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Legacy Reserves LP Announces Fourth Quarter and Annual 2014 Results, 2015 Guidance and New Chief Operating Officer

MIDLAND, Texas, Feb. 25, 2015 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (Nasdaq:LGCY) today announced fourth quarter and annual results for 2014 as well as financial guidance for 2015. 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, 2015.

A summary of selected financial information follows. For consolidated financial statements, please see accompanying tables.

Three Months Ended
December 31,
Twelve Months Ended
December 31,
2014 2013 2014 2013
(dollars in millions)
Production (Boe/d) 32,774 19,402 26,962 19,668
Revenue $ 119.6 $ 122.0 $ 532.3 $ 485.5
Net Loss (a) $ (331.5) $ (46.9) $ (283.6) $ (35.3)
Adjusted EBITDA (b) $ 64.7 $ 64.2 $ 278.2 $ 273.4
Distributable Cash Flow (b) $ 24.2 $ 32.5 $ 128.1 $ 151.2
(a) Includes non-cash impairment charges of $440.1 million and $62.4 million for the fourth quarter of 2014 and 2013, respectively, and $448.7 million and $85.8 million for the years ended December 31, 2014 and 2013, respectively.
(b) 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.

2014 highlights include:

  • Generated record annual production of 26,962 Boe/d up 37% from 19,668 Boe/d in 2013
  • Generated record annual EBITDA of $278.2 million
  • Completed $536.3 million of acquisitions including our $360.0 million acquisition of natural gas properties located in the Piceance Basin from WPX Energy, Inc.
  • Year-end proved reserves increased 59% to a record 139.0 MMBoe (90% PDP, 50% liquids)

Management Transition

Cary D. Brown, Chairman, President and Chief Executive Officer of Legacy Reserves GP, LLC, the general partner of Legacy, stated: "As previously released, this is my last week as CEO. I look forward to serving the company as I transition my role to Chairman. While we and our industry face an uphill battle given current commodity prices, I am extremely comforted by the team we have put in place to navigate these difficult waters. With our long-lived, low-decline assets, solid hedges, and ample liquidity under our revolver, we are well positioned for the future."

Paul T. Horne, currently Executive Vice President and Chief Operating Officer and soon-to-be President and Chief Executive Officer, commented, "First off, I'd like to thank Cary for all he has done in building and leading Legacy. I'm grateful for the opportunity that he and the Board have provided me and I look forward to leading the organization forward. We accomplished a great deal in 2014 and I would like to thank our employees for their hard work. We acquired over $530 million of properties this year including our strategic alliance with WPX. We posted record production and EBITDA and we raised a tremendous amount of long-term focused capital. All of these accomplishments put us in a better position today and for that I'm thankful.

"We undoubtedly face challenging commodity prices. While it's not fun, we've been here several times before, and we know what to do in this environment. We are reigning in costs across the board and we have dramatically reduced our capital budget, from $133 million in 2014 to $30 million in 2015. We expect service costs to fall commensurate with price and will continue to evaluate our capital budget options throughout the year.

Legacy is also pleased to announce the appointment of Kyle M. Hammond as Executive Vice President and Chief Operating Officer of Legacy Reserves GP, LLC effective March 1, 2015. Prior to joining Legacy, Mr. Hammond founded and served as President and Chief Executive Officer of FireWheel Energy LLC ("FireWheel") since August 2011. Prior to forming FireWheel, Mr. Hammond served as VP of Operations for the Permian Division of XTO Energy/Exxon from 2003 to August 2011. While there, Mr. Hammond managed the growth of the Permian assets as well as their Alaskan operations. Mr. Hammond earned a BS in Petroleum Engineering from Texas A&M University. Mr. Hammond currently serves on the board of directors of Abilene Christian University and Midland Christian School.

Mr. Horne added, "I am thrilled to have Kyle Hammond join the team. I've known Kyle since our time together at Texas A&M and respect the person, oilman, and Aggie engineer that he is. The operational, management and growth experience he gained at XTO will help us immensely at Legacy."

