Rex Energy Reports Fourth Quarter and Full Year 2013 Operational and Financial Results

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| Source: Rex Energy Corporation
  • Average daily production from oil and NGLs reached a record level of 5.7 MBoe/d, a 7% increase over the third quarter of 2013
  • Fourth quarter adjusted EBITDAX reached $40.7 million, the highest level in company history
  • Increased proved reserves at December 31, 2013 by 37% over December 31, 2012; Appalachian Basin drill-bit F&D of $0.70/Mcfe for 2013
  • Baillie Trust pad continues to perform well; 30-day sales rate of 5.1 MMcfe/d per well from four vertically offset stacked laterals
  • Currently drilling the three-well Schilling pad, with an estimated lateral length of ~ 5,800 feet, the longest average lateral length of any combination of wells drilled in the Butler Operated Area
  • Drilling final well of six-well Grunder pad in Warrior North Prospect; nine wells in the Warrior North Prospect to be placed into sales in second quarter of 2014
  • Exited 2013 with approximately 79,000 gross acres in the Butler Operated Area

STATE COLLEGE, Pa., Feb. 19, 2014 (GLOBE NEWSWIRE) -- Rex Energy Corporation (Nasdaq:REXX) today announced its fourth quarter and full year 2013 operational and financial results.

Fourth Quarter Financial Results

Operating revenues from continuing operations for the three months ended December 31, 2013 were $72.1 million, which represents an increase of 60% over the same period in 2012. Commodity revenues, including the net cash received from derivatives, were $65.1 million, an increase of 49% over the comparable period of 2012. Commodity revenues from oil and natural gas liquids (NGLs), including net cash received from derivatives, represented 56% of total commodity revenues for the three months ended December 31, 2013.

Lease operating expense (LOE) from continuing operations was $18.4 million, or $1.82 per Mcfe for the quarter, a 6% decrease on a per unit basis compared to the same period in 2012. DD&A expense for the fourth quarter of 2013 was $23.6 million, an increase of $10.4 million over the fourth quarter of 2012 and $7.3 million over the third quarter of 2013. This increase in depletion is due to the significant production growth in the Appalachian Basin assets and higher finding costs in the Illinois Basin.

The company incurred a non-cash impairment charge of approximately $29.7 million during the fourth quarter of 2013, largely due to higher finding costs on its exploration program in the Illinois Basin as well as decreases in expected future prices for crude oil.

Loss from continuing operations attributable to common shareholders for the three months ended December 31, 2013 was $13.9 million, or $0.26 per share. Adjusted net income, a non-GAAP measure, for the three months ended December 31, 2013 was $5.4 million, or $0.10 per share.

EBITDAX from continuing operations, a non-GAAP measure, was $40.7 million for the fourth quarter, an increase of 54% over the fourth quarter of 2012 and 17% over the third quarter of 2013.

Reconciliations of cash G&A expenses to GAAP G&A expenses, adjusted net income to GAAP net income, and EBITDAX to GAAP net income for the three months ended December 31, 2013, as well as a discussion of the uses of each measure, are presented in the appendix attached to this release.

Full Year 2013 Financial Results

Operating revenues from continuing operations for the full year 2013 were $237.9 million, which is an increase of 61% over full year 2012 operating revenues. Commodity revenues, including the net cash received from derivatives, were $221.0 million, an increase of 47% over full year 2012. Commodity revenues from oil and NGLs, including net cash received from derivatives, represented 56% of total commodity revenues for the full year 2013.

LOE from continuing operations was $62.1 million, or $1.84 per Mcfe for the full year 2013. Cash G&A expenses from continuing operations, a non-GAAP measure which excludes stock based compensation, were $27.7 million for the full year 2013. DD&A expense for the full year 2013 was $63.9 million, an increase of $18.5 million over the full year 2012. This increase in depletion is due to the significant production growth in the Appalachian Basin assets and higher finding costs in the Illinois Basin.

Loss from continuing operations attributable to common shareholders for the full year 2013 was $1.9 million, or $0.04 per share. Adjusted net income, a non-GAAP measure, for the full year 2013 was $23.8 million, or $0.45 per share.

EBITDAX from continuing operations, a non-GAAP measure, was $134.9 million for the full year 2013, an increase of 52% over the full year 2012.

Reconciliations of cash G&A expenses to GAAP G&A expenses, adjusted net income to GAAP net income, and EBITDAX to GAAP net income for the twelve months ended December 31, 2013, as well as a discussion of the uses of each measure, are presented in the appendix attached to this release.

