Exhibit 99.1
Rex Energy Reports Third Quarter 2013 Operational and Financial Results
| • | Average daily production from oil and NGLs reached a record level of 5.3 MBoe/d, a 21% increase over the second quarter of 2013 |
| • | Completed fourth Upper Devonian well, the Stebbins 2H; produced 5.5 MMcfe/d from a lateral length of only 2,825 feet, which equates to 7.8 MMcfe/d when adjusted to a 4,000 foot lateral |
| • | Completed fifth total and second “Super Rich” Upper Devonian well, the Perry Township 1HD; produced 1,314 BTU gas with 55% liquids |
| • | Two-well Lynn N&S pad produced into sales at a combined 5-day rate of 13.9 MMcfe/d from an average lateral length of only 2,762 feet, which equates to 20.1 MMcfe/d combined when adjusted to a 4,000 foot lateral |
| • | Completing 6-well Baillie Trust pad, testing Marcellus and Upper Devonian formations from the same pad; wells will be shut-in for 30-day resting period |
STATE COLLEGE, PA., November 5, 2013 (GLOBE NEWSWIRE) – Rex Energy Corporation (Nasdaq: REXX) today announced its third quarter 2013 operational and financial results.
Third Quarter Financial Results
Operating revenues from continuing operations for the three and nine months ended September 30, 2013 were $63.0 million and $165.8 million, respectively, which represents an increase of 62% and 61% over the same periods in 2012, respectively. Commodity revenues, including the net cash received from derivatives, were $58.8 million and $156.0 million for the three and nine months ended September 30, 2013, respectively, an increase of 51% and 46%, over the comparable periods of 2012, respectively. Commodity revenues, including the net cash received from derivatives, from oil and natural gas liquids (NGLs) represented 58% and 55% of total commodity revenues, including the net cash received from derivatives, for the three and nine months ended September 30, 2013, respectively.
Lease operating expense (LOE) from continuing operations was $17.2 million, or $1.89 per Mcfe for the quarter. For the nine months ended September 30, 2013, LOE was approximately $43.7 million, or $1.84 per Mcfe. Exploration expense for the quarter was $3.2 million, an increase of $2.0 million over the third quarter of 2012 and $1.0 million over the second quarter of 2013. This increase is due to additional microseismic and other geological expenditures as compared to previous periods.
Cash general and administrative (G&A) expenses from continuing operations, a non-GAAP measure which excludes stock-based compensation, were $7.5 million for the three months ended September 30, 2013, which represents a 4% decrease on a per unit basis as compared to the same period in 2012. For the nine months ended September 30, 2013, cash G&A expenses from continuing operations were $20.6 million, a 3% decrease on a per unit basis as compared to the same period in 2012. A reconciliation of cash G&A expenses to GAAP G&A expenses for the three and nine months ended September 30, 2013, as well as a discussion of the uses of the measure, is presented in the appendix attached to this release.
Income from continuing operations attributable to common shareholders for the three months ended September 30, 2013 was $1.6 million, or $0.03 per fully diluted share. Income from continuing operations attributable to common shareholders for the nine months ended September 30, 2013 was $12.5 million, or $0.24 per fully diluted share. Adjusted net income, a non-GAAP measure, for the three months ended
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September 30, 2013 was $6.3 million, or $0.12 per share. Adjusted net income for the nine months ended September 30, 2013 was $20.9 million, or $0.40 per share. A reconciliation of adjusted net income to GAAP net income for the third quarter of 2013, as well as a discussion of the uses of the measure, is presented in the appendix attached to this release.
EBITDAX from continuing operations, a non-GAAP measure, was $34.9 million for the third quarter and $94.2 million for the first nine months of 2013. This was an increase of 53% over the third quarter of 2012 and an increase of 51% over the first nine months of 2012. A reconciliation of EBITDAX to GAAP net income, as well as a discussion of the uses of the measure, is presented in the appendix attached to this release.
Production Update
Third quarter 2013 production volumes were 98.7 MMcfe/d, an increase of 39% over the third quarter of 2012 and 16% over the second quarter of 2013, consisting of 67.1 MMcf/d of natural gas and 5.3 MBoe/d of oil and NGLs. Average daily production from oil and NGLs increased 21% over the second quarter of 2013 and accounted for 32% of net production during the third quarter. Third quarter 2013 production of 98.7 MMcfe/d was slightly above the midpoint of the company’s previously announced guidance range of 97.0 – 100.0 MMcfe/d.
Third Quarter 2013 Capital Investments
For the third quarter of 2013, the company made operational capital investments of approximately $89.9 million, of which $71.0 million was used to fund Marcellus and Ohio Utica operations and $18.9 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 ten gross (6.8 net) wells, fracture stimulation of 19 gross (11.9 net) wells, placing 14 gross (9.5 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 four gross (4.0 net) wells, fracture stimulation of seven gross (7 net) wells, placing eight gross (8.0 net) wells into sales and other projects related to drilling and completing wells.
In addition to operational capital investments, investments for leasing and proved property acquisitions were $13.7 million and capitalized interest was $2.0 million for the third quarter of 2013. The company expects to provide a full update on leasing activity for the Illinois Basin and Appalachian Basin at year-end.
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’ “Super Frac” design.
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Appalachian Basin – Butler Operated Area, Pennsylvania
In the Butler Operated Area, the company drilled four gross (2.8 net) wells in the third quarter of 2013, with eight gross (5.6 net) wells fracture stimulated and nine gross (6.3 net) wells placed into sales. The company had nine gross (6.3 net) wells drilled and awaiting completion as of September 30, 2013.
