Delaware
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1-33249
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16-1751069
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(State or other jurisdiction of
incorporation)
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(Commission
File Number)
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(IRS Employer
Identification No.)
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303 W. WALL ST, SUITE 1400
MIDLAND, TX |
79701
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(Address of principal executive offices)
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(Zip Code)
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Item 2.02. Results of Operations and Financial Condition.
On February 25, 2013, the Registrant issued a press release, a copy of which is attached hereto as Exhibit 99.1 and is incorporated herein by reference.
The information in this report, including the Exhibit attached hereto, shall not be deemed "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 (the "Exchange Act") nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933, or the Exchange Act, except as specifically identified therein as being incorporated by reference.
Item 9.01. Financial Statements and Exhibits.
Legacy Reserves LP
By: Legacy Reserves GP, LLC,
its general partner
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February 25, 2013
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/s/ JAMES DANIEL WESTCOTT
James Daniel Westcott
Executive Vice President and Chief Financial Officer
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EXHIBIT 99.1
MIDLAND, Texas, Feb. 25, 2013 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for 2012 as well as financial guidance for 2013. Financial results contained herein are preliminary and subject to the audited financial statements included in Legacy's Form 10-K to be filed on or about February 27, 2013.
A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.
Three Months Ended | Twelve Months Ended | |||
December 31, | September 30, | December 31, | ||
2012 | 2012 | 2012 | 2011 | |
(dollars in millions) | ||||
Production (Boe/d) | 15,729 | 14,772 | 14,811 | 13,071 |
Revenue | $90.5 | $84.2 | $346.5 | $336.9 |
Adjusted EBITDA (*) | $51.6 | $49.5 | $197.6 | $201.4 |
Development capital expenditures | $19.7 | $19.6 | $68.2 | $71.6 |
Distributable Cash Flow (*) | $24.7 | $23.7 | $104.5 | $107.8 |
* Non-GAAP financial measure. Please see Adjusted EBITDA and Distributable Cash Flow table at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure. |
2012 highlights include:
Q4 2012 highlights include:
Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "2012 was a landmark year for Legacy, as we closed the largest acquisition in our history on December 20, the $502.6 million acquisition of Permian Basin properties from Concho. These properties are in some of the most prolific fields in the Permian Basin. With the exception of the Lower Abo, these properties provide us with a strong set of mature PDP assets with modest production decline rates as well as a very strong portfolio of proved and unproved drilling locations and developed, non-producing projects. Our integration of this acquisition is going smoothly thus far, and since assuming operations on January 1, our operations group is even more excited about the asset potential they are seeing.
"The Concho acquisition helped us set a Company record in proved reserves with 83.2 MMBoe and, despite closing the transaction at the very end of the year, we also set annual and quarterly production records of over 14,800 Boe/d during 2012 and over 15,700 Boe/d during the fourth quarter. We generated Adjusted EBITDA of $197.6 million, the second highest in our history, in the face of challenging Midland-to-Cushing crude oil differentials and unusually high well failure expenses. A market has developed to hedge the Midland-to-Cushing differential and we have now hedged a significant portion of our exposure during 2013. On the development front, we continue to be pleased with our results from our Wolfberry drilling and are excited about the results from our new horizontal Bone Spring well that began producing in November. Due to our acquisitions, strong development results and promising outlook, we increased our distribution every quarter during 2012, resulting in year-over-year distribution growth of 3.6%. We have now increased our distribution for the last nine consecutive quarters. For the year, assuming we had used $50.0 million of our development capital expenditures as maintenance capital expenditures (approximately 25% of our Adjusted EBITDA), our 2012 coverage ratio was 1.11 times. Using $13 million as maintenance capital expenditures (roughly 25% of Adjusted EBITDA) and excluding the impact of the Concho acquisition and our associated year-end capital raises, our fourth quarter distributable cash flow per unit would have been approximately $0.64 per unit, covering our $0.57 distribution by 1.12 times.
