Exhibit 99.1
Rex Energy Corporation Announces Fourth Quarter and Year-End 2009 Results
STATE COLLEGE, Pa., Mar 2, 2010 (GLOBE NEWSWIRE) — Rex Energy Corporation (“Rex Energy”) (Nasdaq:REXX) today announced fourth quarter and year-end 2009 results. Highlights include:
| | • | | Proved reserves increased 90%, with all-in reserve replacement of 410%. Four-year compounded annual growth rate in proved reserves was 31%. |
| | • | | All-in finding and development cost averaged $1.60 per Mcfe, including acreage costs, and $1.32 per Mcfe excluding acreage. |
| | • | | Natural gas production grew by 46% year-over-year. Overall production grew by 3% year-over-year. |
| | • | | Natural gas production in the fourth quarter grew by 78% year-over-year and 20% over the third quarter of 2009. |
| | • | | Exit rate natural gas production grew by 69%, with overall exit rate production growing by 7%. |
| | • | | Financial discipline was maintained as total debt to market capitalization was 5%. |
| | • | | Drilled and completed seven horizontal Marcellus Shale wells with average gross proven reserves of 3.2 Bcfe per well. |
Financial results for 2009 were negatively impacted by the significant decline in the average oil and gas prices when compared to 2008. Year-over-year, oil prices after the effects of hedging fell by 18% and natural gas prices after the effects of hedging fell by 28%. The decline in prices more than offset the increase in production resulting in oil and gas sales revenue (including cash settled derivatives) decreasing 20% to $54.4 million. Reported GAAP earnings resulted in a loss of $16.2 million or a diluted loss per share of $0.44. Adjusted net loss comparable to analysts’ estimates, a non-GAAP measure, was $5.4 million with diluted loss per share of $0.15. Cash provided by operating activities was $20.8 million, and EBITDAX from continuing operations, a non-GAAP measure, was $22.5 million. EBITDAX excluding a one-time legal accrual of $925,000 for an expected legal settlement was $23.4 million.
Total production for 2009 increased by 3%, to an average of 16.1 MMcfe per day, over 2008. Natural gas and natural gas liquids (“NGLs”) production for the year grew by 50% to an average of 4.3 MMcfe per day. Oil production for the year declined 7% to an average of 1,973 Bbls per day.
Commenting on the fourth quarter and year-end results, Benjamin W. Hulburt, the company’s President and CEO, said, “It was a challenging year, but we were able to increase production and nearly double reserves while maintaining a conservative balance sheet through careful debt management and a structured hedging program. I am extremely pleased with the company’s strong finish in 2009 and believe that we are poised for tremendous growth throughout 2010.”
Revenues, including the effects of cash settled derivatives, were $14.9 million in the fourth quarter 2009. Realized natural gas prices, after the effects of cash settled derivatives, declined 21% to $6.19 per Mcf, and realized oil prices, after the effects of cash settled derivatives, increased 6% to $66.44 per Bbl when compared to the fourth quarter of 2008. EBITDAX, a non-
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GAAP measure, was $4.5 million and excluding a one-time legal accrual of $925,000, EBITDAX was $5.4 million. Cash provided by operations was $8.0 million in the fourth quarter of 2009. Reported GAAP earnings resulted in a loss of $4.6 million during the quarter, and adjusted earnings comparable to analysts’ estimates, a non-GAAP measure, were a loss of $2.6 million in the fourth quarter.
Production in the fourth quarter of 2009 increased 7% over the fourth quarter 2008 to 17.2 MMcfe per day. Production for the month of December 2009 increased 7% over the same period in 2008 to 18.1 MMcfe per day. Natural gas and natural gas liquids production grew by 25% and oil production was flat when comparing the fourth and third quarter of 2009.
Summary of Changes in Proved Reserves
Total proved oil and natural gas reserves as of December 31, 2009 increased 90% from 2008 year-end estimates to 125.2 Bcfe. Rex Energy’s proved reserves estimates for all of its oil and gas properties were prepared in accordance with the definitions and guidelines of the U.S. Securities and Exchange Commission (“SEC”) by the independent reservoir engineering firm of Netherland, Sewell & Associates, Inc. (“Netherland”).
The company replaced 410% of production in 2009. At year-end, reserves were 45% natural gas, 6% NGLs and 49% oil by volume, and the reserve life index stood at 20.1 years based on fourth quarter production rates. The percentage of proved undeveloped reserves increased to 46% compared to 35% as of December 31, 2008. For year-end 2009, new SEC rules were implemented requiring that the reserve calculations be based on the arithmetic 12-month average beginning-of-the-month prices throughout the year, as opposed to the previous method which required the use of year-end prices. For crude oil and NGL volumes, the average West Texas Intermediate posted price of $57.65 per Bbl was adjusted by county for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.87 per million British thermal units (“MMBTU”) was adjusted by county for energy content, transportation fees, and regional price differentials. In addition to the new SEC rules regarding oil and gas prices, the SEC also implemented new rules regarding proved undeveloped reserves. Using the new SEC rules for both oil and gas prices and proved undeveloped reserves, the company’s finding and development cost from all sources, including leasehold additions and all price and performance revisions averaged $1.60 per Mcfe. Using the new SEC rules for both oil and gas prices and proved undeveloped reserves, the company’s finding and development cost from all sources and excluding acquisitions averaged $1.32 per Mcfe.