Marcellus Results
The company placed into sales five (3.5 net) Marcellus wells in the Butler Operated Area in the third quarter of 2013. The average 5-day rate of these wells was 6.2 MMcfe/d from an average lateral length of 3,273 feet. Three of the five wells placed into sales were completed with lateral lengths below 3,300 feet. After adjusting the lateral lengths to 4,000 feet, the average 5-day sales rate would have been 7.8 MMcfe/d. In addition, the wells averaged 1,228 BTU and produced 51% liquids.
The tables below list, where available, the 5-day and 30-day sales rates for the company’s recent completions.
Upper Devonian Burkett Results
During the third quarter, the company placed into sales its fourth Upper Devonian Burkett well, the Stebbins 2H. The Stebbins 2H was drilled to a total measured depth of 8,711 feet with a horizontal lateral length of 2,825 feet and was completed in 19 stages. Based on composition analysis, the gas being produced is approximately 1,215 BTU.
The company also placed into sales the Perry Township 1HD, the company’s fifth Upper Devonian Burkett well and second “Super Rich” Upper Devonian Burkett well. The well was drilled to a total measured depth of 9,806 feet with a horizontal lateral length of 4,588 feet and was completed in 31 stages. Based on composition analysis, the gas being produced is approximately 1,314 BTU. By the end of 2013, the company expects to have seven Upper Devonian Burkett wells flowing into sales.
The company is completing the six-well Baillie Trust pad and the wells will be shut-in for a 30-day resting period. As previously reported, the six-well Baillie Trust pad includes two Upper Devonian Burkett wells in addition to four Marcellus wells. The two Upper Devonian laterals are offset above the laterals in the Marcellus formation. In addition, the company is testing 600 foot spacing between the Marcellus laterals. The six-well Baillie Trust pad was drilled with an average lateral length of 4,337 feet, which represents the company’s longest average lateral length for wells drilled from a single pad to date in the Butler Operated Area.
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The tables below list, 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) a | | | % Liquids | | | Total –
Ethane
Recovery
(Mcfe/d) | | | Total –
Adjusted
to 4,000’
Lateral | | | Total –
Ethane
Rejection
(Mcfe/d) | |
Lynn N&S 3H, 5H | | Marcellus | | | 3,650 | | | | 550 | | | | 47 | % | | | 6,946 | | | | 10,059 | | | | 4,909 | |
Rape 2H | | Marcellus | | | 3,360 | | | | 501 | | | | 47 | % | | | 6,362 | | | | 6,233 | | | | 4,530 | |
Warner 1H, 2H | | Marcellus | | | 2,476 | | | | 468 | | | | 53 | % | | | 5,282 | | | | 5,305 | | | | 3,683 | |
Stebbins 2H | | Upper Devonian | | | 2,838 | | | | 443 | | | | 48 | % | | | 5,492 | | | | 7,776 | | | | 3,916 | |
Perry Township 1HD | | “Super Rich” Upper Devonian | | | 2,379 | | | | 481 | | | | 55 | % | | | 5,267 | | | | 4,592 | | | | 3,762 | |
| a. | Condensate average was approximately 10 bbls/d for wells shown above |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
30-Day Sales Rate (Average Per Well) | |
Well Name | | Target Formation | | Natural
Gas
(Mcf/d) | | | NGLs /
Condensate
(Bbls/d) a | | | % Liquids | | | Total –
Ethane
Recovery
(Mcfe/d) | | | Total –
Adjusted
to 4,000’
Lateral | | | Total –
Ethane
Rejection
(Mcfe/d) | |
Rape 2H | | Marcellus | | | 2,944 | | | | 439 | | | | 47 | % | | | 5,576 | | | | 5,463 | | | | 3,971 | |
Warner 1H, 2H | | Marcellus | | | 2,152 | | | | 399 | | | | 53 | % | | | 4,547 | | | | 4,566 | | | | 3,156 | |
Stebbins 2H | | Upper Devonian | | | 2,381 | | | | 369 | | | | 48 | % | | | 4,592 | | | | 6,502 | | | | 3,268 | |
Perry Township 1HD | | “Super Rich” Upper Devonian | | | 1,819 | | | | 369 | | | | 55 | % | | | 4,030 | | | | 3,514 | | | | 2,880 | |
| a. | Condensate average was approximately 8 bbls/d for wells shown above |
| | | | | | | | |
Total Operated Area – Butler County, PA |
| | | Wells Drilled | | Wells Fracture
Stimulated | | Wells Placed Into
Sales | | Wells Awaiting
Completion |
YTD 2013 | | 17 | | 24 | | 19 | | 11 |
FY 2013 Forecast | | 19 | | 26 | | 23 | | 11 |
Appalachian Basin – Warrior North Prospect, Carroll County, Ohio
To date during 2013, Rex Energy has drilled six gross (six net) wells in the Warrior North Prospect, with four gross (four net) wells fracture stimulated and four gross (four net) wells placed into sales. The company expects to have five gross (five net) wells awaiting completion at the end of 2013. The three wells on the Ocel pad in the Warrior North Prospect were drilled during the third and fourth quarter of 2013. Completion operations on the three-well Ocel pad are expected to begin in early 2014 and the company expects these wells to be placed into sales during the second quarter of 2014.
