Operational Update
Warrior North Area
In the Warrior North Area, the company drilled seven gross (2.5 net) wells in 2016, with ten gross (4.1 net) wells fracture stimulated and 13 gross (5.1 net) wells placed into sales. The company had no wells drilled and awaiting completion as of
The company recently placed the four-well Vaughn pad into sales. The Vaughn wells were drilled to an average lateral length of approximately 7,200 feet and completed in an average of 37 stages with average sand concentrations of 2,600 pounds per foot. The wells produced at an average 24-hour sales rate per well, assuming full ethane recovery, of 1.5 Mboe/d, consisting of 3.1 MMcf/d of natural gas, 639 bbls/d of NGLs and 315 bbls/d of condensate. The wells went on to produce an average 5-day sales rate per well, assuming full ethane recovery, of 1.3 Mboe/d, consisting of 2.8 MMcf/d of natural gas, 579 bbls/d of NGLs and 289 bbls/d of condensate. The four Vaughn wells were drilled on the eastern portion of the Warrior North Area, where condensate yields have historically been lower than seen in other areas of the field.
Warrior North - Well Level Economics / Type Curve Update
The company has updated its well-level economics for the Warrior North Area. In the Warrior North Area, the company has adjusted its well-level economics to reflect its increased average lateral length, strong well performance, reduced cycle times and adjustments in expected realized prices. In summary, the rate of return assuming a
Legacy Butler Operated Area
In the Legacy Butler Operated Area, the company drilled two gross (1.4 net) wells in 2016, with two gross (1.4 net) wells fracture stimulated and two gross (1.4 net) wells placed into sales. The company had no wells drilled and awaiting completion as of
In 2017, the company plans to drill the four-well Wilson pad in the Legacy Butler Operated Area, with an estimated average lateral
length of 9,200 feet. The four-well Wilson pad is adjacent to the two-well Geyer pad, which was drilled to an average lateral length of 4,200 feet and placed into sales in
Moraine East Area
In the Moraine East Area, the company drilled 11.0 gross (4.5 net) wells in 2016, with six gross (2.7 net) wells fracture stimulated and 18 gross (8.7 net) wells placed into sales. The company had nine gross (3.8 net) wells drilled and awaiting completion as of
The company recently finished completing the four-well Baird pad, which was drilled to an average lateral length of approximately 7,140 feet. The pad is expected to be placed into sales at the end of the first quarter of 2017. The company has also finished drilling the six-well Shields pad, which was drilled to an average lateral length of approximately 7,750 feet. The Shields pad is expected to be placed into sales in the third quarter of 2017. The company is currently drilling the third of four wells on the Mackrell pad, which is expected to be drilled to an average lateral length of approximately 7,630 feet. The Mackrell pad is expected to be placed into sales in second half of 2017.
The six-well Shields pad and the four-well Mackrell pad will be the first wells drilled on the eastern portion of the Moraine East Area. This area is characterized by a thicker Upper Marcellus formation and the brittle nature of the formation allows for more effective completions. In addition, the Shields pad and the Mackrell pad are on trend with the the two-well Lynn pad, which was drilled in the Legacy Butler perated Area. The two wells were drilled to an average lateral length of approximately 2,725 feet and had average 5-day sales rates per well of 6.9 MMcfe/d.
2017 C3+ Natural Gas Liquids Pricing Improvement
During the fourth quarter of 2016, realized C3+ NGL prices, before the effects of hedging, averaged approximately 56% of WTI oil prices. The improvement in pricing was driven largely by the recent improvement in Mont Belvieu prices as well as improved differentials for NGLs in the northeast. Due to these improvements, the company now expects full-year 2017 realized C3+ NGL prices to average approximately 50% - 55% of WTI, an improvement over the previous guidance of 43% - 48%.