Production Update

Fourth quarter 2013 production volumes were 110.4 MMcfe/d, an increase of 12% over the third quarter of 2013 and 49% over the fourth quarter of 2012, consisting of 76.4 MMcf/d of natural gas and 5.7 Mboe/d of oil and NGLs. Oil and NGLs accounted for 31% of net production during the fourth quarter and increased by 7% over the third quarter of 2013. For full year 2013, production volumes increased by 38% over 2012 to 92.7 MMcfe/d, consisting of 64.2 MMcf/d of natural gas and 4.8 Mboe/d of oil and NGLs. Oil and NGLs increased by 59% over 2012 and accounted for 31% of net production during 2013. Both the company's fourth quarter 2013 and full year 2013 average daily production volumes exceeded the midpoint of the company's previously announced fourth quarter 2013 and full year 2013 production guidance.

Including the effects of cash-settled derivatives, realized prices for the three months ended December 31, 2013 were $90.30 per barrel for oil and condensate, $4.03 for natural gas and $52.19 per barrel for NGLs. For the full year 2013, realized prices including the effects of cash-settled derivatives were $91.30 per barrel for oil and condensate, $4.17 for natural gas and $48.34 per barrel for NGLs. Before the effects of hedging, realized prices for the three months ended December 31, 2013 were $93.33 per barrel for oil and condensate, $3.60 for natural gas and $54.81 per barrel for NGLs. For the full year 2013, realized prices prior the effects of hedging were $95.12 per barrel for oil and condensate, $3.71 for natural gas and $48.66 per barrel for NGLs.

Full Year 2013 Capital Investments

For the full year 2013, the company made operational capital investments of approximately $303.2 million, of which $233.0 million was used to fund Marcellus and Ohio Utica operations and $70.2 million was used to fund conventional drilling, water flood enhancement and facility upgrades in the Illinois Basin. The Marcellus and Ohio Utica capital investment funded the drilling of 42.0 gross (29.8 net) wells, fracture stimulation of 44.0 gross (30.0 net) wells, placing 47.0 gross (31.7 net) wells into sales and other projects related to drilling and completing wells in the Appalachian Basin. The Illinois Basin capital investment funded the drilling of 19 gross (19.0 net) wells, fracture stimulation of 29 gross (29.0 net) wells and placing 29 gross (29.0 net) wells into sales and other projects related to drilling and completing wells.

In addition to operational capital investments, investments for leasing and property acquisitions were $35.6 million and capitalized interest was $7.5 million for the full year 2013.

Estimated Proved Reserves

Rex Energy previously reported proved oil, NGL and natural gas reserves as of December 31, 2013 of 849.8 Bcfe, an increase of 37% over December 31, 2012. Of the proved reserves, 39% was attributable to oil, natural gas liquids and condensate, assuming 55% ethane recovery. The proved developed portion of the reserves increased to 356.5 Bcfe from 257.9 Bcfe as of December 31, 2012 and accounted for 42% of proved reserves. Drill-bit finding and development costs on a per unit basis were $0.91 per Mcfe for 2013 and $0.70 per Mcfe for the Appalachian Basin. The proved reserves estimates as of December 31, 2013 were prepared by the company's independent reservoir engineers, Netherland, Sewell & Associates, Inc. For more information on proved reserves and related information, see "Note on Hydrocarbon Volumes and Estimates" below.

Operational Update

Note: Unless specifically stated otherwise in this operational update, all numbers are gross; all well results assume full ethane recovery and all wells were completed using the company's 150' stage spacing "Super Frac" design.

Appalachian Basin – Butler Operated Area, Pennsylvania

In the Butler Operated Area, the company drilled 19.0 gross (13.3 net) wells in 2013, with 26.0 gross (18.2 net) wells fracture stimulated and 26.0 gross (18.2 net) wells placed into service. The company had 11.0 gross (7.7 net) wells drilled and awaiting completion as of December 31, 2013.

As previously reported, the company placed into sales the six-well Baillie Trust pad, which produced into sales at an average five-day sales rate per well (excluding downtime) of 5,957 Mcfe/d (52% NGLs, 47% gas, 1% condensate), assuming full ethane recovery. The six wells have gone on to produce at an average 30-day sales rate per well (excluding downtime) of 5,192 Mcfe/d (52% NGLs, 47% gas, 1% condensate), assuming full ethane recovery. In addition, the company tested slightly different landing zones for the laterals on two of the six wells drilled. Based on the results of these wells, the company plans to target its historical landing zone in the high organic section of the reservoir for future laterals in its Butler Operated Area. The 30-day sales rate per well for the four wells landed in the high organic section of the reservoir was 5.5 MMcfe/d.

The company is currently drilling the third of three wells on the Schilling pad. The three wells will be drilled with an average lateral length of approximately 5,800 feet, which represents the longest average lateral length of any combination of wells drilled in the Butler Operated Area. The company expects to finish drilling the wells during the first quarter of 2014 and begin completion operations in the second quarter of 2014.

The table below lists, where available, the 5-day and 30-day sales rates for the company's recent completions.