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Appalachian Basin – Warrior South Prospect, Guernsey, Noble & Belmont Counties, Ohio
The company completed the five-well J. Anderson pad during the third quarter of 2013 and the wells are currently shut-in for a 60-day resting period. The wells were drilled to an average lateral length of approximately 4,250 feet and completed with an average of 28 total stages. The company expects the wells to be placed into sales in December 2013.
| | | | | | | | |
Total Operated Area – Ohio Utica Shale |
| | | Wells Drilled | | Wells Fracture
Stimulated | | Wells Placed Into
Sales | | Wells Awaiting
Completion |
YTD 2013 | | 11 | | 9 | | 7 | | 3 |
FY 2013 Forecast | | 13 | | 9 | | 12 | | 5 |
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 three wells and placed three wells into sales during the third quarter of 2013. WPX Energy currently plans to drill an additional two wells, fracture stimulate five wells and place into sales three wells in 2013. WPX Energy has adjusted its development schedule and certain production has been deferred to early 2014. WPX Energy estimates that at the end of 2013, five wells will be 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 44.8 MMcfe/d.
| | | | | | | | |
Total Non-Operated Area – Westmoreland, Clearfield and Centre Counties, PA |
| | | Wells Drilled | | Wells Fracture
Stimulated | | Wells Placed Into
Sales | | Wells Awaiting
Completion |
YTD 2013 | | 7 | | 6 | | 4 | | 8 |
FY 2013 Forecast | | 9 | | 11 | | 7 | | 5 |
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 the third quarter of 2013, the company drilled five vertical wells, performed completion or re-completion operations on seven wells and placed eight wells into sales.
The company has also completed its second horizontal well in the Illinois Basin. The well was drilled to a lateral length of approximately 1,500 feet and was fracture stimulated with 11 stages. The well is currently flowing back.
| | | | | | | | |
Total Operated Area – Illinois Conventional Program |
| | | Wells Drilled | | Wells Fracture
Stimulated | | Wells Placed Into
Sales | | Wells Awaiting
Completion |
YTD 2013 | | 19 | | 26 | | 25 | | 3 |
FY 2013 Forecast | | 19 | | 29 | | 29 | | 0 |
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Liquidity Update
During the third quarter of 2013, Rex Energy completed it semi-annual borrowing base redetermination for its senior secured credit facility and reaffirmed the existing borrowing base of $325 million. The company’s next scheduled redetermination will occur in the first quarter of 2014. As of September 30, 2013, the company had approximately $24 million of cash and no outstanding borrowings under its senior secured credit facility. As of November 1, 2013, the company has $19 million drawn on its senior secured credit facility.
2013 Capital Expenditures Budget
Rex Energy is increasing its capital expenditure budget for 2013 by $35 million to $290 – $310 million. The increase in planned capital expenditures is due to an increase in drilling and completion activity in the Appalachian Basin, incremental costs related to multi-zone exploration in the Illinois Basin, participation in non-operated drilling and completion costs in the Ohio Utica and further investments in the growth of the company’s water service subsidiary.
Fourth Quarter and Full Year 2013 Guidance
Rex Energy is providing its guidance for the fourth quarter and full year 2013 guidance ($ in millions):
| | | | |
| | | 4Q2013 | | Full Year 2013 |
Production | | 103.5 - 111.5 MMcfe/d | | 91.0 - 93.0 MMcfe/d |
Lease Operating Expense | | $18.3 - $19.3 | | $62 - $63 |
Cash G&A | | $6.4 - $7.4 | | $27 - $28 |
Operational Capital Expendituresa | | — | | $290 - $310 |
| a. | Land acquisition expense and capitalized interest is not included in the operational capital expenditures budget |
Production results for the fourth quarter of 2013 will be largely contingent upon the placed in sales date of the five-well J. Anderson pad in the Warrior South Prospect in the Ohio Utica.
Conference Call Information
Management will host a live conference call and webcast on Wednesday, November 6, 2013 at 10:00 a.m. Eastern to review third quarter financial results and operational highlights. All financial results included in this release or discussed on the conference call will remain subject to our independent auditor’s review. 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 December 6, 2013.
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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; potential liquids composition; expected dates for placement of wells into sales; activities of our joint venture partners, WPX Energy; leasing plans; conventional expansion plans and plans for horizontal drilling in the Illinois Basin; and the company’s financial guidance, plans for capital expenditures and projections for 2013 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. |
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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.
