MIDLAND, Texas, Feb. 19, 2014 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced annual and fourth quarter results for 2013 as well as financial guidance for 2014. 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 21, 2014.
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, | ||
2013 | 2013 | 2013 | 2012 | |
(dollars in millions) | ||||
Production (Boe/d) | 19,402 | 20,043 | 19,668 | 14,811 |
Revenue | $122.0 | $136.2 | $485.5 | $346.5 |
Net Income (Loss) | ($46.9) | ($3.4) | ($35.3) | $68.6 |
Adjusted EBITDA (*) | $64.2 | $76.2 | $272.7 | $197.6 |
Distributable Cash Flow (*) | $32.4 | $44.1 | $150.5 | $104.5 |
* 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. |
2013 highlights include:
As announced on December 4, 2013 and as reported by other operators, severe winter weather and infrastructure issues negatively impacted operations in the Permian Basin in Q4. While we experienced no material long-term property damage, our production was temporarily curtailed or shut-in throughout numerous fields. This anomalous event created a shortfall in production and corresponding cash flow. Notable Q4 2013 results, inclusive of the impact of these disruptions, include:
Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, commented: "After a record acquisition year in 2012, Legacy focused on integration and execution in 2013, generating record production, Adjusted EBITDA and proved reserves. We increased our annual production by 33% to over 19,600 Boe per day despite third-party infrastructure issues and severe winter weather that impacted our Permian Basin production. We increased our Adjusted EBITDA by 38% to approximately $273 million and our proved reserves by 5% to 87.6 MMBoe. Our integration of the 2012 Concho Acquisition, which was the largest in our history, went very smoothly thanks to the hard work and dedication of our employees. We remain pleased with the results from these assets during our first year of ownership and are encouraged about their potential.
"On the acquisition front in 2013, we closed 16 acquisitions of oil-weighted properties for approximately $108 million, of which approximately 90% were in the Permian Basin. Although we pursued a record number of acquisition opportunities in 2013, we fell well short of our goal as acquisition prices were rich, particularly in the Permian Basin. While the timing of acquisitions can be unpredictable and uneven, we have closed 33 deals for over $740 million of producing properties over the last two years and over 120 deals for over $1.6 billion of producing properties since 2006. We continue to stay very active in evaluating a broad variety of acquisition opportunities and strive to be vigilant in our approach. Given our historical success and our current record inventory of potential opportunities, we are excited about our acquisition prospects in 2014.
"On the development front, we are pleased with the results of our oil-focused drilling efforts in the Permian Basin. Our one-rig program in the Wolfberry continues to go well and our horizontal Bone Spring drilling is outperforming expectations. In November, we brought another well online that is comparable to the impressive results of our September 2013 and November 2012 wells. For 2014, our Board recently approved our proposed $100 million capital budget. Key contributors in our operated program will be numerous Wolfberry wells and three additional horizontal Bone Spring wells. In a bit of a change, we also plan on spending about $10 million on long-term focused capital including operated waterflood projects in the Cooper Jal and Fullerton fields, two non-operated waterflood projects and facilities capital. While this capital generates no incremental 2014 production, we believe this is the right kind of work for us to be doing for the long-term benefit of the Company and its unitholders. Other non-operated projects, based on our partners' current plans, include the drilling of additional horizontal Bone Spring, Yeso, and Bakken wells as well as at least one horizontal Wolfcamp well.
"Despite the impacts of third-party infrastructure issues and severe winter weather, we generated outstanding operational and financial results during 2013. Given this performance, our promising acquisition outlook and attractive development inventory, we increased our distribution for the 13th consecutive quarter to $0.59 per unit, resulting in year-over-year distribution growth of 3.5%. For the year, we generated Distributable Cash Flow of $150.5 million, covering our annual distributions by 1.12 times."
Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "Legacy had another strong year of growth in 2013 as evidenced by our record operational and financial results. Along with the accomplishments that Cary discussed, we also positioned our balance sheet for future growth in 2013 with an opportunistic offering of $250 million of senior unsecured notes at an attractive interest rate of 6.625%. Due to this financing and our current borrowing base of $800 million, we have approximately $465 million of availability as of February 1, 2014 for future acquisitions and development projects.
"We have also recently made some significant additions and changes to our hedge portfolio. In December 2013, we completed a costless restructuring of all of our 2014 crude oil 3-way collars with $90 or $85 per Bbl long puts in exchange for swaps with identical volumes and tenors at an average price of $95.49 per Bbl, adding further stability to our 2014 cash flows at an attractive oil price. In addition, we took advantage of the recent surge in natural gas prices due to an abnormally cold winter to hedge most of our expected dry natural gas exposure in 2015 as well as a portion of our 2016 exposure.
"With an attractive hedge portfolio, favorable conditions in the capital markets and ample availability under our credit facility, we are well positioned to execute on our growth initiatives in 2014 and beyond."
2014 Guidance
The following table sets forth certain assumptions being used by Legacy to estimate its anticipated results of operations for 2014. These estimates do not include any acquisitions of additional oil or natural gas properties. In addition, these estimates are based on, among other things, assumptions of capital expenditure levels, current indications of supply and demand for oil and natural gas and current operating and labor costs. The guidance set forth below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. The guidance below sets forth management's best estimate based on current and anticipated market conditions and other factors. While we believe that these estimates and assumptions are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate, as set forth under "Cautionary Statement Relevant to Forward-Looking Information."
($ in thousands unless otherwise noted) | FY 2014E Range | ||
Production: | |||
Oil (MBbls) | 4,530 | -- | 4,650 |
Natural gas liquids (MGal) | 12,100 | -- | 12,400 |
Natural gas (MMcf) | 13,250 | -- | 13,600 |
Total (MBoe) | 7,026 | -- | 7,212 |
Average daily production (Boe/d) | 19,250 | -- | 19,759 |
Weighted Average NYMEX Differentials: | |||
Oil (per Bbl) | ($6.25) | -- | ($7.50) |
NGL realization (1) | 1.00% | -- | 1.10% |
Natural gas (per Mcf) | $0.95 | -- | $1.05 |
Expenses: | |||
Oil and natural gas production expenses ($/Boe) | $21.10 | -- | $22.20 |
Ad valorem and production taxes (% of revenue) | 9.00% | -- | 9.50% |
Cash G&A expenses (2) | $28,600 | -- | $30,100 |
Capital expenditures: | |||
Total development capital expenditures | $100,000 | -- | $100,000 |
Estimated maintenance capital expenditures | $71,200 | -- | $71,200 |
(1) Represents the projected percentage of WTI crude oil prices divided by 42, as we report NGLs in gallons. | |||
(2) 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 – 2013 Compared to 2012
2013 Financial and Operating Results – Fourth Quarter Compared to Third Quarter
Proved Reserves
Our proved reserves by operating region as of December 31, 2013 are as follows:
Operating Regions |
Oil (MBbls) |
Gas (MMcf) |
NGLs (MBbls) |
Total (MBoe) |
% Liquids |
% PDP |
% Total |
Permian Basin | 44,127 | 139,811 | 593 | 68,022 | 65.7% | 81.8% | 77.6% |
Mid-Continent | 3,230 | 15,637 | 3,429 | 9,265 | 71.9% | 98.0% | 10.6% |
Rocky Mountain | 9,549 | 2,302 | 14 | 9,946 | 96.1% | 93.9% | 11.4% |