In addition to the SEC proved reserves, Netherland also prepared estimates of Rex Energy’s year-end proved reserves using two alternative commodity price assumptions. The Flat Case alternative assumptions used the previous SEC rules for oil and gas which were based on the posted spot prices as of December 31, 2009 for both oil and gas and held constant during the life of the properties. For oil and NGL volumes, the average West Texas Intermediate posted price of $76.00 per Bbl was adjusted by county for quality, transportation fees, and regional price differentials. For gas volumes, the Henry Hub spot price of $5.79 per MMBTU was adjusted by county for energy content, transportation fees, and regional price differentials.
The NYMEX Case alternative assumptions were based on the forward closing prices on the New York Mercantile Exchange for crude oil and natural gas as of December 31, 2009. For oil and NGL volumes, the price was based on a crude oil price which increased from $79.36 per Bbl to $101.92 per Bbl during the life of the properties and was adjusted by county for quality,
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transportation fees and regional price differentials. For gas volumes, the price was based on a natural gas price which increased from $5.57 per MMBTU to $9.08 per MMBTU over the life of the properties and was adjusted by county for energy content, transportation fees, and regional price differentials.
The following tables summarize the company’s proved reserves using each of the three cases:
| | | | | | | | | | | | | | | | | |
| SEC Case Proved Reserves |
| | | | | | | |
Area | | Oil
(MMBbl) | | NGL
(MMBbl) | | Natural
Gas
(Bcf) | | Bcfe | | % Oil &
NGLs | | | % Proved
Developed | | | PV-10 ($
in millions) |
Appalachia | | — | | 1.2 | | 56.2 | | 63.4 | | 11 | % | | 26 | % | | $ | 45.1 |
Illinois | | 10.3 | | — | | — | | 61.8 | | 100 | % | | 83 | % | | $ | 145.4 |
| | | | | | | | | | | | | | | | | |
Total | | 10.3 | | 1.2 | | 56.2 | | 125.2 | | 55 | % | | 54 | % | | $ | 190.5 |
|
| Flat Case Proved Reserves |
| | | | | | | |
Area | | Oil
(MMBbl) | | NGL
(MMBbl) | | Natural
Gas
(Bcf) | | Bcfe | | % Oil &
NGLs | | | % Proved
Developed | | | PV-10 ($
in millions) |
Appalachia | | — | | 1.2 | | 60.2 | | 67.4 | | 11 | % | | 27 | % | | $ | 108.3 |
Illinois | | 11.8 | | — | | — | | 70.8 | | 100 | % | | 84 | % | | $ | 245.3 |
| | | | | | | | | | | | | | | | | |
Total | | 11.8 | | 1.2 | | 60.2 | | 138.2 | | 56 | % | | 56 | % | | $ | 353.6 |
|
| NYMEX Case Proved Reserves |
| | | | | | | |
Area | | Oil
(MMBbl) | | NGL
(MMBbl) | | Natural
Gas
(Bcf) | | Bcfe | | % Oil &
NGLs | | | % Proved
Developed | | | PV-10 ($
in millions) |
Appalachia | | — | | 1.3 | | 62.9 | | 70.7 | | 11 | % | | 27 | % | | $ | 145.1 |
Illinois | | 12.9 | | — | | — | | 77.4 | | 100 | % | | 84 | % | | $ | 318.3 |
| | | | | | | | | | | | | | | | | |
Total | | 12.9 | | 1.3 | | 62.9 | | 148.1 | | 58 | % | | 55 | % | | $ | 463.4 |
Operational Highlights
In the Appalachian Region, Rex Energy has drilled and completed nine horizontal Marcellus Shale wells to date. The company drilled and completed two of these as test wells in a different zone of the shale, which resulted in lower recoveries. Excluding the two test wells, the seven day average test rate after peak production was reached has averaged 3.1 MMcfe per day with an average lateral length of 2,200 feet. The company has experimented with six to twelve stage fracture stimulations. The average gross EUR of these wells was estimated to be 3.2 Bcfe per well at an average cost of $4.6 million. The following table summarizes the company’s Marcellus shale horizontal drilling to date by county excluding the two test wells:
| | | | | | | | | | | | | |
County | | # of
Wells | | 7-Day Avg.
Test Rate
(MMcfe/d) | | Lateral
Length
(feet) | | # Frac
Stages | | Estimated
EUR
(Bcfe) | | D&C Cost
($/millions) |
Butler | | 1 | | 3.1 | | 1,894 | | 8 | | 3.5 | | $ | 4.6 |
Clearfield | | 2 | | 3.4 | | 2,368 | | 12 | | 3.0 | | $ | 4.7 |
Westmoreland | | 4 | | 2.9 | | 2,257 | | 8 | | 3.1 | | $ | 4.5 |
| | | | | | | | | | | | | |
Total/Average | | 7 | | 3.1 | | 2,173 | | 9.3 | | 3.2 | | $ | 4.6 |
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Currently, Rex Energy is running two horizontal drilling rigs in the play. The company recently completed the drilling of two horizontal wells in Butler County. The wells have an average lateral length of 3,500 feet and were drilled in under 21 days per well. The company expects to simultaneously fracture stimulate these wells during the first quarter of 2009. The company has budgeted $4.0 million per well for its 2010 wells and it expects the wells to have average lateral lengths of 3,000 to 4,000 feet. The company is currently drilling two wells in Butler County and one well in Westmoreland County. During 2010, the company expects to drill and complete 10 gross (10 net) operated horizontal Marcellus Shale wells, and to participate in 9 gross (4.5 net) horizontal Marcellus Shale wells with our partner.