Fourth Quarter Financial Results
Unless otherwise noted, results of continuing operations are presented excluding the results of the company's
Operating revenue from continuing operations for the three months ended
Lease operating expense (LOE) from continuing operations was
Full-Year 2016 Financial Results
Operating revenue from continuing operations for full-year 2016 were
LOE from continuing operations was
Reconciliations of G&A to cash G&A for the three months and twelve months ended
Production Results and Price Realizations
Fourth quarter 2016 production volumes from continuing operations were 194.9 MMcfe/d, an increase of 12% over the fourth quarter of 2015, consisting of 120.9 MMcf/d of natural gas, 5.4 MBbls/d of C3+ NGLs, 5.8 Mbbls/d of ethane and 1.1 Mbbls/d of condensate. NGLs (including ethane) and condensate accounted for 38% of net production for the fourth quarter of 2016. For full-year 2016, production volumes increased by 6% over 2015 to 195.3 MMcfe/d, consisting of 122.1 MMcf/d of natural gas, 5.5 MBbls/d of C3+ NGLs, 5.8 Mbbls/d of ethane and 1.0 Mbbls/d of condensate. NGLs (including ethane) and condensate accounted for 37% of net production during 2016.
Including the effects of cash-settled derivatives, realized prices for the three months ended
Including the effects of cash-settled derivatives, realized prices for the twelve months ended
Full-Year 2016 Capital Investments
For the full-year 2016, net operational capital investments were approximately
Liquidity Update
During the first quarter of 2017,
First Quarter and Full-Year 2017 Guidance
The following table outlines Rex Energy's guidance for the first quarter of 2017 and full-year 2017. First quarter 2017 production, adjusting for the Warrior South asset sale, would have been approximately 182.0 - 184.0 MMcfe/d. However, the company experienced delays in the completion of the four-well Vaughn pad and the four-well Baird pad during the first quarter of 2017, which resulted in a reduction of 5% to the company's expected first quarter 2017 production. Given that the majority of the wells in the 2017 development plan will be placed into sales in the second half of the year, the company continues to expect full-year 2017 average daily production to be in the range of 194.0 - 204.0 MMcfe/d.
| 1Q2017 | Full-Year 2017 | |
| Production | 173.0 - 175.0 MMcfe/d | 194.0 - 204.0 MMcfe/d |
| LOE ($/Mcfe) | -- | |
| Cash G&A ($/Mcfe) | -- | |
| Net Operational Capital Expenditures(1) | -- | |
| (1) Land acquisition expense and capitalized interest are not included in the net operational capital expenditures budget estimate | ||
Conference Call Information
Management will host a live conference call and webcast on
About
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Forward-Looking Statements
Except for historical information, statements made in this release, including those relating to the timing and nature of development plans; drilling and completion schedules; anticipated fracture stimulation activities; expected dates for placement of wells into sales; anticipated hedging strategies and potential results thereof; and our financial guidance for full year 2017, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may contain words such as "expected", "expects", "scheduled", "planned", "plans", "anticipates" or similar words, and are based on management's experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We believe these statements and the assumptions and estimates contained in this release are reasonable based on information that is currently available to us. However, management's assumptions and the company's future performance are subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can or will meet the goals, expectations, and projections included in this release. Any number of factors could cause our actual results to be materially different from those expressed or implied in our forward looking statements, including (without limitation):
We undertake no obligation to publicly update or revise any forward-looking statements. Further information on the company's risks and uncertainties is available in our filings with the
| CONSOLIDATED BALANCE SHEETS | |||||||
| ($ in Thousands, Except Share and Per Share Data) | |||||||
| ASSETS | (Unaudited) | ||||||
| Current Assets | |||||||
| Cash and Cash Equivalents | $ | 3,697 | $ | 1,091 | |||
| Accounts Receivable | 25,448 | 17,274 | |||||
| Taxes Receivable | 211 | 18 | |||||
| Short-Term Derivative Instruments | 1,873 | 34,260 | |||||
| Inventory, Prepaid Expenses and Other | 2,546 | 3,059 | |||||
| Assets Held for Sale | -- | 53,151 | |||||
| Total Current Assets | 33,775 | 108,853 | |||||
| Property and Equipment (Successful Efforts Method) | |||||||
| 1,053,461 | 943,092 | ||||||
| 215,794 | 262,992 | ||||||
| Other Property and Equipment | 21,401 | 20,363 | |||||
| Wells and Facilities in Progress | 21,964 | 141,100 | |||||
| Pipelines | 18,029 | 14,024 | |||||
| Total Property and Equipment | 1,330,649 | 1,381,571 | |||||
| Less: Accumulated Depreciation , Depletion and Amortization | (475,205 | ) | (430,528 | ) | |||
| Net Property and Equipment | 855,444 | 951,043 | |||||
| Other Assets | 2,492 | 2,501 | |||||
| Long-Term Derivative Instruments | 2,212 | 9,534 | |||||
| Total Assets | $ | 893,923 | $ | 1,071,931 | |||
| LIABILITIES AND EQUITY | |||||||
| Current Liabilities | |||||||
| Accounts Payable | $ | 40,712 | $ | 36,785 | |||
| Current Maturities of Long-Term Debt | 764 | 402 | |||||
| Accrued Liabilities | 37,207 | 40,608 | |||||
| Short-Term Derivative Instruments | 25,025 | 2,486 | |||||
| Liabilities Related to Assets Held for Sale | -- | 36,320 | |||||
| Total Current Liabilities | 103,708 | 116,601 | |||||
| Long-Term Derivative Instruments | 7,227 | 5,556 | |||||
| Senior Secured Line of Credit and Long-Term Debt, Net of Issuance Costs | 113,785 | 109,386 | |||||
| Senior Notes, Net of Issuance Costs and Deferred Gain on Debt Exchanges | 641,762 | 663,089 | |||||
| Premium on Senior Notes, Net | (3,601 | ) | 2,344 | ||||
| Other Long-Term Debt | 3,409 | ||||||
| Other Deposits and Liabilities | 8,671 | 3,156 | |||||
| Future Abandonment Cost | 8,736 | 11,568 | |||||
| Total Liabilities | $ | 883,697 | $ | 911,700 | |||
| Stockholder Equity | |||||||
| Preferred Stock, | $ | 1 | $ | 1 | |||
| Common Stock, | 95 | 54 | |||||
| 650,584 | 623,863 | ||||||
| Accumulated Deficit | (640,454 | ) | (463,687 | ) | |||
| Total Stockholders' Equity | 10,226 | 160,231 | |||||
| Total Liabilities and Owners' Equity | $ | 893,923 | $ | 1,071,931 | |||
| CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||
| (Unaudited, in Thousands, Except per Share Data) | |||||||||||||||
| For the Three Months Ended | For the Twelve Months Ended | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| OPERATING REVENUE | |||||||||||||||