Other | 124 | 1,270 | 39 | 375 | 43.5% | 100.0% | 0.4% |
Total | 57,030 | 159,020 | 4,075 | 87,608 | 69.7% | 85.0% | 100.0% |
New Commodity Derivatives Contracts
Since we filed our 3rd quarter Form 10-Q, we completed a costless restructuring of a portion of our 2014 oil derivatives and entered into several new Henry Hub natural gas, WTI crude oil and Midland-to-Cushing crude oil differential derivatives contracts, which are summarized as follows:
Costless Restructuring:
We completed a costless restructuring of all of our 2014 WTI crude oil 3-way collars with $90 or $85 per Bbl long puts in exchange for swaps with identical volumes and tenors. Summaries are as follows:
Old WTI Crude Oil 3-Way Collars:
Average Short | Average Long | Average Short | ||
Time Period | Volumes (Bbls) | Put Price per Bbl | Put Price per Bbl | Call Price per Bbl |
2014 | 1,038,380 | $62.41 | $87.68 | $107.18 |
New WTI Crude Oil Swaps:
Average | ||
Time Period | Volumes (Bbls) | Price per Bbl |
2014 | 1,038,380 | $95.49 |
WTI Crude Oil Swaps:
Average | ||
Time Period | Volumes (Bbls) | Price per Bbl |
Q1 2014 | 90,000 | $98.57 |
Midland-to-Cushing/WTI Crude Oil Differential Swaps:
Average | ||
Time Period | Volumes (Bbls) | Price per Bbl |
Q1 2014 | 132,000 | ($1.75) |
Henry Hub Natural Gas Swaps:
Average | ||
Time Period | Volumes (MMBtu) | Price per MMBtu |
2015 | 3,360,000 | $4.16 |
2016 | 1,200,000 | $4.12 |
Henry Hub Natural Gas 3-Way Collars:
Average Short Put | Average Long Put | Average Short Call | ||
Time Period | Volumes (MMBtu) | Price per MMBtu | Price per MMBtu | Price per MMBtu |
2015 | 1,440,000 | $3.25 | $4.05 | $4.49 |
Commodity Derivatives Contracts
We have entered into the following oil and natural gas derivatives contracts to help mitigate the risk of changing commodity prices. As of February 19, 2014, we had entered into derivatives agreements to receive average NYMEX WTI crude oil prices; Midland-to-Cushing crude oil differentials; and NYMEX Henry Hub, Waha, ANR-Oklahoma, and CIG-Rockies natural gas prices as summarized below:
WTI Crude Oil Swaps:
Average | Price | ||
Time Period | Volumes (Bbls) | Price per Bbl | Range per Bbl |
2014 | 3,087,144 | $93.52 | $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 |
WTI Crude Oil 3-Way Collars:
Average Short | Average Long | Average Short | ||
Time Period | Volumes (Bbls) | Put Price per Bbl | Put Price per Bbl | Call Price per Bbl |
2014 | 780,500 | $71.78 | $96.78 | $110.53 |
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 |
WTI Crude Oil Enhanced Swaps:
Average Long | Average Short | Average Swap | ||
Time Period | Volumes (Bbls) | Put Price per Bbl | Put Price per Bbl | Price per Bbl |
2015 | 365,000 | $60.00 | $80.00 | $92.35 |
2016 | 183,000 | $57.00 | $82.00 | $91.70 |
2017 | 182,500 | $57.00 | $82.00 | $90.85 |
2018 | 127,750 | $57.00 | $82.00 | $90.50 |
Average Short | Average Swap | ||
Time Period | Volumes (Bbls) | Put Price per Bbl | Price per Bbl |
2015 | 365,000 | $70.00 | $92.03 |
Midland-to-Cushing/WTI Crude Oil Differential Swaps:
Average | Price | ||
Time Period | Volumes (Bbls) | Price per Bbl | Range per Bbl |
Q1 2014 | 132,000 | ($1.75) | ($1.75) |
Natural Gas Swaps (Henry Hub, WAHA, ANR-Oklahoma and CIG-Rockies):
Average | Price | ||
Time Period | Volumes (MMBtu) | Price per MMBtu | Range per MMBtu |
2014 | 8,271,254 | $4.32 | $3.61 - $6.47 |
2015 | 4,699,300 | $4.58 | $4.15 - $5.82 |
2016 | 1,419,200 | $4.30 | $4.12 - $5.30 |
Natural Gas 3-Way Collars (Henry Hub):
Average Short Put | Average Long Put | Average Short Call | ||
Time Period | Volumes (MMBtu) | Price per MMBtu | Price per MMBtu | Price per MMBtu |
2015 | 1,440,000 | $3.25 | $4.05 | $4.49 |
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 2013 Form 10-K which will be filed on or about February 21, 2014.