Mr. Hulburt continued, “The build-out of our Marcellus midstream infrastructure is progressing as scheduled. We expect our two Clearfield County wells to be connected to our initial gathering system in April 2010. In Butler County, we expect our midstream joint venture to put our cryogenic processing facility into operation during the fourth quarter of 2010. We expect the plant will have a processing capacity of 40 MMcf per day. We plan to install compression to permit the plant to process 20 MMcf per day initially, which will be scaled up as additional wells are brought online.”
The company has continued to lease additional acreage in its three Marcellus Shale project areas in southwestern and central Pennsylvania. Rex Energy’s current total acreage under control in the Marcellus Shale fairway is 68,700 acres, an increase of approximately 15% compared with the company’s previous leasing update in January 2010. The net acreage amount excludes approximately 22,000 acres, which can be earned by Williams pursuant to the Participation and Exploration Agreement entered into on June 18, 2009, and includes approximately 8,300 acres covered by oil and gas leases that are pending title verification and final closing.
In the Illinois Basin, Rex Energy is currently drilling the wells for its Middagh Unit, the company’s first operationally sized ASP unit in the Bridgeport Sandstone within the Lawrence Field. The company has recently completed additional core flood testing with ASP chemicals at the University of Texas, which resulted in oil recoveries of up to 90% of residual oil after waterflooding, representing a 10% increase over previous testing. Rex Energy expects to begin injecting ASP chemicals in the unit during the second quarter of 2010.
(EBITDAX and Earnings/Net Loss Comparable to Analyst Estimates are non-GAAP financial measures. Please see the accompanying definitions and tables for the reconciliation of each of these non-GAAP measures. The company has classified all first quarter 2009 and prior period amounts related to its operations in the Southwestern Region as discontinued operations due to the sale of these assets during the first quarter of 2009. Please see the accompanying table for the reconciliation of the reported GAAP amounts to the amounts that would have been reported if Southwestern Region operations were included in continuing operations.)
Conference Call Information
A conference call to review the fourth quarter and year-end 2009 financial and operational results is scheduled for Wednesday, March 3, 2010 at 10:00 a.m. Eastern time. A webcast of the conference call will be broadcast live and available for replay on the company’s website at www.rexenergy.com in the Events and Presentations section under the Investor Relations tab.
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Furthermore, Rex Energy will be incorporating slides with the conference call and webcast, which are now available on the company’s website under the Investor Relations tab.
About Rex Energy Corporation
Rex Energy is an independent oil and gas company operating in the Illinois Basin and the Appalachian Basin of the United States. The company has pursued a balanced growth strategy of exploiting its sizable inventory of lower risk developmental drilling locations, pursuing its higher potential exploration drilling prospects and actively seeking to acquire complementary oil and natural gas properties.
Forward-Looking Statements
Except for historical information, statements made in this release about the proposed offering are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions and the company’s future performance are subject to a wide range of business risks and uncertainties, and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward-looking statements, including, but not limited to, adverse economic conditions in the United States and globally; the difficult and adverse conditions in the domestic and global capital and credit markets; domestic and global demand for oil and natural gas; volatility in the prices the company receives for oil and natural gas; the effects of government regulation, permitting and other legal requirements; the quality of the company’s properties with regard to, among other things, the existence of reserves in economic quantities; uncertainties about the estimates of the company’s oil and natural gas reserves; the company’s ability to increase production and oil and natural gas income through exploration and development; the company’s ability to successfully apply horizontal drilling techniques and tertiary recovery methods; the number of well locations to be drilled, the cost to drill and the time frame within which they will be drilled; drilling and operating risks; the availability of equipment, such as drilling rigs and transportation pipelines; changes in the company’s drilling plans and related budgets; the adequacy of capital resources and liquidity including, but not limited to, access to additional borrowing capacity; and uncertainties associated with the company’s 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.
The company’s internal estimates of reserves may be subject to revision and may be different from estimates by the company’s external reservoir engineers at year end. Although the company believes the expectations and forecasts reflected in these and other forward-looking statements are reasonable, it can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.