* * * * *
For more information, please contact:
Mark Aydin
Manager, Investor Relations
(814) 278-7249
maydin@rexenergy.com
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REX ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in Thousands, Except Share and Per Share Data)
| | | | | | | | |
| | | September 30, 2013
(Unaudited) | | | December 31, 2012 | |
| ASSETS | | | | | | | | |
Current Assets | | | | | | | | |
Cash and Cash Equivalents | | $ | 23,791 | | | $ | 43,975 | |
Accounts Receivable | | | 31,953 | | | | 24,980 | |
Taxes Receivable | | | 6,487 | | | | 6,429 | |
Short-Term Derivative Instruments | | | 5,741 | | | | 12,005 | |
Assets Held For Sale | | | — | | | | 2,279 | |
Inventory, Prepaid Expenses and Other | | | 1,713 | | | | 1,316 | |
| | | | | | | | |
Total Current Assets | | | 69,685 | | | | 90,984 | |
Property and Equipment (Successful Efforts Method) | | | | | | | | |
Evaluated Oil and Gas Properties | | | 685,891 | | | | 485,448 | |
Unevaluated Oil and Gas Properties | | | 189,144 | | | | 165,503 | |
Other Property and Equipment | | | 65,597 | | | | 50,073 | |
Wells and Facilities in Progress | | | 104,341 | | | | 92,913 | |
Pipelines | | | 7,888 | | | | 6,116 | |
| | | | | | | | |
Total Property and Equipment | | | 1,052,861 | | | | 800,053 | |
Less: Accumulated Depreciation, Depletion and Amortization | | | (182,094 | ) | | | (146,038 | ) |
| | | | | | | | |
Net Property and Equipment | | | 870,767 | | | | 654,015 | |
Deferred Financing Costs and Other Assets – Net | | | 12,208 | | | | 10,029 | |
Equity Method Investments | | | 18,902 | | | | 16,978 | |
Long-Term Derivative Instruments | | | 1,534 | | | | 704 | |
| | | | | | | | |
Total Assets | | $ | 973,096 | | | $ | 772,710 | |
| | | | | | | | |
| LIABILITIES AND EQUITY | | | | | | | | |
Current Liabilities | | | | | | | | |
Accounts Payable | | $ | 53,212 | | | $ | 31,134 | |
Accrued Liabilities | | | 65,815 | | | | 22,421 | |
Short-Term Derivative Instruments | | | 3,983 | | | | 1,389 | |
Current Deferred Tax Liability | | | 651 | | | | 539 | |
Liabilities Related to Assets Held for Sale | | | — | | | | 52 | |
| | | | | | | | |
Total Current Liabilities | | | 123,661 | | | | 55,535 | |
8.875% Senior Notes Due 2020 | | | 350,000 | | | | 250,000 | |
Premium (Discount) on Senior Notes | | | 3,162 | | | | (1,742 | ) |
Senior Secured Line of Credit and Other Long-Term Debt | | | 2,750 | | | | 991 | |
Long-Term Derivative Instruments | | | 445 | | | | 1,510 | |
Long-Term Deferred Tax Liability | | | 34,005 | | | | 23,625 | |
Other Deposits and Liabilities | | | 5,337 | | | | 5,675 | |
Future Abandonment Cost | | | 24,230 | | | | 24,822 | |
| | | | | | | | |
Total Liabilities | | | 543,590 | | | | 360,416 | |
| | |
Stockholders’ Equity | | | | | | | | |
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 53,619,870 shares issued and outstanding on September 30, 2013 and 53,213,264 shares issued and outstanding on December 31, 2012 | | | 52 | | | | 52 | |
Additional Paid-In Capital | | | 454,933 | | | | 451,062 | |
Accumulated Deficit | | | (27,116 | ) | | | (39,595 | ) |
| | | | | | | | |
Rex Energy Stockholders’ Equity | | | 427,869 | | | | 411,519 | |
Noncontrolling Interests | | | 1,637 | | | | 775 | |
| | | | | | | | |
Total Stockholders’ Equity | | | 429,506 | | | | 412,294 | |
Total Liabilities and Owners’ Equity | | $ | 973,096 | | | $ | 772,710 | |
| | | | | | | | |
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REX ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in Thousands, Except per Share Data)
| | | | | | | | | | | | | | | | |
| | | For the Three Months Ended
September 30, | | | For the Nine Months Ended
September 30, | |
| | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
OPERATING REVENUE | | | | | | | | | | | | | | | | |
Oil, Natural Gas and NGL Sales | | $ | 58,063 | | | $ | 34,711 | | | $ | 150,447 | | | $ | 93,893 | |
Field Services Revenue | | | 4,847 | | | | 4,170 | | | | 15,193 | | | | 8,990 | |
Other Revenue | | | 64 | | | | 48 | | | | 164 | | | | 137 | |
| | | | | | | | | | | | | | | | |
TOTAL OPERATING REVENUE | | | 62,974 | | | | 38,929 | | | | 165,804 | | | | 103,020 | |
OPERATING EXPENSES | | | | | | | | | | | | | | | | |
Production and Lease Operating Expense | | | 17,203 | | | | 11,234 | | | | 43,695 | | | | 34,505 | |
General and Administrative Expense | | | 8,826 | | | | 6,858 | | | | 24,404 | | | | 18,043 | |
Loss on Disposal of Assets | | | 140 | | | | 16 | | | | 1,632 | | | | 110 | |
Impairment Expense | | | 2,244 | | | | 292 | | | | 2,414 | | | | 3,357 | |
Exploration Expense | | | 3,242 | | | | 1,206 | | | | 7,511 | | | | 3,511 | |
Depreciation, Depletion, Amortization and Accretion | | | 16,267 | | | | 12,130 | | | | 40,367 | | | | 32,297 | |
