Legacy Reserves LP Announces Fourth Quarter 2013 Results, Annual 2013 Results and 2014 Guidance

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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:

  • Production increased 33% to an annual record of 19,668 Boe/d from 14,811 Boe/d in 2012 primarily due to (i) a full-year impact of $635.4 million of acquisitions of producing properties during 2012, including our $502.6 million of Permian Basin properties from Concho Resources Inc. that closed on December 20, 2012 ("2012 Concho Acquisition"); (ii) $108.4 million of acquisitions of oil-weighted properties during 2013; and (iii) a record $94.0 million of development capital expenditures during 2013.
  • Adjusted EBITDA increased 38% to a record $272.7 million from $197.6 million in 2012, as the impact of increased production and commodity prices was partially offset by increased expenses and cash settlements paid on commodity derivatives.
  • Year-end proved reserves increased 5% to a record 87.6 MMBoe (85% PDP, 70% liquids), as acquisitions added 5.1 MMBoe, development activities and improved performance added 4.9 MMBoe, and increased commodity prices added 2.1 MMBoe, which were partially offset by a 7.2 MMBoe decrease from production.

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:

  • Production decreased 3% to 19,402 Boe/d compared to 20,043 Boe/d in the third quarter primarily due to the impact of severe winter weather and ongoing third-party infrastructure issues in the Permian Basin. These factors were partially offset by strong production from two operated horizontal Bone Spring wells as well as recent oil-weighted acquisitions. The net impact of these factors disproportionately impacted our natural gas production, which declined 8% from the third quarter compared to relatively flat liquids production.
  • Adjusted EBITDA was $64.2 million compared to $76.2 million in the third quarter, as lower production, lower oil prices and higher LOE were partially offset by higher natural gas prices, lower taxes and lower settlements paid on commodity derivatives.
  • Our distribution was increased for the 13th consecutive quarter, ending the year at $0.59 per unit, which represents 3.5% year-over-year growth and 44% growth since our IPO in January 2007.

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

  • Production increased 33% to an annual record of 19,668 Boe/d from 14,811 Boe/d primarily due to (i) a full-year impact of our $635.4 million of acquisitions of producing properties during 2012, including production from our 2012 Concho Acquisition for $502.6 million that closed on December 20, 2012; (ii) $108.4 million of acquisitions of oil-weighted properties during 2013; and (iii) our record $94.0 million of development activities that were primarily focused on oil-weighted projects in the Permian Basin, most notably our Wolfberry drilling program and two operated horizontal Bone Spring wells that were completed in late 2013. These increases were partially offset by third party infrastructure issues that mostly impacted our natural gas production in the Permian Basin throughout the year as well as the impact of severe winter weather on our production during the fourth quarter of 2013.
  • Average realized price, excluding net cash settlements from commodity derivatives, increased 6% to $67.63 per Boe in 2013 from $63.91 per Boe in 2012. Average realized oil price increased 6% to $90.62 per Bbl in 2013 from $85.78 per Bbl in 2012. This increase of $4.84 per Bbl was primarily attributable to an increase in the average West Texas Intermediate ("WTI") crude oil price of $3.93 per Bbl. Average realized natural gas price increased 5% to $4.60 per Mcf in 2013 from $4.38 per Mcf in 2012 reflecting an $0.87 increase in the average Henry Hub natural gas index price that was mostly offset by lower, positive differentials primarily due to the curtailment of a portion of our NGL-rich natural gas production in the Permian Basin. Finally, our average realized NGL price increased 6% to $1.06 per gallon in 2013 from $1.00 per gallon in 2012. The large majority of our separately reported NGL production is from our Mid-Continent region.
  • Production expenses, excluding ad valorem taxes, increased 38% to $142.8 million in 2013 from $103.4 million in 2012. On an average cost per Boe basis, production expenses increased 4% to $19.89 per Boe in 2013 from $19.08 per Boe in 2012. Production expenses increased primarily due to acquisitions and remedial workovers and other well failure expenses associated with those acquisitions. To a lesser extent, expenses associated with Legacy's development activities also contributed to the increase in production expenses.
  • Legacy's general and administrative expenses excluding unit-based/Long-Term Incentive Plan ("LTIP") compensation expense totaled $24.1 million in 2013 compared to $21.0 million in 2012. This increase was mostly attributable to an increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base. Legacy's total general and administrative expenses were $28.9 million in 2013 compared to $24.5 million during 2012, as LTIP expense increased by approximately $1.3 million in 2013 due to an increase in our unit price between December 31, 2012 and December 31, 2013.
  • Cash settlements paid on our commodity derivatives during 2013 were $7.1 million, as the $14.2 million paid on our crude oil hedges was partially offset by $7.1 million received on our natural gas hedges. This $7.1 million in cash settlements paid compared to $5.9 million received during 2012.
  • Total development capital expenditures increased to $94.0 million in 2013 from $68.2 million in 2012, as we continued our one-rig Wolfberry program throughout 2013, drilled two horizontal Bone Spring wells in late 2013, and increased our other operated and non-operated drilling and capital workover activity, most of which was in the Permian Basin. Our non-operated capital expenditures were 27% of our total capital expenditures in 2013 as compared to 23% in 2012.