For more information, contact:
Julia Williams, Manager, Investor Relations
(814) 278-7130
jwilliams@rexenergycorp.com
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REX ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
($ in Thousands, Except per Share Data)
| | | | | | | | |
| | | December 31, 2009 | | | December 31, 2008 | |
ASSETS | | | | | | | | |
Current Assets | | | | | | | | |
Cash and Cash Equivalents | | $ | 5,582 | | | $ | 7,046 | |
Accounts Receivable | | | 14,333 | | | | 5,840 | |
Short-Term Derivative Instruments | | | 2,124 | | | | 8,153 | |
Deferred Taxes | | | 2,827 | | | | — | |
Inventory, Prepaid Expenses and Other | | | 1,111 | | | | 3,068 | |
| | | | | | | | |
Total Current Assets | | | 25,977 | | | | 24,107 | |
Property and Equipment (Successful Efforts Method) | | | | | | | | |
Evaluated Oil and Gas Properties | | | 206,676 | | | | 185,108 | |
Unevaluated Oil and Gas Properties | | | 80,218 | | | | 65,564 | |
Other Property and Equipment | | | 25,082 | | | | 19,388 | |
Wells and Facilities in Progress | | | 34,086 | | | | 29,629 | |
Pipelines | | | 5,167 | | | | 3,457 | |
| | | | | | | | |
Total Property and Equipment | | | 351,229 | | | | 303,146 | |
Less: Accumulated Depreciation, Depletion and Amortization | | | (75,968 | ) | | | (53,288 | ) |
| | | | | | | | |
Net Property and Equipment | | | 275,261 | | | | 249,858 | |
Assets Held for Sale | | | — | | | | 18,852 | |
Intangible Assets and Other Assets– Net | | | 1,199 | | | | 1,628 | |
Long-Term Derivative Instruments | | | 1,673 | | | | 7,561 | |
Investment in RW Gathering | | | 840 | | | | — | |
| | | | | | | | |
Total Assets | | $ | 304,950 | | | $ | 302,006 | |
| | | | | | | | |
| | |
LIABILITIES AND EQUITY | | | | | | | | |
Current Liabilities | | | | | | | | |
Accounts Payable | | $ | 16,386 | | | $ | 7,180 | |
Accrued Expenses | | | 9,333 | | | | 7,388 | |
Short-Term Derivative Instruments | | | 6,692 | | | | — | |
Current Deferred Tax Liability | | | — | | | | 2,785 | |
| | | | | | | | |
Total Current Liabilities | | | 32,411 | | | | 17,353 | |
Senior Secured Line of Credit and Long-Term Debt | | | 23,049 | | | | 15,000 | |
Long-Term Derivative Instruments | | | 426 | | | | 1,476 | |
Long-Term Deferred Tax Liability | | | 6,894 | | | | 11,995 | |
Other Deposits and Liabilities | | | 5,830 | | | | 7,322 | |
Liabilities Related to Assets Held for Sale | | | — | | | | 1,838 | |
Future Abandonment Cost | | | 16,143 | | | | 15,174 | |
| | | | | | | | |
Total Liabilities | | $ | 84,753 | | | $ | 70,158 | |
Commitments and Contingencies | | | | | | | | |
Owners’ Equity | | | | | | | | |
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 36,817,812 shares issued and outstanding on December 31, 2009 and 36,589,712 shares issued and outstanding on December 31, 2008 | | | 37 | | | | 37 | |
Additional Paid-In Capital | | | 292,372 | | | | 291,133 | |
Accumulated Deficit | | | (75,555 | ) | | | (59,322 | ) |
| | | | | | | | |
Rex Energy Owners’ Equity | | | 216,854 | | | | 231,848 | |
Noncontrolling Interests | | | 3,343 | | | | — | |
| | | | | | | | |
Total Owners’ Equity | | | 220,197 | | | | 231,848 | |
| | | | | | | | |
Total Liabilities and Owners’ Equity | | $ | 304,950 | | | $ | 302,006 | |
| | | | | | | | |
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REX ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ and Shares in Thousands, Except per Share Data)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
OPERATING REVENUE | | | | | | | | | | | | | | | | |
Oil and Natural Gas Sales | | $ | 15,208 | | | $ | 13,248 | | | $ | 48,534 | | | $ | 84,013 | |
Other Revenue | | | 57 | | | | 30 | | | | 157 | | | | 123 | |
| | | | | | | | | | | | | | | | |
TOTAL OPERATING REVENUES | | $ | 15,265 | | | $ | 13,278 | | | $ | 48,691 | | | $ | 84,136 | |
| | | | |
OPERATING EXPENSES | | | | | | | | | | | | | | | | |
Production and Lease Operating Expenses | | | 6,107 | | | | 6,095 | | | | 22,157 | | | | 26,511 | |
General and Administrative Expense | | | 4,916 | | | | 4,303 | | | | 15,858 | | | | 15,185 | |
Loss on Disposal of Assets | | | 10 | | | | 42 | | | | 427 | | | | 6,468 | |
Impairment Expense | | | 760 | | | | 71,349 | | | | 1,625 | | | | 71,349 | |
Exploration Expense | | | 876 | | | | 866 | | | | 2,080 | | | | 3,261 | |
Depreciation, Depletion, Amortization and Accretion | | | 6,782 | | | | 23,543 | | | | 25,205 | | | | 37,904 | |
| | | | | | | | | | | | | | | | |
TOTAL OPERATING EXPENSES | | $ | 19,451 | | | $ | 106,198 | | | $ | 67,352 | | | $ | 160,678 | |
| | | | | | | | | | | | | | | | |
| | | | |
LOSS FROM OPERATIONS | | $ | (4,186 | ) | | $ | (92,920 | ) | | $ | (18,661 | ) | | $ | (76,542 | ) |
| | | | |
OTHER INCOME (EXPENSE) | | | | | | | | | | | | | | | | |
Interest Income | | | 4 | | | | 8 | | | | 7 | | | | 328 | |
Interest Expense | | | (221 | ) | | | (247 | ) | | | (833 | ) | | | (1,091 | ) |
Gain (Loss) on Derivatives, net | | | (3,060 | ) | | | 57,326 | | | | (7,913 | ) | | | 27,328 | |
Other Expense | | | (132 | ) | | | (107 | ) | | | (170 | ) | | | (168 | ) |