Conference Call
As announced on January 24, 2014, Legacy will host an investor conference call to discuss Legacy's results on Thursday, February 20, 2014 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 Thursday, February 27, 2014, by dialing 855-859-2056 or 404-537-3406 and entering replay code 36679747. 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 a master 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, | ||
2013 | 2013 | 2013 | 2012 | |
(In thousands, except per unit data) | ||||
Revenues: | ||||
Oil sales | $ 100,931 | $ 116,396 | $ 405,536 | $ 286,254 |
Natural gas liquids (NGL) sales | 3,906 | 3,686 | 14,095 | 14,592 |
Natural gas sales | 17,204 | 16,101 | 65,858 | 45,614 |
Total revenues | 122,041 | 136,183 | 485,489 | 346,460 |
Expenses: | ||||
Oil and natural gas production | 42,443 | 39,701 | 154,679 | 112,951 |
Production and other taxes | 7,425 | 8,385 | 29,508 | 20,778 |
General and administrative | 7,629 | 7,933 | 28,907 | 24,526 |
Depletion, depreciation, amortization and accretion | 39,933 | 37,717 | 158,415 | 102,144 |
Impairment of long-lived assets | 62,405 | 835 | 85,757 | 37,066 |
(Gain) loss on disposal of assets | 86 | 758 | 579 | (2,496) |
Total expenses | 159,921 | 95,329 | 457,845 | 294,969 |
Operating income (loss) | (37,880) | 40,854 | 27,644 | 51,491 |
Other income (expense): | ||||
Interest income | 207 | 227 | 776 | 16 |
Interest expense | (13,985) | (14,206) | (50,089) | (20,260) |
Equity in income of equity method investees | 203 | 172 | 559 | 111 |
Net gains (losses) on commodity derivatives | 4,568 | (30,424) | (13,531) | 38,493 |
Other | 29 | (16) | 18 | (118) |
Income (loss) before income taxes | (46,858) | (3,393) | (34,623) | 69,733 |
Income tax expense | (41) | (29) | (649) | (1,096) |
Net income (loss) | $ (46,899) | $ (3,422) | $ (35,272) | $ 68,637 |
Income (loss) per unit -- | ||||
basic and diluted | $ (0.82) | $ (0.06) | $ (0.62) | $ 1.40 |
Weighted average number of units used in computing net income (loss) per unit -- | ||||
Basic | 57,280 | 57,275 | 57,220 | 48,991 |
Diluted | 57,280 | 57,275 | 57,220 | 48,991 |
LEGACY RESERVES LP | ||
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) | ||
(dollars in thousands) | ||
December 31, | December 31, | |
2013 | 2012 | |
ASSETS | ||
Current assets: | ||
Cash and cash equivalents | $ 2,584 | $ 3,509 |
Accounts receivable, net: | ||
Oil and natural gas | 47,429 | 37,547 |
Joint interest owners | 16,532 | 27,851 |
Other | 626 | 551 |
Fair value of derivatives | 3,801 | 15,158 |
Prepaid expenses and other current assets | 3,727 | 3,294 |
Total current assets | 74,699 | 87,910 |
Oil and natural gas properties, at cost: | ||
Proved oil and natural gas properties using the successful efforts method of accounting | 2,265,788 | 2,078,961 |
Unproved properties | 58,392 | 65,968 |
Accumulated depletion, depreciation, amortization and impairment | (788,751) | (573,003) |
1,535,429 | 1,571,926 | |
Other property and equipment, net of accumulated depreciation and amortization of $6,053 and $4,618, respectively | 3,688 | 2,646 |
Operating rights, net of amortization of $4,024 and $3,531, respectively | 2,992 | 3,486 |
Fair value of derivatives | 21,292 | 15,834 |
Other assets, net of amortization of $10,097 and $7,909, respectively | 17,641 | 7,804 |