Credit Agreement Update

On February 23, 2015, Legacy amended the terms of its Credit Agreement. Principle modifications include the replacement of the Total Debt / EBITDA covenant with a maximum 2.5x Secured Debt / EBITDA covenant and a minimum 2.5x EBITDA / Interest covenant. The Partnership's year-end statistics for these two covenants were 0.4x and 4.1x. Legacy also agreed to reduce its borrowing base to $700 million from the prior $950 million. As of February 23, 2015, Legacy had approximately $130 million of borrowings outstanding, providing approximately $570 million of liquidity available.

Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "I'd like to say thank you to Wells Fargo and the rest of our 19-member bank group for their diligence and support in helping us get this amendment executed. With our new financial covenants, we have meaningfully increased our effective liquidity and have greater capacity to swiftly make accretive acquisitions in this market."

Proved Reserves

Our proved reserves by operating region as of December 31, 2014 are as follows:

Operating Regions Oil (MBbls) Natural
Gas (MMcf)
NGLs
(MBbls)
Total
(MBoe)
% Liquids % PDP % Total
Permian Basin 43,425 143,118 1,920 69,198 65.5 % 80.0 % 49.8 %
Rocky Mountain 10,252 254,358 6,918 59,563 28.8 % 99.0 % 42.9 %
Mid-Continent 3,163 17,483 3,200 9,277 68.6 % 97.9 % 6.7 %
Other 84 3,017 335 921 45.5 % 100.0% 0.6 %
Total 56,924 417,976 12,373 138,959 49.9 % 89.5 % 100.0 %

2015 Guidance

The following table sets forth certain assumptions used by Legacy to estimate its anticipated results of operations for 2015. 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."