| | | | | | | | | | | | | | | | |
TOTAL OTHER INCOME (EXPENSE) | | $ | (3,409 | ) | | $ | 56,980 | | | $ | (8,909 | ) | | $ | 26,397 | |
| | | | |
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX | | | (7,595 | ) | | | (35,940 | ) | | | (27,570 | ) | | | (50,145 | ) |
Income Tax Benefit | | | 2,998 | | | | 3,378 | | | | 11,002 | | | | 9,167 | |
| | | | | | | | | | | | | | | | |
LOSS FROM CONTINUING OPERATIONS | | $ | (4,597 | ) | | $ | (32,562 | ) | | $ | (16,568 | ) | | $ | (40,978 | ) |
Income (Loss) from Discontinued Operations, Net of Income Taxes | | | — | | | | (7,741 | ) | | | 323 | | | | (7,704 | ) |
| | | | | | | | | | | | | | | | |
NET LOSS | | $ | (4,597 | ) | | $ | (40,303 | ) | | $ | (16,245 | ) | | $ | (48,682 | ) |
Net Loss Attributable to Noncontrolling Interests | | | 12 | | | | — | | | | 12 | | | | — | |
| | | | | | | | | | | | | | | | |
NET LOSS ATTRIBUTABLE TO REX ENERGY | | $ | (4,585 | ) | | $ | (40,303 | ) | | $ | (16,233 | ) | | $ | (48,682 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Earnings per common share – basic and diluted: | | | | | | | | | | | | | | | | |
Loss from continuing operations attributable to Rex common shareholders | | $ | (0.12 | ) | | $ | (0.89 | ) | | $ | (0.45 | ) | | $ | (1.18 | ) |
Income (loss) from discontinued operations attributable to Rex common shareholders | | | — | | | | (0.21 | ) | | | 0.01 | | | | (0.22 | ) |
| | | | | | | | | | | | | | | | |
Net loss attributable to Rex common shareholders | | $ | (0.12 | ) | | $ | (1.10 | ) | | $ | (0.44 | ) | | $ | (1.40 | ) |
Basic—weighted average shares of common stock outstanding | | | 36,818 | | | | 36,590 | | | | 36,806 | | | | 34,595 | |
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REX ENERGY CORPORATION
CONSOLIDATED OPERATIONAL HIGHLIGHTS
(Unaudited)
| | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
| | | 2009 | | | 2008 | | | 2009 | | 2008 | |
| | | | |
Oil and gas sales (in thousands): | | | | | | | | | | | | | | | |
Oil sales | | | 12,848 | | | | 11,213 | | | | 41,881 | | | 74,230 | |
Natural gas sales | | | 2,202 | | | | 2,035 | | | | 6,460 | | | 9,783 | |
Natural gas liquid sales | | | 158 | | | | — | | | | 193 | | | — | |
Cash-settled derivatives: | | | | | | | | | | | | | | | |
Crude oil a | | | (1,052 | ) | | | 1,431 | | | | 2,626 | | | (15,613 | ) |
Natural gas | | | 793 | | | | 106 | | | | 3,216 | | | (554 | ) |
| | | | | | | | | | | | | | | |
Total oil and gas sales including cash settled derivatives | | | 14,949 | | | | 14,785 | | | | 54,376 | | | 67,846 | |
| | | | |
Production during the period: | | | | | | | | | | | | | | | |
Oil (Bbls) | | | 177,543 | | | | 201,495 | | | | 720,010 | | | 776,185 | |
Natural gas (Mcf) | | | 484,091 | | | | 2,72,598 | | | | 1,510,500 | | | 1,036,891 | |
Natural gas liquids (Bbls) | | | 5,905 | | | | — | | | | 7,750 | | | — | |
| | | | | | | | | | | | | | | |
Total (Mcfe)b | | | 1,584,782 | | | | 1,481,568 | | | | 5,877,060 | | | 5,694,001 | |
| | | | |
Production – average per day: | | | | | | | | | | | | | | | |
Oil (Bbls) | | | 1,930 | | | | 2,190 | | | | 1,973 | | | 2,127 | |
Natural gas (Mcf) | | | 5,262 | | | | 2,963 | | | | 4,138 | | | 2,841 | |
Natural gas liquids (Bbls) | | | 64 | | | | — | | | | 21 | | | — | |
| | | | | | | | | | | | | | | |
Total (Mcfe)b | | | 17,226 | | | | 16,104 | | | | 16,102 | | | 15,600 | |
| | | | |
Average price per unit: | | | | | | | | | | | | | | | |
Realized crude oil price per Bbl – as reported | | $ | 72.37 | | | $ | 55.65 | | | $ | 58.17 | | $ | 95.63 | |
Realized impact from cash settled derivatives per Bbl | | | (5.93 | ) | | | (7.10 | ) | | | 3.65 | | | (20.11 | ) |
| | | | | | | | | | | | | | | |
Net realized price per Bbl | | $ | 66.44 | | | $ | 62.75 | | | $ | 61.82 | | $ | 75.52 | |
| | | | |
Realized natural gas price per Mcf – as reported | | $ | 4.55 | | | $ | 7.47 | | | $ | 4.28 | | $ | 9.43 | |
Realized impact from cash settled derivatives per Mcf | | | 1.64 | | | | 0.39 | | | | 2.13 | | | (0.53 | ) |
| | | | | | | | | | | | | | | |
Net realized price per Mcf | | $ | 6.19 | | | $ | 7.86 | | | $ | 6.41 | | $ | 8.90 | |
| | | | |
Realized natural gas liquids price per Bbl – as reported | | $ | 26.76 | | | | — | | | $ | 24.90 | | | — | |
Realized impact from cash settled derivatives per Bbl | | | — | | | | — | | | | — | | | — | |
| | | | | | | | | | | | | | | |
Net realized price per Bbl | | $ | 26.76 | | | | — | | | $ | 24.90 | | | — | |
| a | Excludes $4.6 million for the early settlement of certain oil derivatives associated with 2011 redeemed in the first quarter of 2009 |
| b | Natural gas is converted at the rate of one Mcf to one Mcfe. Oil and natural gas liquids are converted at a rate of one Bbl to six Mcfe |
Page8 of14
REX ENERGY CORPORATION
OIL AND GAS DERIVATIVES AS OF DECEMBER 31, 2009
(Unaudited)
| | | | | | | | | | | |
Year | | Volume | | % of Current
Production | | | Average Floor | | Average
Ceiling |
| | | | |
Oil | | | | | | | | | | | |
2010 | | 588 MBbls | | 83 | % | | $ | 62.71 | | $ | 79.31 |