Investments in equity method investees | 4,092 | 393 |
Total assets | $ 1,659,833 | $ 1,689,999 |
LIABILITIES AND UNITHOLDERS' EQUITY | ||
Current liabilities: | ||
Accounts payable | $ 6,016 | $ 1,822 |
Accrued oil and natural gas liabilities | 63,161 | 50,162 |
Fair value of derivatives | 10,060 | 10,801 |
Asset retirement obligation | 2,610 | 29,501 |
Other | 12,043 | 11,437 |
Total current liabilities | 93,890 | 103,723 |
Long-term debt | 878,693 | 775,838 |
Asset retirement obligation | 173,176 | 132,682 |
Fair value of derivatives | 2,119 | 5,590 |
Other long-term liabilities | 1,559 | 1,886 |
Total liabilities | 1,149,437 | 1,019,719 |
Commitments and contingencies | ||
Unitholders' equity: | ||
Limited partners' equity - 57,280,049 and 57,038,942 units issued and outstanding at December 31, 2013 and December 31, 2012, respectively | 510,322 | 670,183 |
General partner's equity (approximately 0.03%) | 74 | 97 |
Total unitholders' equity | 510,396 | 670,280 |
Total liabilities and unitholders' equity | $ 1,659,833 | $ 1,689,999 |
LEGACY RESERVES LP | ||||||
SELECTED FINANCIAL AND OPERATING DATA | ||||||
Three Months Ended | Twelve Months Ended | |||||
December 31, | September 30, | December 31, | ||||
2013 | 2013 | 2013 | 2012 | |||
(In thousands, except per unit data) | ||||||
Revenues: | ||||||
Oil sales | $ 100,931 | $ 116,396 | $ 405,536 | $ 286,254 | ||
Natural gas liquids (NGL) sales | 3,906 | 3,686 | 14,095 | 14,592 | ||
Natural gas sales | 17,204 | 16,101 | 65,858 | 45,614 | ||
Total revenues | $ 122,041 | $ 136,183 | $ 485,489 | $ 346,460 | ||
Expenses: | ||||||
Oil and natural gas production | $ 39,490 | $ 36,659 | $ 142,798 | $ 103,409 | ||
Ad valorem taxes | 2,953 | 3,042 | 11,881 | 9,542 | ||
Total oil and natural gas production including ad valorem taxes | $ 42,443 | $ 39,701 | $ 154,679 | $ 112,951 | ||
Production and other taxes | $ 7,425 | $ 8,385 | $ 29,508 | $ 20,778 | ||
General and administrative excluding LTIP | $ 6,429 | $ 6,648 | $ 24,093 | $ 20,980 | ||
LTIP expense | 1,200 | 1,285 | 4,814 | 3,546 | ||
Total general and administrative | $ 7,629 | $ 7,933 | $ 28,907 | $ 24,526 | ||
Depletion, depreciation, amortization and accretion | $ 39,933 | $ 37,717 | $ 158,415 | $ 102,144 | ||
Net cash settlements on commodity derivatives: | ||||||
Net cash settlements paid on oil derivatives | $ (4,449) | $ (8,006) | $ (14,160) | $ (10,211) | ||
Net cash settlements received on natural gas derivatives | $ 2,058 | $ 2,054 | $ 7,104 | $ 16,113 | ||
Production: | ||||||
Oil (MBbls) | 1,131 | 1,141 | 4,475 | 3,337 | ||
Natural gas liquids (MGal) | 3,532 | 3,527 | 13,272 | 14,607 | ||
Natural gas (MMcf) | 3,419 | 3,714 | 14,328 | 10,417 | ||
Total (MBoe) | 1,785 | 1,844 | 7,179 | 5,421 | ||
Average daily production (Boe/d) | 19,402 | 20,043 | 19,668 | 14,811 | ||
Average sales price per unit (excluding net cash settlements on commodity derivatives): | ||||||
Oil price (per Bbl) | $ 89.24 | $ 102.01 | $ 90.62 | $ 85.78 | ||
Natural gas liquids price (per Gal) | $ 1.11 | $ 1.05 | $ 1.06 | $ 1.00 | ||
Natural gas price (per Mcf) | $ 5.03 | $ 4.34 | $ 4.60 | $ 4.38 | ||
Combined (per Boe) | $ 68.37 | $ 73.85 | $ 67.63 | $ 63.91 | ||
Average sales price per unit (including net cash settlements on commodity derivatives): | ||||||