"Due to our recent strong drilling results and our newly-expanded development inventory, in January our board approved a 2013 capital budget of $90 million. We consider $68 million of our budget to be maintenance capital. With our multi-year, oil-weighted drilling inventory, our recently closed Concho acquisition and our strong ongoing acquisition efforts, we are excited about our opportunities in 2013 and beyond."
Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "We are very pleased with our acquisition efforts and growth in 2012. To finance the Concho acquisition, we completed our largest equity offering and issued $300 million of senior notes during the fourth quarter. In addition, our now 20-member bank group redetermined our borrowing base at $800 million. As of February 25, we had $500 million of debt outstanding under our revolving credit facility, giving us approximately $300 of current availability (another Company record) for future acquisitions and development projects. With favorable conditions in the capital markets and ample availability under our credit facility, we look forward to another year of strong results and the pursuit of additional acquisitions."
2013 Guidance
The following table sets forth certain assumptions being used by Legacy to estimate its anticipated results of operations for 2013. These estimates do not include any acquisitions of additional oil or natural gas properties. In addition, these estimates are based on, among other things, assumptions of capital expenditure levels, current indications of supply and demand for oil and natural gas and current operating and labor costs. The guidance set forth below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. The guidance below sets forth management's best estimate based on current and anticipated market conditions and other factors. While we believe that these estimates and assumptions are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate, as set forth under "Cautionary Statement Relevant to Forward-Looking Information."
($ in thousands unless otherwise noted) | FY 2013E Range | ||
Production: | |||
Oil (MBbls) | 4,330 | -- | 4,470 |
Natural gas liquids (MGal) | 13,300 | -- | 13,750 |
Natural gas (MMcf) | 14,050 | -- | 14,500 |
Total (MBoe) | 6,988 | -- | 7,214 |
Average daily production (Boe/d) | 19,146 | -- | 19,765 |
Weighted Average NYMEX Differentials: (1) | |||
Oil (per Bbl) | ($7.50) | -- | ($9.00) |
NGL realization (2) | 1.00% | -- | 1.15% |
Natural gas (per Mcf) | $1.25 | -- | $1.35 |
Expenses: | |||
Oil and natural gas production expenses ($/Boe) | $18.30 | -- | $19.20 |
Ad valorem taxes (% of revenue) | 3.25% | -- | 3.50% |
Production and other taxes (% of revenue) | 6.00% | -- | 6.50% |
Cash G&A expenses (3) | $25,400 | -- | $26,650 |
(1) Based on current NYMEX strip pricing. Excludes the impact of commodity derivatives. Q1 2013 oil differentials are projected to be materially wider ($11.75--$13.50) primarily driven by recent Midland-to-Cushing differentials which have since narrowed considerably. | |||
(2) Represents the projected percentage of WTI crude oil prices divided by 42, as we report NGLs in gallons. | |||
(3) Consistent with our definition of Adjusted EBITDA, these figures exclude LTIP expenses. Cash settlements of LTIP (not included herein) impact Distributable Cash Flow. |
Annual Financial and Operating Results – 2012 Compared to 2011
2012 Financial and Operating Results – Fourth Quarter Compared to Third Quarter
Commodity Derivatives Contracts