2011 | | 228 MBbls | | 32 | % | | $ | 63.42 | | $ | 108.87 |
2012 | | 72 MBbls | | 10 | % | | $ | 60.00 | | $ | 127.00 |
| | | | |
Natural Gas & NGLs | | | | | | | | | | | |
2010 | | 2.28 Bcf | | 93 | % | | $ | 6.29 | | $ | 8.91 |
2011 | | 1.80 Bcf | | 73 | % | | $ | 6.47 | | $ | 10.47 |
2012 | | 0.60 Bcf | | 24 | % | | $ | 5.60 | | $ | 7.86 |
The following table has been added to provide better clarification of components of Gain (Loss) on Derivatives, net under Other Income (Expense) on the Consolidated Statements of Operations for each of the periods presented (in thousands):
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Realized Gains (Losses) from Financial Derivatives: | | | | | | | | | | | | | | | | |
Crude Oil Derivatives | | $ | (1,052 | ) | | $ | 1,431 | | | $ | 7,198 | | | $ | (15,613 | ) |
Natural Gas Derivatives | | | 793 | | | | 106 | | | | 3,216 | | | | (554 | ) |
Interest Rate Derivatives | | | (203 | ) | | | (69 | ) | | | (769 | ) | | | (251 | ) |
| | | | | | | | | | | | | | | | |
Total Realized Gains (Losses) from Financial Derivatives | | $ | (462 | ) | | $ | 1,468 | | | $ | 9,645 | | | $ | (16,418 | ) |
| | | | |
Unrealized Gains (Losses) from Financial Derivatives: | | | | | | | | | | | | | | | | |
Crude Oil Derivatives | | $ | (3,344 | ) | | $ | 54,019 | | | $ | (18,445 | ) | | $ | 41,447 | |
Natural Gas Derivatives | | | 592 | | | | 2,654 | | | | 427 | | | | 3,470 | |
Interest Rate Derivatives | | | 154 | | | | (815 | ) | | | 460 | | | | (1,171 | ) |
| | | | | | | | | | | | | | | | |
Total Unrealized Gains (Losses) from Financial Derivatives | | $ | (2,598 | ) | | $ | 55,858 | | | $ | (17,558 | ) | | $ | 43,746 | |
| | | | | | | | | | | | | | | | |
| | | | |
Gain (Loss) on Derivatives, net | | $ | (3,060 | ) | | $ | 57,326 | | | $ | (7,913 | ) | | $ | 27,328 | |
| | | | | | | | | | | | | | | | |
Page9 of14
Non-GAAP Financial Measures
Finding and Developing Costs
REX ENERGY CORPORATION
FINDING AND DEVELOPING COSTS
(Unaudited, $ and Volumes in Thousands, Except per Mcfe Data)
| | | | | | | | | | | | | |
| | | 2009 | | 2008 | | | 2007 | | Combined |
Costs Incurred: | | | | | | | | | | | | | |
Acquisitions | | | | | | | | | | | | | |
Unproved leasehold acquired | | $ | 17,949 | | $ | 57,224 | | | $ | 4,141 | | $ | 79,314 |
Proved oil and gas properties | | | 39 | | | 4,950 | | | | 1,090 | | | 6,079 |
| | | | |
Development expenditures | | | 26,921 | | | 76,109 | | | | 24,180 | | | 127,210 |
Exploration expenditures | | | 6,210 | | | 5,571 | | | | 5,676 | | | 17,457 |
Gas gathering facilities: | | | | | | | | | | | | | |
Acquisitions | | | 296 | | | — | | | | — | | | 296 |
Development | | | 1,241 | | | — | | | | — | | | 1,241 |
| | | | | | | | | | | | | |
Total costs incurred per 10-K | | $ | 52,656 | | $ | 143,854 | | | $ | 35,087 | | $ | 231,597 |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Changes in future development costs | | $ | 51,419 | | $ | 13,473 | | | $ | 15,444 | | $ | 80,336 |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Total finding and development costs | | $ | 104,075 | | $ | 157,327 | | | $ | 50,531 | | $ | 311,933 |
| | | | | | | | | | | | | |
| | | | |
Reserve Adds (MMcfe): | | | | | | | | | | | | | |
Extensions, discoveries and additions | | | 24,068 | | | 992 | | | | 2,051 | | | 27,111 |
Purchases | | | — | | | 17,683 | | | | 506 | | | 18,189 |
Revisions | | | 41,048 | | | (31,489 | ) | | | 12,261 | | | 21,820 |
| | | | | | | | | | | | | |
Total reserve adds | | | 65,116 | | | (12,814 | ) | | | 14,818 | | | 67,121 |
| | | | |
Finding and development costs per Mcfe | | | | | | | | | | | | | |
Total overall finding and development costs | | $ | 1.60 | | $ | (12.28 | ) | | $ | 3.41 | | $ | 4.65 |
Finding and development costs excluding acquisitions | | $ | 1.32 | | $ | (3.12 | ) | | $ | 3.17 | | $ | 4.63 |
EBITDAX
“EBITDAX”, for any defined 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, depreciation, depletion, amortization, accretion, unrealized losses from financial derivatives, 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 Rex Energy’s management team and by other users of its financial statements, such as the company’s commercial bank lenders, to analyze such things as:
| | • | | Rex Energy’s operating performance and return on capital in comparison to those of other companies in its industry, without regard to financial or capital structure; |
| | • | | The financial performance of the company’s assets and valuation of the entity, without regard to financing methods, capital structure or historical cost basis; |
| | • | | Rex Energy’s ability to generate cash sufficient to pay interest costs, support its indebtedness and make cash distributions to its stockholders; and |
| | • | | The viability of acquisitions and capital expenditure projects and the overall rates or 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) in measuring the company’s performance, nor used as an exclusive measure of cash flow, 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 the company’s statements of cash flows.