Oil price (per Bbl) | $ 85.31 | $ 95.00 | $ 87.46 | $ 82.72 | ||
Natural gas liquids price (per Gal) | $ 1.11 | $ 1.05 | $ 1.06 | $ 1.00 | ||
Natural gas price (per Mcf) | $ 5.63 | $ 4.89 | $ 5.09 | $ 5.93 | ||
Combined (per Boe) | $ 67.03 | $ 70.62 | $ 66.64 | $ 65.00 | ||
Average WTI oil spot price (per Bbl) | $ 97.50 | $ 105.83 | $ 97.98 | $ 94.05 | ||
Average Henry Hub natural gas index price (per Mcf) | $ 3.60 | $ 3.58 | $ 3.66 | $ 2.79 | ||
Average unit costs per Boe: | ||||||
Oil and natural gas production | $ 22.12 | $ 19.88 | $ 19.89 | $ 19.08 | ||
Ad valorem taxes | $ 1.65 | $ 1.65 | $ 1.65 | $ 1.76 | ||
Production and other taxes | $ 4.16 | $ 4.55 | $ 4.11 | $ 3.83 | ||
General and administrative excluding LTIP | $ 3.60 | $ 3.61 | $ 3.36 | $ 3.87 | ||
Total general and administrative | $ 4.27 | $ 4.30 | $ 4.03 | $ 4.52 | ||
Depletion, depreciation, amortization and accretion | $ 22.37 | $ 20.45 | $ 22.07 | $ 18.84 |
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 concerning the performance of our business and are used by investors and financial analysts to analyze and compare our current operating and financial performance relative to past performance and such performances relative to that of other publicly traded partnerships in the industry. Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other publicly traded limited partnerships or limited liability companies because all companies may not calculate such measures in the same manner.
Distributable Cash Flow is one of the factors used by the board of directors of our general partner (the "Board") to help determine the amount of Available Cash as defined in our partnership agreement, which is the amount to be distributed to unitholders for such period. Under our partnership agreement, Available Cash is defined generally to mean, cash on hand at the end of each quarter, plus working capital borrowings made after the end of the quarter, less cash reserves determined by our general partner. The Board determines whether to increase, maintain or decrease the current level of distributions in accordance with the provisions of our partnership agreement based on a variety of factors including without limitation Distributable Cash Flow, cash reserves established in prior periods, reserves established for future periods, borrowing capacity for working capital, temporary, one-time or uncharacteristic historical results, and forecasts of future period results including the impact of pending acquisitions. Management and the Board consider the long-term view of expected results in determining the amount of its distributions. Certain factors impacting Adjusted EBITDA and Distributable Cash Flow may be viewed as temporary, one-time in nature, or being offset by reserves from past performance or near-term future performance. Financial results are also driven by various factors that do not typically occur evenly throughout the year that are difficult to predict, including rig availability, weather, well performance, the timing of drilling and completions and near-term commodity price changes. Consistent with practices common to publicly traded partnerships, the Board historically has not varied the distribution it declares based on such timing effects.