 
5-Day Sales Rate (Average Per Well)
Well Name Target Formation Natural Gas (Mcf/d) NGLs / Condensate (Bbls/d) % Liquids Total – Ethane Recovery (Mcfe/d) Total - Ethane Rejection (Mcfe/d)
Baillie Trust(1) 2H, 4H, 5H(2), 6H (2) Marcellus / Upper Devonian 2,826 531 53% 6,009 4,105
Baillie Trust 1H, 3H Marcellus 2,711 524 54% 5,854 4,023
 
30-Day Sales Rate (Average Per Well)
Well Name Target Formation Natural Gas (Mcf/d) NGLs / Condensate (Bbls/d) % Liquids Total – Ethane Recovery (Mcfe/d) Total - Ethane Rejection (Mcfe/d)
Baillie Trust(1) 2H, 4H, 5H(2), 6H (2) Marcellus / Upper Devonian 2,405 450 53% 5,106 3,486
Baillie Trust 1H, 3H Marcellus 2,487 479 54% 5,364 3,685
(1) Stacked laterals
(2) Upper Devonian wells
 
Total Operated Area – Butler County, PA
  Wells Drilled Wells Fracture Stimulated Wells Placed Into Sales Wells Awaiting Completion
FY 2014 Forecast 40 – 45 35 – 38 35 – 38 16 – 18

Butler Operated Area – Midstream Capacity

As previously reported, the company's existing 90 MMcf/d of processing capacity at the Sarsen and Bluestone facilities has been substantially filled and the company expects the plant to remain at or near capacity until the Bluestone II facility, which is currently under construction, is commissioned. The company continues to expect that the Bluestone II facility will be commissioned in the second quarter of 2014, adding an incremental 120 MMcf/d of processing capacity in the Butler Operated Area (of which 100 MMcf/d is dedicated to Rex Energy). The company currently expects to place 10 – 12 wells into sales in the second quarter of 2014 in its Butler Operated Area due to the additional processing capacity at the Bluestone II facility.

In addition, Rex Energy recently secured approximately 48 MMcf/d of additional future firm residue transportation through Dominion Transmission in the Butler Operated Area. The company now has approximately 133 MMcf/d of firm transportation in the Butler Operated Area. The additional firm transportation will be used to support the expected production growth in the Butler Operated Area once the Bluestone II facility is commissioned in the second quarter of 2014.

Appalachian Basin – Warrior North Prospect, Carroll County, Ohio

In the Warrior North Prospect, the company drilled nine gross (9.0 net) wells in 2013, with four gross (4.0 net) wells fracture stimulated and four gross (4.0 net) wells placed into service. The company had six gross (6.0 net) wells awaiting completion as of December 31, 2013.

The company is drilling the last well on the six-well Grunder pad in the Warrior North Prospect. The six wells will average total measured depth of approximately 12,905 feet with an average lateral length of approximately 4,800 feet. The company recently added a sixth well to the Grunder pad in order to test 500 foot and 650 foot down spacing. Rex Energy expects to begin completion operations during the first quarter of 2014 and expects to place the wells into sales in the second quarter of 2014.

The company recently completed the three-well Ocel pad. The three wells on the pad were completed on 750 foot spacing and were drilled to an average total measured depth of approximately 12,700 feet with an average lateral length of approximately 4,400 feet and were completed with an average of 29 frac stages. The wells are expected to be placed into sales in the second quarter of 2014.

Appalachian Basin – Warrior South Prospect, Guernsey, Noble & Belmont Counties, Ohio

In the Warrior South Prospect, the company drilled five gross (3.9 net) wells in 2013, with five gross (3.9 net) wells fracture stimulated and eight gross (6.2 net) wells placed into service. The company had no wells awaiting completion as of December 31, 2013.

As previously reported, the company placed the five-well J. Anderson pad into sales during the fourth quarter of 2013. The wells produced at an average five-day sales rate (excluding downtime) of 1,886 Boe/d on an average 18/64 inch choke and have subsequently gone on to produce at an average 30-day sales rate (excluding downtime) of 1,721 Boe/d and a average last 5-day sales rate of 1,515 Boe/d. These wells, along with the initial three Warrior South Prospect wells placed into sales in June 2013, continue to flow into sales without processing constraints.

The company expects to start drilling operations on the six-well J. Hall pad, located in Guernsey County, in the second quarter of 2014. The six-wells on the J. Hall pad are expected to be drilled with an average lateral length of approximately 5,500 feet and are testing approximately 650 foot spacing between the laterals on this pad. The six-well J. Hall pad is expected to be completed in the third quarter of 2014 and placed into sales near the end of 2014. 

 
Total Operated Area – Ohio Utica Shale
  Wells Drilled Wells Fracture Stimulated Wells Placed Into Sales Wells Awaiting Completion
FY 2014 Forecast 11 17 11 0

Appalachian Basin – Well Cost Reduction

As previously reported, the company reduced its cost to drill and complete wells in the Appalachian Basin by approximately 10% in 2013 through a combination of improved pricing on service costs and operational efficiencies in both the Butler Operated Area and Ohio Utica Warrior Prospects. Rex Energy expects well costs in the Butler Operated Area to average approximately $5.9 million per well for a 4,000 foot lateral, a decrease of approximately 9% over the $6.5 million average per well from one year ago.