| Natural Gas, Condensate and NGL Sales | $ | 48,022 | $ | 27,363 | $ | 139,000 | $ | 138,707 | |||||||
| Other Revenue | 5 | 12 | 17 | 42 | |||||||||||
| TOTAL OPERATING REVENUE | 48,027 | 27,375 | 139,017 | 138,749 | |||||||||||
| OPERATING EXPENSES | |||||||||||||||
| Production and Lease Operating Expense | 28,694 | 22,246 | 104,699 | 93,892 | |||||||||||
| General and Administrative Expense | 5,384 | 6,441 | 20,621 | 26,694 | |||||||||||
| (Gain) Loss on Disposal of Assets | 164 | (7 | ) | (4,121 | ) | (540 | ) | ||||||||
| Impairment Expense | 29,275 | 73,364 | 74,619 | 283,244 | |||||||||||
| Exploration Expense | 224 | 843 | 2,178 | 2,617 | |||||||||||
| Depreciation, Depletion, Amortization and Accretion | 16,503 | 18,475 | 62,874 | 85,844 | |||||||||||
| Other Operating Expense (Income) | (176 | ) | 275 | 10,754 | 5,603 | ||||||||||
| TOTAL OPERATING EXPENSES | 80,068 | 121,637 | 271,624 | 497,354 | |||||||||||
| LOSS FROM OPERATIONS | (32,041 | ) | (94,262 | ) | (132,607 | ) | (358,605 | ) | |||||||
| OTHER INCOME (EXPENSE) | |||||||||||||||
| Interest Expense | (9,404 | ) | (11,706 | ) | (43,519 | ) | (47,783 | ) | |||||||
| Gain (Loss) on Derivatives, Net | (24,261 | ) | 14,689 | (32,515 | ) | 60,176 | |||||||||
| Other Expense | (2,152 | ) | (247 | ) | (2,124 | ) | (129 | ) | |||||||
| Debt Exchange Expense | (15 | ) | -- | (9,063 | ) | -- | |||||||||
| Gain on Extinguishment of Debt | 497 | -- | 24,627 | -- | |||||||||||
| Loss on Equity Method Investments | -- | -- | -- | (411 | ) | ||||||||||
| TOTAL OTHER INCOME (EXPENSE) | (35,335 | ) | 2,736 | (62,594 | ) | 11,853 | |||||||||
| LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX | (67,376 | ) | (91,526 | ) | (195,201 | ) | (346,752 | ) | |||||||
| Income Tax Expense | (8,221 | ) | (6,030 | ) | (2,436 | ) | (6,030 | ) | |||||||
| NET LOSS FROM CONTINUING OPERATIONS | (75,597 | ) | (97,556 | ) | (197,637 | ) | (352,782 | ) | |||||||
| Income (Loss) From Discontinued Operations, Net of Income Taxes | 8,203 | (481 | ) | 20,922 | (8,251 | ) | |||||||||
| NET LOSS | (67,394 | ) | (98,037 | ) | (176,715 | ) | (361,033 | ) | |||||||
| Net Income Attributable to Noncontrolling Interests | -- | -- | -- | 2,245 | |||||||||||
| NET LOSS ATTRIBUTABLE TO REX ENERGY | (67,394 | ) | (98,037 | ) | (176,715 | ) | (363,278 | ) | |||||||
| Preferred Stock Dividends | (650 | ) | (2,415 | ) | (5,091 | ) | (9,660 | ) | |||||||
| Effect of Preferred Stock Conversions | 668 | -- | 72,984 | -- | |||||||||||
| NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ | (67,376 | ) | $ | (100,452 | ) | $ | (108,822 | ) | $ | (372,938 | ) | |||
| Earnings per common share: | |||||||||||||||
| Basic - Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders | $ | (0.78 | ) | $ | (1.84 | ) | $ | (1.63 | ) | $ | (6.66 | ) | |||
| Basic - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders | 0.09 | (0.01 | ) | 0.26 | (0.19 | ) | |||||||||
| Basic - Net Loss Attributable to Rex Energy Common Shareholders | $ | (0.69 | ) | $ | (1.85 | ) | $ | (1.37 | ) | $ | (6.85 | ) | |||
| Basic - Weighted Average Shares of Common Stock Outstanding | 97,398 | 54,342 | 79,256 | 54,392 | |||||||||||
| Diluted - Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders | $ | (0.78 | ) | $ | (1.84 | ) | $ | (1.63 | ) | $ | (6.66 | ) | |||