"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:
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, | ||
2013 | 2013 | 2013 | 2012 | |
(dollars in thousands) | ||||
Net income (loss) | $ (46,899) | $ (3,422) | $ (35,272) | $ 68,637 |
Plus: | ||||
Interest expense | 13,985 | 14,206 | 50,089 | 20,260 |
Income tax expense | 41 | 29 | 649 | 1,096 |
Depletion, depreciation, amortization and accretion | 39,933 | 37,717 | 158,415 | 102,144 |
Impairment of long-lived assets | 62,405 | 835 | 85,757 | 37,066 |
(Gain) loss on disposal of assets | 86 | 758 | 579 | (2,496) |
Equity in income of equity method investees | (203) | (172) | (559) | (111) |
Unit-based compensation expense | 1,200 | 1,285 | 4,814 | 3,546 |
Minimum payments received in excess of overriding royalty interest earned (1) | 325 | 316 | 1,051 | -- |
Equity in EBITDA of equity method investee (2) | 282 | 219 | 727 | -- |
Net (gains) losses on commodity derivatives | (4,568) | 30,424 | 13,531 | (38,493) |
Net cash settlements received (paid) on commodity derivatives | (2,391) | (5,952) | (7,056) | 5,902 |
Adjusted EBITDA | $ 64,196 | $ 76,243 | $ 272,725 | $ 197,551 |
Less: | ||||
Cash interest expense | 13,918 | 14,058 | 51,171 | 21,387 |
Cash settlements of LTIP unit awards | 36 | 315 | 1,496 | 3,555 |
Estimated maintenance capital expenditures (3) | 17,800 | 17,800 | 69,600 | |
Total development capital expenditures | 68,150 | |||
Distributable Cash Flow (3) | $ 32,442 | $ 44,070 | $ 150,458 | $ 104,459 |
Distributions Attributable to Each Period (4) | $ 33,934 | $ 33,645 | $ 133,956 | $ 113,311 |
Distribution Coverage Ratio (3)(5) | 0.96x | 1.31x | 1.12x | 0.92x |
(1) Minimum payments received in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments are recognized in net income. | ||||
(2) EBITDA applicable to equity method investee is defined as the equity method investee's net income plus interest expense and depreciation. | ||||
(3) Beginning in the first quarter of 2013, Legacy began deducting estimated maintenance capital expenditures instead of total development capital expenditures in the computation and presentation of Distributable Cash Flow, which results in the measure of Distributable Cash Flow, and therefore also Distribution Coverage Ratio, not being comparable to any periods prior to 2013. Estimated maintenance capital expenditures are intended to represent the amount of capital required to fully offset declines in production, but do not target specific levels of proved reserves to be achieved. Estimated maintenance capital expenditures do not include the cost of new oil and natural gas reserve acquisitions, but rather the costs associated with converting proved developed non-producing, proved undeveloped and unproved reserves to proved developed producing reserves. These costs, which are incorporated in our annual capital budget as approved by the Board, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing production on both operated and non-operated properties. Estimated maintenance capital expenditures are based on management's judgment of various factors including the long-term (generally 5-10 years) decline rate of our current production and the projected productivity of our total development capital expenditures. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our production. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all. | ||||
(4) Represents the aggregate cash distributions declared for the respective period and paid by Legacy within 45 days after the end of each quarter within such period. | ||||
(5) We refer to the ratio of Distributable Cash Flow over Distributions Attributable to Each Period ("Available Cash" per our partnership agreement) as "Distribution Coverage Ratio." If the Distribution Coverage Ratio is equal to or greater than 1.0x, then our cash flows are sufficient to cover our quarterly distributions with respect to such period. If the Distribution Coverage Ratio is less than 1.0x, then our cash flows with respect to such period were not sufficient to cover our quarterly distributions and we must borrow funds or use cash reserves established in prior periods to cover our quarterly distributions. The Board uses its discretion in determining if such shortfalls are temporary or if distributions should be adjusted downward. |