Page10 of14
Rex Energy has reported EBITDAX because it is a financial measure used by its 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 the company’s computations of EBITDAX. While Rex Energy has disclosed its EBITDAX to permit a more complete comparative analysis of its operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by the company may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not by fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.
Rex Energy believes that EBITDAX assists its lenders and investors in comparing a company’s performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because the company may borrow money to finance its operations, interest expense is a necessary element of its costs and ability to generate cash available for distribution. Because Rex Energy uses capital assets, depreciation and amortization are also necessary elements of its costs. Additionally, the company is required to pay federal and state taxes, which are necessary elements of its costs. Therefore, any measures that exclude these elements have material limitations.
To compensate for these limitations, Rex Energy believes it is important to consider both net income (loss) determined under GAAP and EBITDAX to evaluate its performance.
The following table presents a reconciliation of the company’s net (loss) from continuing operations to its EBITDAX from continuing operations for each of the periods presented ($ in thousands):
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Net Loss From Continuing Operations | | $ | (4,597 | ) | | $ | (32,562 | ) | | $ | (16,568 | ) | | $ | (40,978 | ) |
Add Back Depletion, Depreciation, Amortization & Accretion | | | 6,782 | | | | 23,543 | | | | 25,205 | | | | 37,904 | |
Add Back Non-Cash Compensation Expense | | | 589 | | | | 1,423 | | | | 1,557 | | | | 2,990 | |
Add Back Interest Expense | | | 221 | | | | 247 | | | | 833 | | | | 1,091 | |
Add Back Impairment Expense | | | 760 | | | | 71,349 | | | | 1,625 | | | | 71,349 | |
Add Back Exploration Expense | | | 876 | | | | 866 | | | | 2,080 | | | | 3,261 | |
Less Interest Income | | | (4 | ) | | | (8 | ) | | | (7 | ) | | | (328 | ) |
Add Back Loss on Interest Rate Swap | | | 203 | | | | 69 | | | | 769 | | | | 251 | |
Add Back Loss on Disposal of Assets | | | 10 | | | | 42 | | | | 427 | | | | 6,468 | |
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives | | | 2,598 | | | | (55,858 | ) | | | 17,558 | | | | (43,746 | ) |
Add Back Noncontrolling Interest Share of Net Loss | | | 12 | | | | — | | | | 12 | | | | — | |
Less Income Tax Benefit | | | (2,998 | ) | | | (3,378 | ) | | | (11,002 | ) | | | (9,167 | ) |
| | | | | | | | | | | | | | | | |
EBITDAX From Continuing Operations | | $ | 4,452 | | | $ | 5,733 | | | $ | 22,489 | | | $ | 29,095 | |
| | | | | | | | | | | | | | | | |
Page11 of14
Earnings Comparable with Analyst Estimates
“Earnings Comparable with Analyst Estimates” 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: deferred income taxes, unrealized gains or losses from financial derivatives, minus gains from unrealized financial derivatives, minus deferred income tax benefits, added to net income. Earnings Comparable with Analyst Estimates, as defined above, 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. Earnings Comparable with Analyst Estimates 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 Earnings Comparable with Analyst Estimates 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 Earnings Comparable with Analyst Estimates 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 Earnings Comparable with Analyst Estimates.