| Diluted - Net Income (Loss) From Discontinued Operations Attributable to Rex Energy Common Shareholders | 0.09 | (0.01 | ) | 0.26 | (0.19 | ) | |||||||||
| Diluted - Net Loss Attributable to Rex Energy Common Shareholders | $ | (0.69 | ) | $ | (1.85 | ) | $ | (1.37 | ) | $ | (6.85 | ) | |||
| Diluted - Weighted Average Shares of Common Stock Outstanding | 97,398 | 54,342 | 79,256 | 54,392 | |||||||||||
| CONSOLIDATED OPERATIONAL HIGHLIGHTS | |||||||||||||||
| UNAUDITED | |||||||||||||||
| Three Months Ending | Twelve Months Ending | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Oil, Natural Gas, NGL and Ethane sales (in thousands): | |||||||||||||||
| Natural gas sales | $ | 24,844 | $ | 15,083 | $ | 73,275 | $ | 83,140 | |||||||
| Natural gas liquids (C3+) sales | 13,824 | 7,917 | 35,877 | 32,789 | |||||||||||
| Ethane sales | 4,989 | 2,552 | 16,484 | 8,710 | |||||||||||
| Condensate sales | 4,366 | 1,811 | 13,364 | 14,068 | |||||||||||
| Cash-settled derivatives: | |||||||||||||||
| Natural gas | 2,068 | 9,323 | 26,348 | 32,573 | |||||||||||
| Natural gas liquids (C3+) | (1,126 | ) | 3,204 | 4,914 | 10,384 | ||||||||||
| Ethane | (255 | ) | 1,103 | (14 | ) | 42 | |||||||||
| Condensate | (547 | ) | 3,054 | 1,644 | 11,860 | ||||||||||
| Total oil, gas, NGL and Ethane sales including cash settled derivatives | $ | 48,163 | $ | 43,054 | $ | 171,892 | $ | 193,566 | |||||||
| Production during the period: | |||||||||||||||
| Natural gas (Mcf) | 11,125,475 | 10,446,424 | 44,684,571 | 44,606,753 | |||||||||||
| Natural gas liquids (C3+) (Bbls) | 500,114 | 454,963 | 1,996,075 | 2,026,321 | |||||||||||
| Ethane (Bbls) | 532,841 | 416,496 | 2,111,321 | 1,319,582 | |||||||||||
| Condensate (Bbls) | 101,239 | 57,141 | 360,384 | 402,867 | |||||||||||
| Total (Mcfe)1 | 17,930,639 | 16,018,024 | 71,491,251 | 67,099,373 | |||||||||||
| Production - average per day: | |||||||||||||||
| Natural gas (Mcf) | 120,929 | 113,548 | 122,089 | 122,210 | |||||||||||
| Natural gas liquids (C3+) (Bbls) | 5,436 | 4,945 | 5,454 | 5,552 | |||||||||||
| Ethane (Bbls) | 5,792 | 4,527 | 5,769 | 3,615 | |||||||||||
| Condensate (Bbls) | 1,100 | 621 | 985 | 1,104 | |||||||||||
| Total (Mcfe)1 | 194,898 | 174,109 | 195,331 | 183,834 | |||||||||||
| Average price per unit: | |||||||||||||||
| Realized natural gas price per Mcf - as reported | $ | 2.23 | $ | 1.44 | $ | 1.64 | $ | 1.86 | |||||||
| Realized impact from cash settled derivatives per Mcf | 0.19 | 0.89 | 0.59 | 0.73 | |||||||||||
| Net realized price per Mcf | $ | 2.42 | $ | 2.33 | $ | 2.23 | $ | 2.59 | |||||||
| Realized NGL (C3+) price per Bbl - as reported | $ | 27.64 | $ | 17.40 | $ | 17.97 | $ | 16.18 | |||||||
| Realized impact from cash settled derivatives per Bbl2 | (2.25 | ) | 7.04 | 2.46 | 5.12 | ||||||||||
| Net realized price per Bbl | $ | 25.39 | $ | 24.44 | $ | 20.43 | $ | 21.30 | |||||||
| Realized ethane price per Bbl - as reported | $ | 9.36 | $ | 6.13 | $ | 7.81 | $ | 6.60 | |||||||
| Realized impact from cash settled derivatives per Bbl | (0.48 | ) | 0.26 | (0.01 | ) | 0.10 | |||||||||
| Net realized price per Bbl | $ | 8.88 | $ | 6.39 | $ | 7.80 | $ | 6.70 | |||||||
| Realized condensate price per Bbl - as reported | $ | 43.13 | $ | 31.69 | $ | 37.08 | $ | 34.92 | |||||||
| Realized impact from cash settled derivatives per Bbl | (5.40 | ) | 53.45 | 4.56 | 29.44 | ||||||||||