Field Services Operating Expense | | | 3,652 | | | | 2,985 | | | | 10,354 | | | | 5,706 | |
Other Operating Expense | | | 19 | | | | 399 | | | | 910 | | | | 693 | |
| | | | | | | | | | | | | | | | |
TOTAL OPERATING EXPENSES | | | 51,593 | | | | 35,120 | | | | 131,287 | | | | 98,222 | |
INCOME FROM OPERATIONS | | | 11,381 | | | | 3,809 | | | | 34,517 | | | | 4,798 | |
OTHER INCOME (EXPENSE) | | | | | | | | | | | | | | | | |
Interest Expense | | | (6,181 | ) | | | (1,118 | ) | | | (16,013 | ) | | | (4,440 | ) |
Gain (Loss) on Derivatives, Net | | | (4,624 | ) | | | (5,893 | ) | | | (1,423 | ) | | | 5,188 | |
Other Income (Expense) | | | (30 | ) | | | (497 | ) | | | 2,041 | | | | 92,241 | |
Loss on Equity Method Investments | | | (207 | ) | | | (174 | ) | | | (569 | ) | | | (3,738 | ) |
| | | | | | | | | | | | | | | | |
TOTAL OTHER INCOME (EXPENSE) | | | (11,042 | ) | | | (7,682 | ) | | | (15,964 | ) | | | 89,251 | |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX | | | 339 | | | | (3,873 | ) | | | 18,553 | | | | 94,049 | |
Income Tax (Expense) Benefit | | | 1,493 | | | | 2,131 | | | | (5,622 | ) | | | (35,768 | ) |
| | | | | | | | | | | | | | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | | | 1,832 | | | | (1,742 | ) | | | 12,931 | | | | 58,281 | |
Income (Loss) From Discontinued Operations, Net of Income Taxes | | | — | | | | (258 | ) | | | 460 | | | | (8,662 | ) |
| | | | | | | | | | | | | | | | |
NET INCOME (LOSS) | | | 1,832 | | | | (2,000 | ) | | | 13,391 | | | | 49,619 | |
Net Income Attributable to Noncontrolling Interests | | | 258 | | | | 193 | | | | 912 | | | | 516 | |
| | | | | | | | | | | | | | | | |
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY | | $ | 1,574 | | | $ | (2,193 | ) | | $ | 12,479 | | | $ | 49,103 | |
| | | | | | | | | | | | | | | | |
Earnings per common share: | | | | | | | | | | | | | | | | |
Basic – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders | | $ | 0.03 | | | $ | (0.04 | ) | | $ | 0.23 | | | $ | 1.13 | |
Basic – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders | | | 0.00 | | | | 0.00 | | | | 0.01 | | | | (0.17 | ) |
| | | | | | | | | | | | | | | | |
Basic – Net Income (Loss) Attributable to Rex Common Shareholders | | $ | 0.03 | | | $ | (0.04 | ) | | $ | 0.24 | | | $ | 0.96 | |
| | | | | | | | | | | | | | | | |
Basic – Weighted Average Shares of Common Stock Outstanding | | | 52,626 | | | | 52,036 | | | | 52,560 | | | | 51,120 | |
Diluted – Net Income (Loss) From Continuing Operations Attributable to Rex Common Shareholders | | $ | 0.03 | | | $ | (0.04 | ) | | $ | 0.23 | | | $ | 1.11 | |
Diluted – Net Income (Loss) From Discontinued Operations Attributable to Rex Common Shareholders | | | 0.00 | | | | 0.00 | | | | 0.01 | | | | (0.17 | ) |
| | | | | | | | | | | | | | | | |
Diluted – Net Income (Loss) Attributable to Rex Common Shareholders | | $ | 0.03 | | | $ | (0.04 | ) | | $ | 0.24 | | | $ | 0.94 | |
| | | | | | | | | | | | | | | | |
Diluted – Weighted Average Shares of Common Stock Outstanding | | | 53,293 | | | | 52,805 | | | | 53,124 | | | | 52,018 | |
10
REX ENERGY CORPORATION
CONSOLIDATED OPERATIONAL HIGHLIGHTS
UNAUDITED
| | | | | | | | | | | | | | | | |
| | | Three Months Ending | | | Nine Months Ending | |
| | | September 30, | | | September 30, | |
| | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Oil, Natural Gas and NGL sales (in thousands): | | | | | | | | | | | | | | | | |
Oil and condensate sales | | $ | 25,843 | | | $ | 16,263 | | | $ | 63,629 | | | $ | 48,587 | |
Natural gas sales | | | 21,427 | | | | 14,492 | | | | 61,742 | | | | 35,917 | |
Natural gas liquid sales | | | 10,793 | | | | 3,956 | | | | 25,076 | | | | 9,389 | |
Cash-settled derivatives: | | | | | | | | | | | | | | | | |
Crude oil | | | (2,404 | ) | | | — | | | | (2,737 | ) | | | (286 | ) |
Natural gas | | | 3,227 | | | | 4,119 | | | | 7,831 | | | | 13,394 | |
Natural gas liquids | | | (82 | ) | | | 155 | | | | 446 | | | | 248 | |
| | | | | | | | | | | | | | | | |
Total oil, gas and NGL sales including cash settled derivatives | | $ | 58,804 | | | $ | 38,985 | | | $ | 155,987 | | | $ | 107,249 | |
| | | | |
Production during the period: | | | | | | | | | | | | | | | | |
Oil and condensate (Bbls) | | | 252,426 | | | | 182,759 | | | | 664,257 | | | | 524,149 | |
Natural gas (Mcf) | | | 6,169,918 | | | | 4,865,953 | | | | 16,413,517 | | | | 13,191,301 | |
Natural gas liquids (Bbls) | | | 233,350 | | | | 96,610 | | | | 549,559 | | | | 236,570 | |
| | | | | | | | | | | | | | | | |
Total (Mcfe)a | | | 9,084,574 | | | | 6,542,167 | | | | 23,696,413 | | | | 17,755,615 | |
| | | | |
Production – average per day: | | | | | | | | | | | | | | | | |
Oil and condensate (Bbls) | | | 2,744 | | | | 1,987 | | | | 2,433 | | | | 1,913 | |
Natural gas (Mcf) | | | 67,064 | | | | 52,891 | | | | 60,123 | | | | 48,143 | |