We have entered into the following oil and natural gas derivatives contracts, including swaps and three-way collars, to help mitigate the risk of changing commodity prices. As of February 25, 2013, we had entered into derivatives agreements to receive average NYMEX WTI crude oil and Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below starting with January 2013 through December 2017:
Crude Oil (WTI):
Calendar Year |
Volumes (Bbls) |
Average Price per Bbl |
Price Range per Bbl |
2013 | 2,155,693 | $90.92 | $80.10 -- $108.65 |
2014 | 1,520,764 | $91.54 | $87.50 -- $103.75 |
2015 | 545,351 | $91.98 | $88.50 -- $100.20 |
2016 | 228,600 | $87.94 | $86.30 -- $99.85 |
2017 | 182,500 | $84.75 | $84.75 |
We have also entered into multiple NYMEX WTI crude oil derivative three-way collar contracts as follows:
Calendar Year |
Volumes (Bbls) |
Average Short Put Price |
Average Long Put Price |
Average Short Call Price |
2013 | 1,228,170 | $65.53 | $90.97 | $105.85 |
2014 | 1,453,880 | $65.54 | $90.73 | $110.65 |
2015 | 1,308,500 | $64.67 | $89.67 | $112.21 |
2016 | 621,300 | $63.37 | $88.37 | $106.40 |
2017 | 72,400 | $60.00 | $85.00 | $104.20 |
Additionally, we have entered into swaps for the Midland-to-Cushing/WTI crude oil differential with the following attributes:
Time Period |
Volumes (Bbls) |
Average Price per Bbl |
Price Range per Bbl |
Q1 2013 | 180,000 | ($1.25) | ($1.25) |
Q2 - Q4 2013 | 2,200,000 | ($1.47) | $(1.25) -- $(1.75) |
Natural Gas (WAHA, ANR-Oklahoma and CIG-Rockies hubs):
Calendar Year |
Volumes (MMBtu) |
Average Price per MMBtu |
Price Range per MMBtu |
2013 | 9,240,654 | $4.31 | $3.18 -- $6.89 |
2014 | 7,431,254 | $4.34 | $3.61 -- $6.47 |
2015 | 1,339,300 | $5.65 | $5.14 -- $5.82 |
2016 | 219,200 | $5.30 | $5.30 |
Location and quality differentials attributable to our properties are not reflected in the above prices. The agreements provide for monthly settlement based on the difference between the agreement fixed price and the actual reference oil and natural gas index prices.
Annual Report on Form 10-K
Our consolidated, audited financial statements and related footnotes will be available in our annual 2012 Form 10-K which will be filed on or about February 27, 2013.
Conference Call
As announced on January 22, 2013, Legacy will host an investor conference call to discuss Legacy's results on Tuesday, February 26, 2013 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-266-0479. A replay of the call will be available through Saturday, March 2, 2013, by dialing 855-859-2056 or 404-537-3406 and entering replay code 92534708. Those wishing to listen to the live or archived web cast via the Internet should go to the Investor Relations tab of our website at www.legacylp.com. Following our prepared remarks, we will be pleased to answer questions from securities analysts and institutional portfolio managers and analysts; the complete call is open to all other interested parties on a listen-only basis.
About Legacy Reserves LP
Legacy Reserves LP is an independent oil and natural gas limited partnership headquartered in Midland, Texas, focused on the acquisition and development of oil and natural gas properties primarily located in the Permian Basin, Mid-Continent and Rocky Mountain regions of the United States. Additional information is available at www.legacylp.com.
Cautionary Statement Relevant to Forward-Looking Information