Appalachian Basin – Westmoreland, Clearfield and Centre Counties, Pennsylvania

In the company's non-operated area in Westmoreland County, Pennsylvania, where WPX Energy serves as the operator, WPX drilled nine wells and placed 10 wells into sales during 2013. As of December 31, 2013, WPX had five wells awaiting completion.

In the company's non-operated Westmoreland, Clearfield and Centre counties, Pennsylvania, the combined average production for a recent 5-day period was 55.2 MMcf/d.

 
Total Non-Operated Area – Westmoreland, Clearfield and Centre Counties, PA
  Wells Drilled Wells Fracture Stimulated Wells Placed Into Sales Wells Awaiting Completion
FY 2014 Forecast 1 4 9 0

Illinois Basin – Conventional

In the Illinois Basin, the company is continuing the conventional drilling and re-completion program it commenced in 2012 to increase its oil production. In 2013, the company drilled 19 vertical wells, performed completion or re-completion operations on 29 wells and placed 29 wells into sales.

Since the commencement of the Illinois Basin conventional program, the company's vertical well program has produced at a median 24-hour peak production rate of approximately 55-80 barrels per day and a median 30-day production rate of approximately 20-30 barrels per day.

To date, the recompletion program has produced at a median 24-hour peak production rate of approximately 30-70 barrels per day and a median 30-day production rate of approximately 10-40 barrels per day.

 
Total Operated Area – Illinois Conventional Program
  Wells Drilled Wells Fracture Stimulated(1) Wells Placed Into Sales Wells Awaiting Completion
FY 2014 Forecast 9 – 11 29 – 31 9 – 11 0
(1) Includes approximately 20 re-completions of existing wellbores

Water Service Subsidiary

The company's water service subsidiary, Keystone Clearwater Solutions, continues to expand its position as a premier water solutions provider in the Appalachian Basin. Over the past six months, Keystone Clearwater Solutions has made additional capital investments in bolt-on services such as waterline construction, frac tank rentals and water hauling. For 2013, Keystone Clearwater Solutions generated approximately $32.6 million of revenue and $6.7 million of EBITDAX (before inter-segment eliminations). For 2014, Keystone Clearwater Solutions has budgeted $8 - $12 million in capital expenditures to support its planned growth. Rex Energy holds a 60% membership interest in Keystone Clearwater Solutions.

Land Update

During 2013, the company spent approximately $35.6 million related to leasing and acreage acquisitions in the Appalachian and Illinois Basins. In the Butler Operated Area of the Appalachian Basin, the company leased approximately 9,500 gross (6,200 net) acres during 2013, increasing its total leasehold in the region to approximately 78,900 gross (54,600 net) acres, an increase of 13% over 2012. In addition, the company's leasing activity in 2013 added approximately 30.0 net potential Marcellus drilling locations and 29.0 net potential Upper Devonian drilling locations.

In the Ohio Utica, the company added approximately 1,500 gross (1,200 net) acres, increasing its total leasehold in the region to approximately 21,200 net acres. The 2013 leasing program and strategic acreage trades in the Ohio Utica added approximately 21.0 net drilling locations in the Ohio Utica.

In the Illinois Basin, the company added approximately 33,500 net acres in Illinois & Indiana, increasing its total operated leasehold in the region to approximately 62,200 net acres.

Liquidity Update

As of December 31, 2013, Rex Energy had approximately $2 million of cash and $59 million of its $325 million borrowing base outstanding under its senior secured credit facility. The company's borrowing base, which as of December 31, 2013 had $266 million available, is scheduled for its next redetermination in March 2014. As of December 31, 2013, the company had approximately $268 million of total liquidity.

First Quarter and Full Year 2014 Guidance

Rex Energy is providing its guidance for the first quarter and maintaining its full year 2014 guidance ($ in millions):

 
  1Q2014 Full Year 2014
Production 115.0 -- 118.0 MMcfe/d 143.0 -- 149.0 MMcfe/d
Lease Operating Expense $18.5 -- $19.5 $95.0 -- $101.0
Cash G&A $8.3 -- $9.3 $36.0 -- $39.0
Operational Capital Expenditures(1) -- $350.0 -- $365.0
(1) Land acquisition expense, capitalized interest and Keystone Clearwater Solutions are not included in the operational capital expenditures budget

The company currently expects that its production results for the second quarter and third quarter of 2014 will sequentially increase by 12% - 18% and 20% - 30%, respectively, when the Bluestone II processing facility is completed in its Butler Operated Area. These production results are based upon the expectation that the Bluestone II plant will be completed on May 15, 2014. The company currently expects to place 10 - 12 wells into sales in the second quarter of 2014 in its Butler Operated Area due to the additional processing capacity at the Bluestone II facility. In addition, the company currently expects to place nine Warrior North Prospect wells into sales during the second quarter of 2014. 

