic – Adjusted Net Loss Per Share $ (0.08 )   $ (0.24 )     $ (0.47 )   $ (0.64 )
Basic – Weighted Average Shares of Common Stock Outstanding   97,398       54,342         79,256       54,392  
                         
1  For the year ended December 31, 2016, non-recurring income includes approximately $24.6 million related to the extinguishment of debt, partially offset by approximately $9.1 million in debt exchange expenses, approximately $0.5 million in fees incurred related to the BSP transaction and approximately $8.3 million in expense related to a firm transportation agreement. For the three months ended December 31, 2016, non-recurring income includes amounts related to additional gains related to the extinguishment of debt. For the year ended December 31, 2015, non-recurring costs include net fees incurred to terminate two drilling rig contracts earlier than their original term
2Assumes an effective tax rate of 40%

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):

  Three Months Ended
December 31,
(Unaudited)
  Twelve Months Ended
December 31,
(Unaudited)
  2016   2015   2016   2015
GAAP G&A $ 5,384   $ 6,441   $ 20,621   $ 26,694
Non-Cash Compensation Expense 1,072   1,378   3,078   5,791
Cash G&A $ 4,312   $ 5,063   $ 17,543   $ 20,903

 

For more information contact:

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

Primary Logo

View Comments and Join the Discussion!