| Net realized price per Bbl | $ | 37.73 | $ | 85.14 | $ | 41.64 | $ | 64.36 | |||||||
| LOE/Mcfe | $ | 1.60 | $ | 1.39 | $ | 1.46 | $ | 1.40 | |||||||
| Cash G&A/Mcfe | $ | 0.24 | $ | 0.32 | $ | 0.25 | $ | 0.31 | |||||||
| 1 Oil and natural gas liquids are converted at the rate of one barrel of oil equivalent to six Mcfe. | |||||||||||||||
| 2 Includes the effect of derivatives not classified as discontinued operations | |||||||||||||||
|
COMMODITY DERIVATIVES - HEDGE POSITION AS OF | |||||||
| 2017 | 2018 | ||||||
| Oil Derivatives (Bbls) | |||||||
| Swap Contracts | |||||||
| Volume | 81,000 | 60,000 | |||||
| Price | $ | 53.30 | $ | 54.00 | |||
| Deferred Premium Puts | |||||||
| Volume | 15,000 | -- | |||||
| Floor | $ | 51.00 | -- | ||||
| Collar Contracts | |||||||
| Volume | 48,000 | 18,000 | |||||
| Ceiling | $ | 57.20 | $ | 60.00 | |||
| Floor | $ | 45.00 | $ | 53.00 | |||
| Collar Contracts with | |||||||
| Volume | 93,000 | 60,000 | |||||
| Ceiling | $ | 61.50 | $ | 62.30 | |||
| Floor | $ | 49.68 | $ | 52.00 | |||
| $ | 40.16 | $ | 43.00 | ||||
| Natural Gas Derivatives (Mcf) | |||||||
| Swap Contracts | |||||||
| Volume | 14,900,000 | 9,160,000 | |||||
| Price | $ | 3.03 | $ | 3.19 | |||
| Swaption Contracts | |||||||
| Volume | 2,400,000 | -- | |||||
| Price | $ | 3.33 | $ | -- | |||
| Put Spread Contracts | |||||||
| Volume | -- | -- | |||||
| Floor | $ | -- | $ | -- | |||
| $ | -- | $ | -- | ||||
| Collar Contracts with | |||||||
| Volume | 17,510,000 | 8,775,000 | |||||
| Ceiling | $ | 3.87 | $ | 3.58 | |||
| Floor | $ | 3.01 | $ | 2.89 | |||
| $ | 2.33 | $ | 2.30 | ||||
| Call Contracts | |||||||
| Volume | 8,380,100 | 16,489,900 | |||||
| Ceiling | $ | 4.51 | $ | 4.64 | |||
| Collar Contracts | |||||||
| Volume | 1,700,000 | 450,000 | |||||
| Ceiling | $ | 3.20 | $ | 3.65 | |||
| Floor | $ | 2.54 | $ | 3.20 | |||
| Natural Gas Liquids (Bbls) | |||||||
| Swap Contracts | |||||||
| Propane (C3) | |||||||
| Volume | 962,000 | 600,000 | |||||
| Price | $ | 23.25 | $ | 25.56 | |||
| Butane (C4) | |||||||
| Volume | 240,000 | 180,000 | |||||
| Price | $ | 29.15 | $ | 32.97 | |||
| Isobutane (IC4) | |||||||
| Volume | 117,000 | 96,000 | |||||
| Price | $ | 29.94 | $ | 33.71 | |||
| Natural Gasoline (C5+) | |||||||
| Volume | 364,000 | 192,000 | |||||
| Price | $ | 48.01 | $ | 49.35 | |||
| Ethane | |||||||
| Volume | 840,000 | 420,000 | |||||
| Price | $ | 10.47 | $ | 13.02 | |||
| Natural Gas Basis (Mcf) | |||||||
| Swap Contracts | |||||||
| Dominion Appalachia | |||||||
| Volume | 15,435,000 | 18,980,000 | |||||
| Price | $ | (0.86 | ) | $ | (0.82 | ) | |
| Volume | 14,600,000 | 14,600,000 | |||||
| Price | $ | (0.13 | ) | $ | (0.13 | ) | |
| NYMEX Heating Oil (Gallon) | |||||||
| Swap Contracts | |||||||
| Volume | -- | -- | |||||
| Price | $ | -- | $ | -- | |||
APPENDIX
NON-GAAP MEASURES
EBITDAX
"EBITDAX" means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period: interest, income taxes, DD&A, unrealized losses from financial derivatives, non-recurring gains and losses, exploration expenses and other similar non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives and gains on asset dispositions, added to net income. EBITDAX, as defined above, is used as a financial measure by our management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:
EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure) in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.