2013 Financial and Operating Results – Fourth Quarter Compared to Third Quarter

  • Production decreased by 3% to 19,402 Boe/d compared to 20,043 Boe/d in the prior quarter primarily due to the impact of severe winter weather and ongoing third-party infrastructure issues in the Permian Basin. These factors were partially offset by strong production from two operated horizontal Bone Spring wells, which initiated production in early September and early November, as well as recent oil-weighted acquisitions. The net impact of these factors disproportionately impacted our natural gas production, which declined 8% compared to the third quarter, while oil production only declined 1% and NGL production remained relatively flat.
  • Average realized price, excluding commodity derivatives settlements, was $68.37 per Boe, down 7% from $73.85 per Boe in the third quarter. Average realized oil price decreased 13% to $89.24 per Bbl from $102.01 per Bbl. Average WTI crude oil price decreased approximately $8.33 per Bbl, and crude oil differentials deteriorated in both the Permian Basin and the Rockies. The Midland-to-Cushing/WTI differential widened to -$2.36 per Bbl from -$0.29 per Bbl, and we expect this differential to be -$2.75 to -$3.25 per Bbl during the first quarter of 2014. Our Midland-to-Cushing basis hedges partially mitigated this swing in the fourth quarter as we hedged 8,000 Bbl/d at -$1.47 per Bbl. We recently hedged approximately 1,450 Bbl/d of our first quarter 2014 Midland-to-Cushing exposure at -$1.75 per Bbl. Average realized natural gas price increased 16% to $5.03 per Mcf from $4.34 per Mcf in the third quarter due to an improvement in the positive differential to Henry Hub prices, which reflects higher NGL prices in the Permian Basin. Average realized price on our separately reported NGLs increased 6% to $1.11 per gallon from $1.05 per gallon.
  • Production expenses, excluding ad valorem taxes, increased 8% to $39.5 million ($22.12 per Boe) from $36.7 million ($19.88 per Boe) in the third quarter. This increase was primarily due to higher workover and other well failure expenses of an incremental $1.5 million.
  • Legacy's general and administrative expenses excluding LTIP compensation expense declined slightly to $6.4 million compared to $6.6 million in the third quarter. Legacy's total general and administrative expenses also declined similarly to $7.6 million from $7.9 million.
  • Cash settlements paid on our commodity derivatives were $2.4 million compared to $6.0 million paid during the third quarter. The decrease in WTI crude oil prices between September and December resulted in a negative one-month lag effect of $2.2 million on our crude oil hedges.
  • Total development capital expenditures increased to $28.6 million compared to $26.1 million in the third quarter. Our level of operated activity was similar to our activity in the third quarter, as we continued our Wolfberry drilling program, drilled and completed the second of our two operated horizontal Bone Spring wells in 2013, and engaged in several other recompletion, capital workover and drilling projects mostly in the Permian Basin. Both Bone Spring wells completed in September and November generated strong initial results and our Wolfberry program continues to deliver. Our non-operated capital expenditures, which were focused on attractive, oil-weighted projects in the Permian Basin, increased in the fourth quarter and accounted for approximately 27% of our total development capital compared to 18% in the 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:

  • Interest expense;
  • Income taxes;
  • Depletion, depreciation, amortization and accretion;
  • Impairment of long-lived assets;
  • (Gain) loss on sale of partnership investment;
  • (Gain) loss on disposal of assets;
  • Equity in (income) loss of equity method investees;
  • Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods;
  • Minimum payments received in excess of overriding royalty interest earned;
  • Equity in EBITDA of equity method investee;
  • Net (gains) losses on commodity derivatives; and
  • Net cash settlements received (paid) on commodity derivatives.

Distributable Cash Flow is defined as Adjusted EBITDA less:

  • Cash interest expense including the accrual of interest expense related to our senior notes which is paid on a semi-annual basis;
  • Cash income taxes;
  • Cash settlements of LTIP unit awards; and
  • Estimated maintenance capital expenditures.

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.

CONTACT: Legacy Reserves LP Dan Westcott Executive Vice President and Chief Financial Officer (432) 689-5200

Source:Legacy Reserves LP