Natural gas liquids (Bbls) | | | 2,536 | | | | 1,050 | | | | 2,013 | | | | 863 | |
| | | | | | | | | | | | | | | | |
Total (Mcfe)a | | | 98,745 | | | | 71,111 | | | | 86,799 | | | | 64,802 | |
| | | | |
Average price per unit: | | | | | | | | | | | | | | | | |
Realized crude oil price per Bbl – as reported | | $ | 102.38 | | | $ | 89.00 | | | $ | 95.79 | | | $ | 92.70 | |
Realized impact from cash settled derivatives per Bbl | | | (9.52 | ) | | | — | | | | (4.12 | ) | | | (0.55 | ) |
| | | | | | | | | | | | | | | | |
Net realized price per Bbl | | $ | 92.86 | | | $ | 89.00 | | | $ | 91.67 | | | $ | 92.15 | |
| | | | |
Realized natural gas price per Mcf – as reported | | $ | 3.47 | | | $ | 2.98 | | | $ | 3.76 | | | $ | 2.72 | |
Realized impact from cash settled derivatives per Mcf | | | 0.52 | | | | 0.85 | | | | 0.48 | | | | 1.02 | |
| | | | | | | | | | | | | | | | |
Net realized price per Mcf | | $ | 3.99 | | | $ | 3.83 | | | $ | 4.24 | | | $ | 3.74 | |
| | | | |
Realized natural gas liquids price per Bbl – as reported | | $ | 46.25 | | | $ | 40.95 | | | $ | 45.63 | | | $ | 39.69 | |
Realized impact from cash settled derivatives per Bbl | | | (0.35 | ) | | | 1.60 | | | | 0.81 | | | | 1.05 | |
| | | | | | | | | | | | | | | | |
Net realized price per Bbl | | $ | 45.90 | | | $ | 42.55 | | | $ | 46.44 | | | $ | 40.74 | |
| | | | |
LOE/Mcfeb | | $ | 1.89 | | | $ | 1.72 | | | $ | 1.84 | | | $ | 1.79 | |
| a | Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe. |
| b | For the nine months ended September 30, 2012, excludes the retroactive accrual of Pennsylvania Impact fee, which equates to approximately $0.15 per Mcfe |
11
REX ENERGY CORPORATION
COMMODITY DERIVATIVES – HEDGE POSITION AS OF NOVEMBER 1, 2013
| | | | | | | | | | | | |
| | | 2013 | | | 2014 | | | 2015 | |
Oil Derivatives (Bbls) | | | | | | | | | | | | |
Swap Contracts | | | | | | | | | | | | |
Volume | | | 180,000 | | | | 390,000 | a | | | — | |
Price | | $ | 93.39 | | | $ | 97.41 | | | $ | — | |
Collar Contracts | | | | | | | | | | | | |
Volume | | | 15,000 | | | | 60,000 | | | | — | |
Ceiling | | $ | 97.00 | | | $ | 97.65 | | | $ | — | |
Floor | | $ | 92.00 | | | $ | 90.00 | | | $ | — | |
Collar Contracts with Short Puts | | | | | | | | | | | | |
Volume | | | 15,000 | | | | 372,000 | b | | | — | |
Ceiling | | $ | 100.00 | | | $ | 103.85 | | | $ | — | |
Floor | | $ | 85.00 | | | $ | 87.60 | | | $ | — | |
Short Put | | $ | 65.00 | | | $ | 76.61 | | | $ | — | |
Put Spread Contracts | | | | | | | | | | | | |
Volume | | | — | | | | 168,000 | | | | — | |
Floor | | $ | — | | | $ | 90.00 | | | $ | — | |
Short Put | | $ | — | | | $ | 75.00 | | | $ | — | |
Natural Gas Derivatives (Mcf) | | | | | | | | | | | | |
Swap Contracts | | | | | | | | | | | | |
Volume | | | 2,460,000 | | | | 6,630,000 | c | | | 1,800,000 | d |
Price | | $ | 3.94 | | | $ | 4.00 | | | $ | 4.17 | |
Swaption Contracts | | | | | | | | | | | | |
Volume | | | 300,000 | | | | 1,200,000 | | | | — | |
Price | | $ | 4.50 | | | $ | 4.51 | | | $ | — | |
Collar Contracts | | | | | | | | | | | | |
Volume | | | 390,000 | | | | 1,800,000 | | | | — | |
Ceiling | | $ | 5.02 | | | $ | 4.43 | | | $ | — | |
Floor | | $ | 4.50 | | | $ | 3.51 | | | $ | — | |
Put Spread Contracts | | | | | | | | | | | | |
Volume | | | 450,000 | | | | — | | | | — | |
Floor | | $ | 5.00 | | | $ | — | | | $ | — | |
Short Put | | $ | 3.75 | | | $ | — | | | $ | — | |
Put Contracts | | | | | | | | | | | | |
Volume | | | 660,000 | e | | | — | | | | — | |
Floor | | $ | 5.00 | | | $ | — | | | $ | — | |
Collar Contracts with Short Puts | | | | | | | | | | | | |
Volume | | | 630,000 | | | | 7,800,000 | | | | 2,400,000 | |
Ceiling | | $ | 4.88 | | | $ | 4.59 | | | $ | 4.63 | |
Floor | | $ | 4.17 | | | $ | 4.08 | | | $ | 4.16 | |
Short Put | | $ | 3.35 | | | $ | 3.32 | | | $ | 3.40 | |
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| | | | | | | | | | | | |
a) Includes 360,000 Bbls of optimized swaps with an $80.83 average short put b) Includes deferred premiums of $5.53/bbl which will be paid at settlement c) Includes 1.8 Bcf of optimized swaps with an $3.32 average short put d) Includes 0.6 Bcf of optimized swaps with an average $3.25 short put e) Includes deferred premiums of $0.65/mcf which will be paid at settlement | | | | | | | | | |
| | | |
Call Contracts | | | | | | | | | | | | |
Volume | | | — | | | | 1,800,000 | | | | — | |
Ceiling | | $ | — | | | $ | 5.00 | | | $ | — | |
Natural Gas Liquids (Bbls) | | | | | | | | | | | | |
Swap Contracts | | | | | | | | | | | | |
Propane (C3) | | | | | | | | | | | | |
Volume | | | 99,000 | | | | 261,000 | | | | — | |
Price | | $ | 42.00 | | | $ | 43.26 | | | $ | — | |
Butane (C4) | | | | | | | | | | | | |
Volume | | | 6,000 | | | | — | | | | — | |
Price | | $ | 66.36 | | | $ | — | | | $ | — | |