We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an indicator of a company's operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management's discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.
We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.
To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.
For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX. The following table presents a reconciliation of our net income to EBITDAX for each of the periods presented.
| Three Months Ended (Unaudited) | Twelve Months Ended (Unaudited) | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Net Loss From Continuing Operations | $ | (75,597 | ) | $ | (97,556 | ) | $ | (197,637 | ) | $ | (352,782 | ) | ||||
| Add Back (Less) Non-Recurring Costs (Income)1 | (372 | ) | -- | (6,760 | ) | 4,774 | ||||||||||
| Add Back Depletion, Depreciation, Amortization and Accretion | 16,503 | 18,475 | 62,874 | 85,844 | ||||||||||||
| Add Back Non-Cash Compensation Expense | 1,072 | 1,378 | 3,078 | 5,791 | ||||||||||||
| Add Back Interest Expense | 9,404 | 11,706 | 43,519 | 47,783 | ||||||||||||
| Add Back Impairment Expense | 29,275 | 73,364 | 74,619 | 283,244 | ||||||||||||
| Add Back Exploration Expenses | 224 | 843 | 2,178 | 2,617 | ||||||||||||
| Add Back (Less) (Gain) Loss on Disposal of Assets2 | 164 | (4 | ) | (4,121 | ) | (537 | ) | |||||||||
| Add Back (Less) (Gain) Loss on Financial Derivatives | 24,261 | (14,689 | ) | 32,515 | (60,176 | ) | ||||||||||
| Add Back Cash Settlement of Derivatives | 86 | 15,691 | 32,571 | 55,793 | ||||||||||||
| Add Back Non-Cash Portion of Equity Method Investments | -- | -- | -- | 406 | ||||||||||||
| Add Back Income Tax Expense | 8,221 | 6,030 | 2,436 | 6,030 | ||||||||||||
| EBITDAX From Continuing Operations | $ | 13,241 | $ | 15,238 | $ | 45,272 | $ | 78,787 | ||||||||
| Income (loss) from Discontinued Operations | $ | 8,203 | $ | (481 | ) | $ | 20,922 | $ | (8,251 | ) | ||||||
| Net Income Attributable to Noncontrolling Interests | -- | -- | -- | (2,245 | ) | |||||||||||
| Income (Loss) From Discontinued Operations Attributable to | 8,203 | (481 | ) | 20,922 | (10,496 | ) | ||||||||||
| Add Back Depletion, Depreciation, Amortization and Accretion | 1 | 3,481 | 5,101 | 18,978 | ||||||||||||
| Add Back (Less) Non-Cash Compensation Expense (Income) | (52 | ) | 238 | (159 | ) | 659 | ||||||||||
| Add Back Interest Expense | -- | 3 | 4 | 510 | ||||||||||||
| Add Back Impairment Expense | -- | 7,734 | 3,543 | 62,531 | ||||||||||||
| Add Back Exploration Expense (Income) | -- | (74 | ) | 143 | 394 | |||||||||||
| Add (Less) Back (Gain) Loss on Disposal of Asset2 | 5 | (760 | ) | (30,530 | ) | (57,748 | ) | |||||||||
| Add Back (Less) Non-Cash Portion of Noncontrolling Interests | -- | 1 | -- | (208 | ) | |||||||||||
| Less Income Tax Benefit | (7,852 | ) | (8,688 | ) | -- | (6,030 | ) | |||||||||
| Add EBITDAX From Discontinued Operations | $ | 305 | $ | 1,454 | $ | (976 | ) | $ | 8,590 | |||||||
| EBITDAX (Non-GAAP) | $ | 13,546 | $ | 16,692 | $ | 44,296 | $ | 87,377 | ||||||||
| 1 For the year ended | ||||||||||||||||
| 2 Includes gain on sale of | ||||||||||||||||
Adjusted Net Income
"Adjusted Net Income" means, for any period, the sum of net income (loss) from continuing operations before income taxes for the
period plus the following expenses, charges or income, in each case, to the extent deducted from or added to net income in the period: unrealized losses from financial derivatives, non-cash compensation expense, dry hole expenses, disposals of assets, impairment and other one-time or non-recurring charges, minus all gains from unrealized financial derivatives, disposal of assets and deferred income tax benefits, added to net income. Adjusted Net Income is used as a financial measure by
To compensate for these limitations, the company believes it is important to consider both net income determined under GAAP and Adjusted Net Income.