Conference Call Information

Management will host a live conference call and webcast on Thursday, February 20, 2014 at 10:00 a.m. Eastern to review fourth quarter and full year 2013 financial results and operational highlights. All financial results included in this release or discussed on the conference call are preliminary pending the completion of the 2013 audit by our independent auditors. The telephone number to access the conference call is (866) 437-1772. Presentation slides containing reference materials for the call and webcast will be available on the company's website, www.rexenergy.com, under the Investor Relations tab. The replay of the event and reference materials will be available on the company's website through March 20, 2014.

About Rex Energy Corporation

Rex Energy, headquartered in State College, Pennsylvania, is an independent oil and gas exploration and production company operating in the Appalachian and Illinois Basins within the United States. 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 Marcellus, Upper Devonian, and Utica shale development plans; drilling and completion schedules; anticipated fracture stimulation activities; expected timing for commissioning of the Bluestone II complex; expected dates for placement of wells into sales; anticipated well costs and potential savings opportunities; activities of our joint venture partner, WPX Energy; and the company's financial guidance, plans for capital expenditures and projections for 2014 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. These statements 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 demand for oil, NGLs and natural gas;
  • volatility in oil, NGL, and natural gas pricing;
  • new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our operations;
  • the geologic quality of the company's properties with regard to, among other things, the existence of hydrocarbons in economic quantities;
  • uncertainties inherent in the estimates of our oil and natural gas reserves;
  • our ability to increase oil and natural gas production and income through exploration and development;
  • drilling and operating 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 them, 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 acquisition;
  • the success of our business and financial strategies, and hedging strategies;
  • conditions in the domestic and global capital and credit markets and their effect on us;
  • the adequacy and availability of capital resources, credit, and liquidity including, but not limited to, access to additional borrowing capacity; and
  • uncertainties related to the legal and regulatory environment for our industry, and our own legal proceedings and their outcome.

The company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on the company's risks and uncertainties is available in the company's filings with the Securities and Exchange Commission.

Note on Hydrocarbon Volumes and Estimates

The estimates of proved reserves in this release are based on a reserve report of our independent external reserve engineers as of December 31, 2013. Generally, "proved reserves" are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (see Rule 4-10(a) of Regulation S-X for the SEC definition of "proved reserves"). The SEC permits publicly-reporting oil and gas companies to disclose "proved reserves" in their filings with the SEC. SEC rules also permit the disclosure of "probable" and "possible" reserves. Rex Energy discloses proved reserves but does not disclose probable or possible reserves. We use certain broad terms and other descriptions of volumes of potentially recoverable hydrocarbons in our public statements. These broad classifications do not constitute "reserves" as defined by the SEC and we do not attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines. We are prohibited from disclosing hydrocarbon quantities that do not constitute reserves in documents filed with the SEC.

We believe the data we prepared and supplied to our external reservoir engineers in connection with their preparation of the 12/31/2013 reserve report, and the assumptions, forecasts, and estimates contained therein, are reasonable, however, we cannot assure that they will prove to have been correct. Estimates of reserves can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

REX ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in Thousands, Except Share and Per Share Data)
     
     
  December 31, 2013  
  (Unaudited) December 31, 2012
ASSETS    
Current Assets    
Cash and Cash Equivalents  $ 1,900  $ 43,975
Accounts Receivable 38,863 24,980
Taxes Receivable 5,189 6,429
Short-Term Derivative Instruments 5,668 12,005
Current Deferred Tax Asset 3,451 --
Assets Held For Sale -- 2,279
Inventory, Prepaid Expenses and Other 2,207 1,316
Total Current Assets 57,278 90,984
Property and Equipment (Successful Efforts Method)    
Evaluated Oil and Gas Properties 749,680 485,448
Unevaluated Oil and Gas Properties 189,385 165,503
Other Property and Equipment 70,115 50,073
Wells and Facilities in Progress 76,545 92,913
Pipelines 7,678 6,116
Total Property and Equipment 1,093,403 800,053
Less: Accumulated Depreciation, Depletion and Amortization (190,521) (146,038)
Net Property and Equipment 902,882 654,015
Deferred Financing Costs and Other Assets – Net 11,993 10,029
Equity Method Investments 18,708 16,978
Long-Term Derivative Instruments 535 704
Total Assets  $ 991,396  $ 772,710
LIABILITIES AND EQUITY    
Current Liabilities    
Accounts Payable  $ 31,103  $ 29,448
Current Maturities of Long-Term Debt 6,743 1,686
Accrued Liabilities 54,450 23,019
Short-Term Derivative Instruments 4,663 1,389
Current Deferred Tax Liability -- 539
Liabilities Related to Assets Held for Sale -- 52
Total Current Liabilities 96,959 56,133
8.875% Senior Notes Due 2020 350,000 250,000
Premium (Discount) on Senior Notes 3,078 (1,742)
Senior Secured Line of Credit and Other Long-Term Debt 62,191 991
Long-Term Derivative Instruments 1,765 1,510
Long-Term Deferred Tax Liability 29,446 23,625
Other Deposits and Liabilities 4,992 5,675
Future Abandonment Cost 26,040 24,224
Total Liabilities 574,471 360,416
     