Isobutane (IC4) | | | | | | | | | | | | |
Volume | | | 6,000 | | | | — | | | | — | |
Price | | $ | 69.72 | | | $ | — | | | $ | — | |
Natural Gasoline (C5+) | | | | | | | | | | | | |
Volume | | | 36,000 | | | | 36,000 | | | | — | |
Price | | $ | 88.20 | | | $ | 88.20 | | | $ | — | |
Natural Gas Basis (Mcf) | | | | | | | | | | | | |
Swap Contracts | | | | | | | | | | | | |
Dominion Appalachia | | | | | | | | | | | | |
Volume | | | 1,800,000 | | | | 4,800,000 | | | | 600,000 | |
Price | | $ | (0.35 | ) | | $ | (0.36 | ) | | $ | (0.35 | ) |
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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, 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.
14
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
September 30, | | | Nine Months Ended
September 30, | |
| | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Net Income (Loss) From Continuing Operations | | $ | 1,832 | | | $ | (1,742 | ) | | $ | 12,931 | | | $ | 58,281 | |
Net Income Attributable to Noncontrolling Interests | | | (258 | ) | | | (193 | ) | | | (912 | ) | | | (516 | ) |
| | | | | | | | | | | | | | | | |
Income (Loss) From Continuing Operations Attributable to Rex Energy | | $ | 1,574 | | | $ | (1,935 | ) | | $ | 12,019 | | | $ | 57,765 | |
| | | | |
(Gain) Loss on Derivatives, Net | | | 4,624 | | | | 5,893 | | | | 1,423 | | | | (5,188 | ) |
Realized Gain on Derivatives | | | 741 | | | | 4,273 | | | | 5,540 | | | | 13,355 | |
| | | | | | | | | | | | | | | | |
Add Back Unrealized Loss from Financial Derivatives | | | 5,365 | | | | 10,166 | | | | 6,963 | | | | 8,167 | |
Add Back Non-Recurring Lossesa | | | — | | | | — | | | | — | | | | 2,809 | |
Add Back Depletion, Depreciation, Amortization and Accretion | | | 16,267 | | | | 12,130 | | | | 40,367 | | | | 32,297 | |
Add Back Non-Cash Compensation Expense | | | 1,365 | | | | 1,305 | | | | 3,788 | | | | 2,147 | |
Add Back Interest Expense | | | 6,181 | | | | 1,118 | | | | 16,013 | | | | 4,440 | |
Add Back Impairment Expense | | | 2,244 | | | | 292 | | | | 2,414 | | | | 3,357 | |
Add Back Exploration Expenses | | | 3,242 | | | | 1,206 | | | | 7,511 | | | | 3,511 | |
Add Back (Less) Loss (Gain) on Disposal of Assetsb | | | 140 | | | | 526 | | | | (620 | ) | | | (92,128 | ) |
Less Non-Cash Portion of Noncontrolling Interests | | | (198 | ) | | | (36 | ) | | | (404 | ) | | | (64 | ) |
Add Back (Less) Income Tax Expense (Benefit) | | | (1,493 | ) | | | (2,131 | ) | | | 5,622 | | | | 35,768 | |
Add Back Non-Cash Portion of Equity Method Investment | | | 195 | | | | 174 | | | | 555 | | | | 4,294 | |
| | | | | | | | | | | | | | | | |
EBITDAX From Continuing Operations | | $ | 34,882 | | | $ | 22,815 | | | $ | 94,228 | | | $ | 62,363 | |
Net Income (Loss) From Discontinued Operations | | | — | | | | (258 | ) | | | 460 | | | | (8,662 | ) |
Less Non-Cash Compensation Income | | | — | | | | (43 | ) | | | — | | | | (31 | ) |
Add Back Impairment Expense | | | — | | | | — | | | | — | | | | 12,951 | |
Add Back Exploration Expenses | | | — | | | | 329 | | | | 97 | | | | 810 | |
Add Back (Less) Loss (Gain) on Disposal of Assets | | | — | | | | 4 | | | | (969 | ) | | | 148 | |
Add Back (Less) Income Tax Expense (Benefit) | | | — | | | | (203 | ) | | | 313 | | | | (6,064 | ) |
| | | | | | | | | | | | | | | | |
Add EBITDAX From Discontinued Operations | | $ | — | | | $ | (171 | ) | | $ | (99 | ) | | $ | (848 | ) |
EBITDAX (Non-GAAP) | | $ | 34,882 | | | $ | 22,644 | | | $ | 94,129 | | | $ | 61,515 | |
| | | | | | | | | | | | | | | | |
| a) | Includes $2.8 million related to the retroactive portion of the Pennsylvania Impact Fee for the nine months ended September 30, 2012 |
| b) | Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million for the nine months ended September 30, 2012 and $2.3 million for the nine months ended September 30, 2013 |
15
Adjusted Net Income
“Adjusted Net Income” means, for any period, the sum of net income for the period plus the following expenses, charges or income, in each case, to the extent deducted from or added to net income in the period: unrealized losses from financial derivatives, non-cash compensation expense, dry hole expenses, disposals of assets, impairment and other one-time or non-recurring charges, minus all gains from unrealized financial derivatives, disposal of assets and deferred income tax benefits, added to net income. Adjusted Net Income is used as a financial measure by Rex Energy’s management team and by other users of its financial statements, to analyze its financial performance without regard to non-cash deferred taxes and non-cash unrealized losses or gains from oil and gas derivatives. Adjusted Net Income is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring the company’s performance.