The following table presents a reconciliation of Rex Energy’s net income (loss) from continuing operations to its Earnings Comparable with Analyst Estimates for each of the periods presented ($ in thousands):
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | | |
Net Loss From Continuing Operations | | $ | (4,597 | ) | | $ | (32,562 | ) | | $ | (16,568 | ) | | $ | (40,978 | ) |
Add Back (Less) Unrealized Loss (Gain) from Financial Derivatives | | | 2,598 | | | | (55,858 | ) | | | 17,558 | | | | (43,746 | ) |
Add Back Dry Hole and Impairment Expense | | | 848 | | | | 71,349 | | | | 1,713 | | | | 71,351 | |
Add Back Non-cash Compensation Expense | | | 589 | | | | 1,423 | | | | 1,557 | | | | 2,990 | |
Add Back Loss on Disposal of Assets | | | 10 | | | | 42 | | | | 427 | | | | 6,468 | |
Add Back Legal Accrual for Expected Settlement | | | 925 | | | | — | | | | 925 | | | | — | |
Add Back Noncontrolling Interest Share of Net Gain | | | 12 | | | | — | | | | 12 | | | | — | |
Less Income Tax Benefit | | | (2,998 | ) | | | (3,378 | ) | | | (11,002 | ) | | | (9,167 | ) |
| | | | | | | | | | | | | | | | |
Net Loss From Continuing Operations Comparable to Analysts Estimates | | $ | (2,613 | ) | | $ | (18,984 | ) | | $ | (5,378 | ) | | $ | (13,082 | ) |
| | | | | | | | | | | | | | | | |
Page12 of14
PV-10
PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue before income tax and asset retirement obligations of Rex Energy’s estimated proved reserves. PV-10 is a non-GAAP financial measure because it excludes the effects of income taxes and asset retirement obligations. The company believes that PV-10 is a useful measure for evaluating the relative monetary significance of their oil and natural gas properties. Further, investors may use the measure as a basis for comparison of the relative size and value of Rex Energy’s reserves to other companies. The company uses this measure when assessing the potential return on investment related to their oil and natural gas properties. PV-10 should not be considered as an alternative to standardized measure of discounted future net cash flows as defined under GAAP. The following table shows the reconciliation of standardized measure of discounted future net cash flows for each case to PV-10.
| | | | | | | | | |
Reconciliation of PV-10 |
| | | SEC
Case | | Flat
Case | | NYMEX
Case |
| | | ($ in millions) |
Standardized measure of discounted future net cash flows | | $ | 144.4 | | $ | 241.4 | | $ | 301.5 |
Discounted future cash flow from income taxes | | $ | 30.0 | | $ | 96.1 | | $ | 145.8 |
Discounted future cash flow for abandonment | | $ | 16.1 | | $ | 16.1 | | $ | 16.1 |
| | | | | | | | | |
Discounted future net cash flow before income taxes (PV-10) | | $ | 190.5 | | $ | 353.6 | | $ | 463.4 |
| | | | | | | | | |
Page13 of14
Discontinued Operations
On March 24, 2009, Rex Energy completed the divestiture of its Southwestern Region operations, predominately located in the Permian Basin in the states of Texas and New Mexico. The company received net cash proceeds of approximately $17.3 million, plus the assumption of certain liabilities, based on an effective date of October 1, 2008.
Pursuant to accounting rules for discontinued operations, these assets were classified as Assets Held for Sale on the Consolidated Balance Sheet as of December 31, 2008, and results of operations are reflected as discontinued operations in the Consolidated Statements of Operations. At March 31, 2009, Rex Energy recorded a loss on sale of assets of approximately $425,000 in the Consolidated Statement of Operations. Summarized financial information for discontinued operations is set forth below ($ in thousands, except per share data):
| | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
| | | 2009 | | 2008 | | | 2009 | | | 2008 | |
| | | | |
Revenues: | | | | | | | | | | | | | | | |
Oil and Gas Sales | | $ | — | | $ | 10 | | | $ | 193 | | | $ | 6,051 | |
Other Revenue | | | — | | | — | | | | — | | | | 304 | |
| | | | | | | | | | | | | | | |
Total Operating Revenue | | | — | | | 10 | | | | 193 | | | | 6,355 | |
| | | | | | | | | | | | | | | |
| | | | |
Costs and Expenses: | | | | | | | | | | | | | | | |
Production and Lease Operating Expense | | | — | | | 30 | | | | 237 | | | | 1,799 | |
General and Administrative Expense (Income) | | | — | | | 207 | | | | (97 | ) | | | 907 | |
Exploration Expense of Oil and Gas Properties | | | — | | | 3 | | | | — | | | | 2,198 | |
Impairment Expense of Oil and Gas Properties | | | — | | | 8,729 | | | | — | | | | 8,729 | |
Depreciation, Depletion, Amortization and Accretion | | | — | | | (35 | ) | | | — | | | | 1,565 | |
Loss on Sale of Oil and Gas Properties | | | — | | | — | | | | — | | | | 41 | |
(Gain) Loss on Derivatives, net | | | — | | | 558 | | | | (558 | ) | | | 558 | |
Other Income | | | — | | | — | | | | — | | | | (2 | ) |
| | | | | | | | | | | | | | | |
Total Costs and Expenses | | | — | | | 9,512 | | | | (418 | ) | | | 15,795 | |
| | | | | | | | | | | | | | | |
Income from Discontinued Operations Before Income Taxes | | | — | | | (9,502 | ) | | | 611 | | | | (9,440 | ) |
Income Tax (Expense) Benefit | | | — | | | 1,761 | | | | (288 | ) | | | 1,736 | |
| | | | | | | | | | | | | | | |
Income (Loss) From Discontinued Operations, net of taxes | | $ | — | | $ | (7,741 | ) | | $ | 323 | | | $ | (7,704 | ) |
| | | | | | | | | | | | | | | |
Page14 of14