Stockholders' Equity    
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 54,186,490 shares issued and outstanding on December 31, 2013 and 53,213,264 shares issued and outstanding on December 31, 2012 54 52
Additional Paid-In Capital 456,554 451,062
Accumulated Deficit (41,725) (39,595)
Rex Energy Stockholders' Equity 414,883 411,519
Noncontrolling Interests 2,042 775
Total Stockholders' Equity 416,925 412,294
Total Liabilities and Owners' Equity  $ 991,396  $ 772,710
 
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,
  2013 2012 2013 2012
OPERATING REVENUE        
Oil, Natural Gas and NGL Sales  $ 63,472  $ 40,681  $ 213,919  $ 134,574
Field Services Revenue 8,619 4,413 23,812 13,403
Other Revenue 36 25 200 162
TOTAL OPERATING REVENUE 72,127 45,119 237,931 148,139
OPERATING EXPENSES        
Production and Lease Operating Expense 18,443 13,133 62,138 47,638
General and Administrative Expense 8,722 5,302 33,126 23,345
(Gain) Loss on Disposal of Assets 15 (52) 1,647 58
Impairment Expense 29,658 17,228 32,072 20,585
Exploration Expense 3,897 1,271 11,408 4,782
Depreciation, Depletion, Amortization and Accretion 23,577 13,140 63,944 45,437
Field Services Operating Expense 6,976 2,534 17,330 8,240
Other Operating Expense (318) 443 592 1,136
TOTAL OPERATING EXPENSES 90,970 52,999 222,257 151,221
INCOME (LOSS) FROM OPERATIONS (18,843) (7,880) 15,674 (3,082)
OTHER INCOME (EXPENSE)        
Interest Expense (6,769) (2,001) (22,782) (6,443)
Gain (Loss) on Derivatives, Net (1,485) 5,499 (2,908) 10,687
Other Income 4,612 6,308 6,653 98,549
Loss on Equity Method Investments (194) (183) (763) (3,921)
TOTAL OTHER INCOME (EXPENSE) (3,836) 9,623 (19,800) 98,872
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX (22,679) 1,743 (4,126) 95,790
Income Tax (Expense) Benefit 9,407 (2,781) 3,785 (38,549)
INCOME (LOSS) FROM CONTINUING OPERATIONS (13,272) (1,038) (341) 57,241
Loss From Discontinued Operations, Net of Income Taxes (692) (2,280) (232) (10,943)
NET INCOME (LOSS) (13,964) (3,318) (573) 46,298
Net Income Attributable to Noncontrolling Interests 645 303 1,557 819
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY  $ (14,609)  $ (3,621)  $ (2,130)  $ 45,479
Earnings per common share:        
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders  $ (0.26)  $ (0.03)  $ (0.04)  $ 1.09
         
Basic – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders (0.01) (0.04) 0.00 (0.21)
Basic – Net Income (Loss) Attributable to Rex Common Shareholders  $ (0.27)  $ (0.07)  $ (0.04)  $ 0.88
Basic – Weighted Average Shares of Common Stock Outstanding 52,705 52,278 52,572 51,543
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders  $ (0.26)  $ (0.03)  $ (0.04)  $ 1.08
         
Diluted – Net Loss From Discontinued Operations Attributable to Rex Common Shareholders (0.01) (0.04) 0.00 (0.21)
Diluted – Net Income (Loss) Attributable to Rex Common Shareholders  $ (0.27)  $ (0.07)  $ (0.04)  $ 0.87
Diluted – Weighted Average Shares of Common Stock Outstanding 52,705 52,278 52,572 52,025
 
REX ENERGY CORPORATION
CONSOLIDATED OPERATIONAL HIGHLIGHTS
UNAUDITED
         
  Three Months Ending Twelve Months Ending
  December 31, December 31,
  2013 2012 2013 2012
Oil, Natural Gas and NGL sales (in thousands):        
Oil and condensate sales  $ 23,330  $ 17,742  $ 86,959  $ 66,329
Natural gas sales 25,336 17,075 87,078 52,992
Natural gas liquid sales 14,806 5,864 39,882 15,253
Cash-settled derivatives:        
Crude oil (758) -- (3,495) (286)
Natural gas 3,054 2,701 10,885 16,095
Natural gas liquids (709) 162 (263) 410
Total oil, gas and NGL sales including cash settled derivatives  $ 65,059  $ 43,544  $ 221,046  $ 150,793
         
Production during the period:        
Oil and condensate (Bbls) 249,975 207,917 914,232 732,066
Natural gas (Mcf) 7,033,238 4,825,400 23,446,755 18,016,700
Natural gas liquids (Bbls) 270,111 121,479 819,670 358,049
Total (Mcfe)(1) 10,153,754 6,801,776 33,850,167 24,557,390
         