Rex Energy has reported Adjusted Net Income because it believes that this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance. You should carefully consider the specific items included in the company’s computation of this measure. You are cautioned that Adjusted Net Income as reported by Rex Energy may not be comparable in all instances to that reported by other companies.
To compensate for these limitations, the company believes it is important to consider both net income determined under GAAP and Adjusted Net Income.
The following table presents a reconciliation of Rex Energy’s net income from continuing operations to its adjusted net income for each of the periods presented ($ in thousands):
| | | | | | | | | | | | | | | | |
| | | For the Three Months Ended | | | For the Nine Months Ended | |
| | | September 30, | | | September 30, | |
| | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
Income (Loss) From Continuing Operations Before Income Taxes, as reported | | $ | 339 | | | $ | (3,873 | ) | | $ | 18,553 | | | $ | 94,049 | |
| | | | |
(Gain) Loss on Derivatives, Net | | | 4,624 | | | | 5,893 | | | | 1,423 | | | | (5,188 | ) |
Realized Gain on Derivatives | | | 741 | | | | 4,273 | | | | 5,540 | | | | 13,355 | |
| | | | | | | | | | | | | | | | |
Add Back Unrealized Loss from Financial Derivatives | | | 5,365 | | | | 10,166 | | | | 6,963 | | | | 8,167 | |
Add Back Non-Recurring Losses | | | — | | | | — | | | | — | | | | 2,809 | |
Add Back Impairment Expense | | | 2,244 | | | | 292 | | | | 2,414 | | | | 3,357 | |
Add Back Dry Hole Expense | | | — | | | | — | | | | 497 | | | | 306 | |
Add Back Non-Cash Compensation Expense | | | 1,365 | | | | 1,305 | | | | 3,788 | | | | 2,147 | |
Add Back (Less) (Gain) Loss on Disposal of Assets a | | | 140 | | | | 526 | | | | (620 | ) | | | (92,128 | ) |
Less Income Attributable to Noncontrolling Interests | | | (258 | ) | | | (193 | ) | | | (912 | ) | | | (516 | ) |
| | | | | | | | | | | | | | | | |
Income Before Income Taxes, adjusted | | $ | 9,195 | | | $ | 8,223 | | | $ | 30,683 | | | $ | 18,191 | |
Less Income Taxes, adjustedb | | | 2,933 | | | | 4,243 | | | | 9,788 | | | | 6,949 | |
| | | | | | | | | | | | | | | | |
Adjusted Net Income | | $ | 6,262 | | | $ | 3,980 | | | $ | 20,895 | | | $ | 11,242 | |
| | | | |
Basic – Adjusted Net Income Per Share | | $ | $0.12 | | | $ | 0.08 | | | $ | $0.40 | | | $ | 0.22 | |
| | | | | | | | | | | | | | | | |
Basic – Weighted Average Shares of Common Stock Outstanding | | | 52,626 | | | | 52,036 | | | | 52,560 | | | | 51,120 | |
16
| a | Includes gain on sale of Keystone Midstream Services, LLC of approximately $92.7 million for the nine months ended September 30, 2012 and $2.3 million for the nine months ended September 30, 2013 |
| b | The income tax adjustment for the three months ended September 30, 2013 represents the effective rate for the nine months ended September 30, 2013 |
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
September 30, | | | For the Nine Months Ended
September 30, | |
| | | 2013 | | | 2012 | | | 2013 | | | 2012 | |
GAAP G&A | | $ | 8,826 | | | $ | 6,858 | | | $ | 24,404 | | | $ | 18,043 | |
Non-Cash Compensation | | | (1,365 | ) | | | (1,305 | ) | | | (3,788 | ) | | | (2,147 | ) |
| | | | | | | | | | | | | | | | |
Cash G&A | | $ | 7,461 | | | $ | 5,553 | | | $ | 20,616 | | | $ | 15,896 | |
| | | | | | | | | | | | | | | | |
17