The following table presents a reconciliation of Rex Energy's net income from continuing operations to its adjusted net income for each of the periods presented ($ in thousands):
| Three Months Ended | Twelve Months Ended | |||||||||||||||
(Unaudited) | (Unaudited) | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Loss From Continuing Operations Before Income Taxes, as reported | $ | (67,376 | ) | $ | (97,556 | ) | $ | (195,201 | ) | $ | (346,752 | ) | ||||
| Gain (Loss) on Derivatives, Net | 24,261 | (14,689 | ) | 32,515 | (60,176 | ) | ||||||||||
| Cash Settlement of Derivatives | 86 | 15,691 | 32,571 | 55,793 | ||||||||||||
| Add Back (Less) Losses (Gains) from Financial Derivatives | 24,347 | 1,002 | 65,086 | (4,383 | ) | |||||||||||
| Add Back Non-Recurring Costs1 | (372 | ) | -- | (6,760 | ) | 4,774 | ||||||||||
| Add Back Impairment Expense | 29,275 | 73,364 | 74,619 | 283,244 | ||||||||||||
| Add Back Dry Hole Expense | 32 | -- | 880 | 191 | ||||||||||||
| Add Back (Less) Non-Cash Compensation Expense (Income) | 1,072 | 1,378 | 3,078 | 5,791 | ||||||||||||
| Add Back (Less) (Gain) Loss on Disposal of Assets | 164 | (4 | ) | (4,121 | ) | (537 | ) | |||||||||
| Loss From Continuing Operations Before Income Taxes, adjusted | $ | (12,858 | ) | $ | (21,816 | ) | $ | (62,419 | ) | $ | (57,672 | ) | ||||
| Less Income Tax Benefit, adjusted2 | 5,143 | 8,726 | 24,968 | 23,069 | ||||||||||||
| Adjusted Net Loss From Continuing Operations | $ | (7,715 | ) | $ | (13,090 | ) | $ | (37,451 | ) | $ | (34,603 | ) | ||||
| Basic - Adjusted Net Loss Per Share | $ | (0.08 | ) | $ | (0.24 | ) | $ | (0.47 | ) | $ | (0.64 | ) | ||||
| Basic - Weighted Average Shares of Common Stock Outstanding | 97,398 | 54,342 | 79,256 | 54,392 | ||||||||||||
| 1 For the year ended | ||||||||||||||||
| 2Assumes an effective tax rate of 40% | ||||||||||||||||
Cash General and Administrative Expenses
Cash General and Administrative Expenses (Cash G&A) is the difference between GAAP G&A and non-Cash G&A, which is primarily comprised of non-cash compensation expense.
To compensate for these limitations, the company believes it is important to consider both Cash G&A and GAAP G&A. The following table presents a reconciliation of Rex Energy's GAAP G&A to its Cash G&A for each of the periods presented (in thousands):
| Three Months Ended (Unaudited) | Twelve Months Ended (Unaudited) | ||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||
| GAAP G&A | $ | 5,384 | $ | 6,441 | $ | 20,621 | $ | 26,694 | |||
| Non-Cash Compensation Expense | 1,072 | 1,378 | 3,078 | 5,791 | |||||||
| Cash G&A | $ | 4,312 | $ | 5,063 | $ | 17,543 | $ | 20,903 | |||
For more information contact: Investor Relations (814) 278-7130 InvestorRelations@rexenergycorp.com
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