This press release contains forward-looking statements relating to our operations that are based on management's current expectations, estimates and projections about its operations. Words such as "anticipates," "expects," "intends," "plans," "targets," "projects," "believes," "seeks," "schedules," "estimated," and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: realized oil and natural gas prices; production volumes, lease operating expenses, general and administrative costs and finding and development costs; future operating results and the factors set forth under the heading "Risk Factors" in our annual and quarterly reports filed with the SEC. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, Legacy undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
LEGACY RESERVES LP | ||||
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||
(UNAUDITED) | ||||
Three Months Ended | Twelve Months Ended | |||
December 31, | September 30, | December 31, | ||
2012 | 2012 | 2012 | 2011 | |
(In thousands, except per unit data) | ||||
Revenues: | ||||
Oil sales | $ 74,157 | $ 70,173 | $ 286,254 | $ 264,473 |
Natural gas liquids (NGL) sales | 3,850 | 3,492 | 14,592 | 18,888 |
Natural gas sales | 12,448 | 10,531 | 45,614 | 53,524 |
Total revenues | 90,455 | 84,196 | 346,460 | 336,885 |
Expenses: | ||||
Oil and natural gas production | 30,929 | 30,728 | 112,951 | 96,914 |
Production and other taxes | 5,737 | 5,137 | 20,778 | 20,329 |
General and administrative | 5,922 | 6,993 | 24,526 | 23,084 |
Depletion, depreciation, amortization and accretion | 29,102 | 24,833 | 102,144 | 88,178 |
Impairment of long-lived assets | 14,510 | 7,277 | 37,066 | 24,510 |
(Gain) loss on disposal of assets | 568 | 260 | (2,496) | (625) |
Total expenses | 86,768 | 75,228 | 294,969 | 252,390 |
Operating income | 3,687 | 8,968 | 51,491 | 84,495 |
Other income (expense): | ||||
Interest income | 5 | 3 | 16 | 15 |
Interest expense | (6,003) | (5,285) | (20,260) | (18,566) |
Equity in income of partnership | 23 | 30 | 111 | 138 |
Realized and unrealized net gains (losses) on commodity derivatives | 4,409 | (27,177) | 38,493 | 6,857 |
Other | (31) | (51) | (118) | 152 |
Income (loss) before income taxes | 2,090 | (23,512) | 69,733 | 73,091 |
Income tax expense | (218) | (54) | (1,096) | (1,030) |
Net income (loss) | $ 1,872 | $ (23,566) | $ 68,637 | $ 72,061 |
Income (loss) per unit -- | ||||
basic and diluted | $ 0.04 | $ (0.49) | $ 1.40 | $ 1.63 |
Weighted average number of units used in computing net income (loss) per unit -- | ||||
Basic | 52,416 | 47,869 | 48,991 | 44,093 |
Diluted | 52,454 | 47,869 | 48,991 | 44,112 |
LEGACY RESERVES LP | ||
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) | ||
(dollars in thousands) | ||
December 31, | ||
2012 | 2011 | |
ASSETS | ||
Current assets: | ||
Cash and cash equivalents | $ 3,509 | $ 3,151 |
Accounts receivable, net: | ||
Oil and natural gas | 37,547 | 35,489 |
Joint interest owners | 27,851 | 10,299 |
Other | 551 | 204 |
Fair value of derivatives | 15,158 | 7,117 |
Prepaid expenses and other current assets | 3,294 | 3,525 |
Total current assets | 87,910 | 59,785 |
Oil and natural gas properties, at cost: | ||
Proved oil and natural gas properties using the successful efforts method of accounting | 2,078,961 | 1,389,326 |
Unproved properties | 65,968 | 20,063 |
Accumulated depletion, depreciation, amortization and impairment | (573,003) | (450,060) |
1,571,926 | 959,329 | |
Other property and equipment, net of accumulated depreciation and amortization of $4,618 and $3,530, respectively | 2,646 | 3,310 |
Operating rights, net of amortization of $3,531 and $3,034, respectively | 3,486 | 3,983 |
Fair value of derivatives | 15,834 | 10,188 |
Other assets, net of amortization of $7,909 and $6,337, respectively | 7,804 | 6,611 |
Investment in equity method investee | 393 | 282 |