Production – average per day:        
Oil and condensate (Bbls) 2,717 2,260 2,505 2,000
Natural gas (Mcf) 76,448 52,450 64,238 49,226
Natural gas liquids (Bbls) 2,936 1,320 2,246 978
Total (Mcfe)(1) 110,366 73,932 92,744 67,097
         
Average price per unit:        
Realized crude oil price per Bbl – as reported  $ 93.33  $ 85.33  $ 95.12  $ 90.61
Realized impact from cash settled derivatives per Bbl (3.03) -- (3.82) (0.39)
Net realized price per Bbl  $ 90.30  $ 85.33  $ 91.30  $ 90.22
         
Realized natural gas price per Mcf – as reported  $ 3.60  $ 3.54  $ 3.71  $ 2.94
Realized impact from cash settled derivatives per Mcf 0.43 0.56 0.46 0.89
Net realized price per Mcf  $ 4.03  $ 4.10  $ 4.17  $ 3.83
         
Realized natural gas liquids price per Bbl – as reported  $ 54.81  $ 48.27  $ 48.66  $ 42.60
Realized impact from cash settled derivatives per Bbl (2.62) 1.33 (0.32) 1.15
Net realized price per Bbl  $ 52.19  $ 49.60  $ 48.34  $ 43.75
         
LOE/Mcfe  $ 1.82  $ 1.93  $ 1.84  $ 1.94
(1)Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe.
 
REX ENERGY CORPORATION
COMMODITY DERIVATIVES – HEDGE POSITION AS OF FEBRUARY 7, 2014
     
  2014 2015
Oil Derivatives (Bbls)    
Swap Contracts    
Volume 390,000(1) --
Price  $ 97.41 $ --
Collar Contracts    
Volume 60,000 --
Ceiling  $ 97.65 $ --
Floor  $ 90.00 $ --
Collar Contracts with Short Puts    
Volume 300,000  --
Ceiling  $ 103.57 $ --
Floor  $ 88.28 $ --
Short Put  $ 77.00 $ --
Put Spread Contracts    
Volume 168,000 --
Floor  $ 90.00 $ --
Short Put  $ 75.00 $ --
Natural Gas Derivatives (Mcf)    
Swap Contracts    
Volume 8,430,000(2) 3,600,000(3)
Price  $ 4.02 $ 4.13
Swaption Contracts    
Volume 2,400,000 --
Price  $ 4.45 $ --
Collar Contracts    
Volume 1,800,000 --
Ceiling  $ 4.43 $ --
Floor  $ 3.51 $ --
Collar Contracts with Short Puts    
Volume 10,500,000 5,400,000
Ceiling  $ 4.59  $ 4.57
Floor  $ 4.10  $ 4.14
Short Put  $ 3.34  $ 3.46
Call Contracts    
Volume 1,800,000 2,400,000
Ceiling  $ 5.00  $ 4.40
Natural Gas Liquids (Bbls)    
Swap Contracts    
Propane (C3)    
Volume 465,000 --
Price  $ 44.94 $ --
Butane (C4)    
Volume 60,000 --
Price  $ 55.65 $ --
Isobutane (IC4)    
Volume 60,000 --
Price  $ 56.28 $ --
Natural Gasoline (C5+)    
Volume 36,000 --
Price  $ 88.20  $ --
Natural Gas Basis (Mcf)    
Swap Contracts    
Dominion Appalachia    
Volume 7,800,000 600,000
Price  $ (0.35)  $ (0.35)
(1) Includes 360,000 Bbls of enhanced swaps
(2) Includes 3,600,000 Mcf of enhanced swaps
(3) Includes 2,400,000 Mcf of enhanced swaps

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 ($ in thousands):

  Three Months Ended December 31, Twelve Months Ended December 31,
  2013 2012 2013 2012
Net Income (Loss) From Continuing Operations  $ (13,272)  $ (1,038)  $ (341)  $ 57,241
Net Income Attributable to Noncontrolling Interests (645) (303) (1,557) (819)
Income (Loss) From Continuing Operations Attributable to Rex Energy  $ (13,917)  $ (1,341)  $ (1,898)  $ 56,422
         