Total assets | $ 1,689,999 | $ 1,043,488 |
LIABILITIES AND UNITHOLDERS' EQUITY | ||
Current liabilities: | ||
Accounts payable | $ 1,822 | $ 3,286 |
Accrued oil and natural gas liabilities | 50,162 | 45,351 |
Fair value of derivatives | 10,801 | 18,905 |
Asset retirement obligation | 29,501 | 20,262 |
Other | 11,437 | 9,646 |
Total current liabilities | 103,723 | 97,450 |
Long-term debt | 775,838 | 337,000 |
Asset retirement obligation | 132,682 | 100,012 |
Fair value of derivatives | 5,590 | 18,897 |
Other long-term liabilities | 1,886 | 1,794 |
Total liabilities | 1,019,719 | 555,153 |
Commitments and contingencies | ||
Unitholders' equity: | ||
Limited partners' equity - 57,038,942 and 47,801,682 units issued and outstanding, respectively | 670,183 | 488,264 |
General partner's equity (approximately 0.03% and 0.04%, respectively) | 97 | 71 |
Total unitholders' equity | 670,280 | 488,335 |
Total liabilities and unitholders' equity | $ 1,689,999 | $ 1,043,488 |
LEGACY RESERVES LP | ||||
SELECTED FINANCIAL AND OPERATING DATA | ||||
Three Months Ended | Twelve Months Ended | |||
December 31, | September 30, | December 31, | ||
2012 | 2012 | 2012 | 2011 | |
(In thousands, except per unit data) | ||||
Revenues: | ||||
Oil sales | $ 74,157 | $ 70,173 | $ 286,254 | $ 264,473 |
Natural gas liquids sales | 3,850 | 3,492 | 14,592 | 18,888 |
Natural gas sales | 12,448 | 10,531 | 45,614 | 53,524 |
Total revenues | $ 90,455 | $ 84,196 | $ 346,460 | $ 336,885 |
Expenses: | ||||
Oil and natural gas production | $ 28,343 | $ 28,207 | $ 103,409 | $ 87,626 |
Ad valorem taxes | $ 2,586 | $ 2,521 | $ 9,542 | $ 9,288 |
Total oil and natural gas production including ad valorem taxes | $ 30,929 | $ 30,728 | $ 112,951 | $ 96,914 |
Production and other taxes | $ 5,737 | $ 5,137 | $ 20,778 | $ 20,329 |
General and administrative excluding LTIP | $ 6,046 | $ 4,855 | $ 20,980 | $ 19,063 |
LTIP expense (benefit) | $ (124) | $ 2,138 | $ 3,546 | $ 4,021 |
Total general and administrative | $ 5,922 | $ 6,993 | $ 24,526 | $ 23,084 |
Depletion, depreciation, amortization and accretion | $ 29,102 | $ 24,833 | $ 102,144 | $ 88,178 |
Realized commodity derivative settlements: | ||||
Realized gains (losses) on oil derivatives | $ 738 | $ 2,108 | $ (10,211) | $ (11,335) |
Realized gains on natural gas derivatives | $ 3,146 | $ 4,000 | $ 16,113 | $ 11,972 |
Production: | ||||
Oil (MBbls) | 919 | 840 | 3,337 | 2,951 |
Natural gas liquids (MGal) | 3,670 | 3,821 | 14,607 | 14,559 |
Natural gas (MMcf) | 2,643 | 2,571 | 10,417 | 8,842 |
Total (MBoe) | 1,447 | 1,359 | 5,421 | 4,771 |
Average daily production (Boe/d) | 15,729 | 14,772 | 14,811 | 13,071 |
Average sales price per unit (excluding commodity derivatives): | ||||
Oil price (per Bbl) | $ 80.69 | $ 83.54 | $ 85.78 | $ 89.62 |
Natural gas liquids price (per Gal) | $ 1.05 | $ 0.91 | $ 1.00 | $ 1.30 |
Natural gas price (per Mcf) | $ 4.71 | $ 4.10 | $ 4.38 | $ 6.05 |
Combined (per Boe) | $ 62.51 | $ 61.95 | $ 63.91 | $ 70.61 |
Average sales price per unit (including realized commodity derivative gains/losses): | ||||
Oil price (per Bbl) | $ 81.50 | $ 86.05 | $ 82.72 | $ 85.78 |
Natural gas liquids price (per Gal) | $ 1.05 | $ 0.91 | $ 1.00 | $ 1.30 |
Natural gas price (per Mcf) | $ 5.90 | $ 5.65 | $ 5.93 | $ 7.41 |
Combined (per Boe) | $ 65.20 | $ 66.45 | $ 65.00 | $ 70.74 |
NYMEX oil index prices per Bbl: | ||||
Beginning of Period | $ 92.19 | $ 84.96 | $ 98.83 | $ 91.38 |
End of Period | $ 91.82 | $ 92.19 | $ 91.82 | $ 98.83 |
NYMEX gas index prices per Mcf: | ||||
Beginning of Period | $ 3.32 | $ 2.82 | $ 2.99 | $ 4.41 |
End of Period | $ 3.35 | $ 3.32 | $ 3.35 | $ 2.99 |
Average unit costs per Boe: | ||||
Oil and natural gas production | $ 19.59 | $ 20.76 | $ 19.08 | $ 18.37 |
Ad valorem taxes | $ 1.79 | $ 1.86 | $ 1.76 | $ 1.95 |
Production and other taxes | $ 3.96 | $ 3.78 | $ 3.83 | $ 4.26 |
General and administrative excluding LTIP | $ 4.18 | $ 3.57 | $ 3.87 | $ 4.00 |
Total general and administrative | $ 4.09 | $ 5.15 | $ 4.52 | $ 4.84 |
Depletion, depreciation, amortization and accretion | $ 20.11 | $ 18.27 | $ 18.84 | $ 18.48 |
Non-GAAP Financial Measures
This press release, the financial tables and other supplemental information include "Adjusted EBITDA" and "Distributable Cash Flow", both of which are non-generally accepted accounting principles ("non-GAAP") measures which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of each of these non-GAAP financial measures to their nearest comparable generally accepted accounting principles ("GAAP") measure.
Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information and metrics relative to the performance of our business, such as the cash distributions we expect to pay to our unitholders. Management believes that both Adjusted EBITDA and Distributable Cash Flow are useful to investors because these measures are used by many companies in the industry as measures of operating and financial performance, and are commonly employed by financial analysts and others to evaluate the operating and financial performance of the Partnership from period to period and to compare it with the performance of other publicly traded partnerships within the industry. Adjusted EBITDA and Distributable Cash Flow may not be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.
"Adjusted EBITDA" and "Distributable Cash Flow" should not be considered as alternatives to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.
Adjusted EBITDA is defined as net income (loss) plus:
Distributable Cash Flow is defined as Adjusted EBITDA less:
* Beginning in the first quarter of 2013, Legacy intends to deduct only maintenance capital expenditures instead of total development capital expenditures in the computation and presentation of Distributable Cash Flow, which will result in the measure of Distributable Cash Flow not being comparable from period to period.
The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:
Three Months Ended | Twelve Months Ended | |||
December 31, | September 30, | December 31, | ||
2012 | 2012 | 2012 | 2011 | |
(dollars in thousands) | ||||
Net income (loss) | $ 1,872 | $ (23,566) | $ 68,637 | $ 72,061 |
Plus: | ||||
Interest expense | 6,003 | 5,285 | 20,260 | 18,566 |
Income tax expense | 218 | 54 | 1,096 | 1,030 |
Depletion, depreciation, amortization and accretion | 29,102 | 24,833 | 102,144 | 88,178 |
Impairment of long-lived assets | 14,510 | 7,277 | 37,066 | 24,510 |
(Gain) loss on sale of assets | 568 | 260 | (2,496) | (625) |
Equity in income of partnership | (23) | (30) | (111) | (138) |
Unit-based compensation expense (benefit) | (124) | 2,138 | 3,546 | 4,021 |
Unrealized (gains) losses on oil and natural gas derivatives | (525) | 33,285 | (32,591) | (6,220) |
Adjusted EBITDA | $ 51,601 | $ 49,536 | $ 197,551 | $ 201,383 |
Less: | ||||
Cash interest expense | 6,991 | 5,283 | 21,387 | 19,044 |
Cash settlements of LTIP unit awards | 184 | 990 | 3,555 | 2,916 |
Development capital expenditures | 19,693 | 19,565 | 68,150 | 71,589 |
Distributable Cash Flow | $ 24,733 | $ 23,698 | $ 104,459 | $ 107,834 |
CONTACT: Legacy Reserves LP Dan Westcott Executive Vice President and Chief Financial Officer (432) 689-5200