(Gain) Loss on Derivatives, Net 1,485 (5,499) 2,908 (10,687)
Realized Gain on Derivatives 1,588 2,864 7,128 16,219
Add Back (Less) Unrealized (Gain) Loss from Financial Derivatives 3,073 (2,635) 10,036 5,532
Add Back Non-Recurring Losses(1) -- -- -- 2,809
Add Back Depletion, Depreciation, Amortization and Accretion 23,577 13,140 63,944 45,437
Add Back Non-Cash Compensation Expense 1,596 993 5,384 3,140
Add Back Interest Expense 6,769 2,001 22,782 6,443
Add Back Impairment Expense 29,658 17,228 32,072 20,585
Add Back Exploration Expenses 3,897 1,271 11,408 4,782
Less Gain on Disposal of Assets(2) (4,539) (7,220) (5,159) (99,349)
Less Non-Cash Portion of Noncontrolling Interests (227) (42) (631) (140)
Add Back (Less) Income Tax Expense (Benefit) (9,407) 2,781 (3,785) 38,549
Add Back Non-Cash Portion of Equity Method Investment 197 177 752 4,471
EBITDAX From Continuing Operations  $ 40,677  $ 26,353  $ 134,905  $ 88,681
Loss From Discontinued Operations (692) (2,281) (232) (10,943)
Less Non-Cash Compensation Income -- -- -- (31)
Add Back Impairment Expense -- 6,819 -- 19,770
Add Back Exploration Expenses -- 57 97 867
Add Back Loss on Disposal of Assets -- (2,274) (969) (2,126)
Add Back (Less) Income Tax Expense (Benefit) 692 (2,425) 1,005 (8,489)
Add EBITDAX From Discontinued Operations  $ --   $ (104)  $ (99)  $ (952)
EBITDAX (Non-GAAP)  $ 40,677  $ 26,249  $ 134,806  $ 87,729
(1) Includes $2.8 million related to the retroactive portion of the Pennsylvania Impact Fee for the nine months ended December 31, 2012
(2) Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million for the twelve months ended December 31, 2012, $4.6 million for the three months ended December 31, 2013 and $6.9 million for the twelve months ended December 31, 2013

Adjusted Net Income

"Adjusted Net Income" means, for any period, the sum of net income 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):

  For the Three Months Ended For the Twelve Months Ended
  December 31, December 31,
  2013 2012 2013 2012
Income (Loss) From Continuing Operations Before Income Taxes, as reported  $ (22,679)  $ 1,743  $ (4,126)  $ 95,790
(Gain) Loss on Derivatives, Net 1,485 (5,499) 2,908 (10,687)
Realized Gain on Derivatives 1,588 2,864 7,128 16,219
Add Back (Less) Unrealized (Gain) Loss from Financial Derivatives 3,073 (2,635) 10,036 5,532
Add Back Non-Recurring Losses -- -- -- 2,809
Add Back Impairment Expense 29,658 17,228 32,072 20,585
Add Back Dry Hole Expense 2,508 -- 3,005 --
Add Back Non-Cash Compensation Expense 1,596 993 5,384 3,140
Less Loss on Disposal of Assets(1) (4,539) (7,220) (5,159) (99,349)
Less Income Attributable to Noncontrolling Interests (645) (303) (1,557) (819)
Income Before Income Taxes, adjusted  $ 8,972  $ 9,806  $ 39,655  $ 27,688
Less Income Taxes, adjusted(2) (3,589) (3,903) (15,862) (11,020)
Adjusted Net Income  $ 5,383  $ 5,903  $ 23,793  $ 16,668
         
Basic – Adjusted Net Income Per Share  $ 0.10  $ 0.11  $ 0.45  $ 0.32
Basic – Weighted Average Shares of Common Stock Outstanding 52,705 52,278 52,572 51,543
         
(1) Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million for the twelve months ended December 31, 2012, $4.6 million for the three months ended December 31, 2013 and $6.9 million for the twelve months ended December 31, 2013
(2) Assumes 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):

  For the Three Months Ended December 31, For the Twelve Months Ended December 31,
  2013 2012 2013 2012
GAAP G&A  $ 8,722  $ 5,302  $ 33,126  $ 23,345
Non-Cash Compensation (1,596) (993) (5,384) (3,140)
Cash G&A  $ 7,126  $ 4,309  $ 27,742  $ 20,205

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):

  December 31, 2011 December 31, 2012 December 31, 2013
Drill-Bit Capital Deployed  $ 192.8  $ 176.9  $ 283.3
Acreage Acquisitions 78.7 51.0 35.6
Equity Method Investments, Noncontrolling Interests and Other(1) 30.9 11.0 18.7
All-In Capital Deployed  $ 302.4  $ 238.9  $ 337.6
(1) Includes capitalized interest, vehicles and corporate capital

A tabular presentation of Drill-Bit Finding and Development Costs is included below ($ in millions):

  December 31, 2011 December 31, 2012 December 31, 2013
Drill-Bit Capital Deployed  $ 192.8  $ 176.9  $ 283.3
Extensions and Discoveries (Bcfe) 155.8 196.6 312.5
Drill-Bit Finding and Development Cost ($/Mcfe)  $ 1.24  $ 0.90  $ 0.91
       
  December 31, 2013 Appalachian Basin
Drill-Bit Capital Deployed  $ 217.1
Extensions and Discoveries (Bcfe) 311.4
Drill-Bit Finding and Development Cost ($/Mcfe)  $ 0.70
For more information, please contact:

Mark Aydin
Manager, Investor Relations
(814) 278-7249