FY 2015E Range
($ in thousands unless otherwise noted)
Production:
Oil (MBbls) 4,640 - 4,760
Natural gas liquids (MGal) 43,500 - 44,600
Natural gas (MMcf) 36,950 - 37,850
Total (MBoe) 11,834 - 12,130
Average daily production (Boe/d) 32,422 - 33,233
Weighted Average NYMEX Differentials:
Oil (per Bbl) $(8.00) - $(7.00)
NGL realization (1) 0.98% - 1.03%
Natural gas (per Mcf) $(0.20) - $(0.15)
Expenses:
Oil and natural gas production expenses ($/Boe) $15.30 - $16.50
Ad valorem and production taxes (% of revenue) 7.80% - 8.20%
Cash G&A expenses (2) $35,000 - $36,000
Capital expenditures:
Total development capital expenditures $30,000 - $30,000
Note: Figures above do not include any assumed acquisitions.
(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.
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
Three Months Ended
December 31,
Twelve Months Ended
December 31,
2014 2013 2014 2013
(In thousands, except per unit data)
Revenues
Oil sales $ 80,348 $ 100,931 $ 396,774 $ 405,536
Natural gas liquids sales 8,002 3,906 27,483 14,095
Natural gas sales 31,256 17,204 108,042 65,858
Total revenues $ 119,606 $ 122,041 $ 532,299 $ 485,489
Expenses:
Oil and natural gas production $ 53,222 $ 39,490 $ 186,750 $ 142,798
Ad valorem taxes 1,745 2,953 12,051 11,881
Total $ 54,967 $ 42,443 $ 198,801 $ 154,679
Production and other taxes $ 7,242 $ 7,425 $ 31,534 $ 29,508
General and administrative excluding LTIP $ 8,259 $ 6,429 $ 35,185 $ 24,093
LTIP expense (60) 1,200 3,795 4,814
Total general and administrative $ 8,199 $ 7,629 $ 38,980 $ 28,907
Depletion, depreciation, amortization and accretion $ 53,436 $ 39,933 $ 173,686 $ 158,415
Commodity derivative cash settlements:
Oil derivative cash settlements received (paid) $ 9,609 $ (4,449) $ (5,431) $ (14,160)
Natural gas derivative cash settlements received 5,031 2,058 8,097 7,104
Total commodity derivative cash settlements $ 14,640 $ (2,391) $ 2,666 $ (7,056)
Production:
Oil (MBbls) 1,253 1,131 4,784 4,475
Natural gas liquids (MGal) 11,283 3,532 30,861 13,272
Natural gas (MMcf) 8,966 3,419 25,936 14,328
Total (MBoe) 3,016 1,785 9,841 7,179
Average daily production (Boe/d) 32,783 19,402 26,962 19,668
Average sales price per unit (excluding commodity derivative cash settlements):
Oil price (per Bbl) $ 64.12 $ 89.24 $ 82.94 $ 90.62
Natural gas liquids price (per Gal) $ 0.71 $ 1.11 $ 0.89 $ 1.06
Natural gas price (per Mcf)(a) $ 3.49 $ 5.03 $ 4.17 $ 4.60
Combined (per Boe) $ 39.66 $ 68.37 $ 54.09 $ 67.63
Average sales price per unit (including commodity derivative cash settlements):
Oil price (per Bbl) $ 71.79 $ 85.31 $ 81.80 $ 87.46
Natural gas liquids price (per Gal) $ 0.71 $ 1.11 $ 0.89 $ 1.06
Natural gas price (per Mcf)(a) $ 4.05 $ 5.63 $ 4.48 $ 5.09
Combined (per Boe) $ 44.51 $ 67.03 $ 54.36 $ 66.64
Average WTI oil spot price (per Bbl) $ 73.20 $ 97.50 $ 92.91 $ 97.98
Average Henry Hub natural gas index price (per Mcf) $ 3.83 $ 3.60 $ 4.26 $ 3.66
Average unit costs per Boe:
Production costs, excluding production and other taxes $ 17.65 $ 22.12 $ 18.98 $ 19.89
Ad valorem taxes $ 0.58 $ 1.65 $ 1.22 $ 1.65
Production and other taxes $ 2.40 $ 4.16 $ 3.20 $ 4.11
General and administrative excluding LTIP $ 2.74 $ 3.60 $ 3.58 $ 3.36
Total general and administrative $ 2.72 $ 4.27 $ 3.96 $ 4.03
Depletion, depreciation, amortization and accretion $ 17.72 $ 22.37 $ 17.65 $ 22.07

Annual Financial and Operating Results - 2014 Compared to 2013

  • Production increased 37% to an annual record of 26,962 Boe/d from 19,668 Boe/d primarily due to $536.3 million of acquisitions in 2014 including our $360.0 million acquisition of non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy, Inc ("WPX Acquisition"). Additionally, production was positively impacted by our record $133.4 million of development capital expenditures during 2014.
  • Average realized price, excluding net cash settlements from commodity derivatives, decreased 20% to $54.09 per Boe in 2014 from $67.63 per Boe in 2013. This decrease in realized prices was primarily driven by the increase of NGL and natural gas production as a percentage of total production. For instance, in 2014 NGLs and natural gas accounted for approximately 51% of our total production compared to approximately 38% in 2013. This increase in lower priced production reduced our total price realization. Average realized oil price decreased 8% to $82.94 in 2014 from $90.62 in 2013. This decrease was primarily driven by a decrease in the average West Texas Intermediate ("WTI") crude oil price of $5.07 per Bbl as well as an increase in realized differentials, primarily in the Permian Basin. Average natural gas price decreased 9% to $4.17 per Mcf in 2014 from $4.60 per Mcf in 2013. While the average Henry Hub natural gas index price increased $0.60 per Mcf, this increase was more than offset by the inclusion of approximately 11,767 MMcf of lower priced natural gas production from the WPX Acquisition. Finally, our average realized NGL price decreased 16% to $0.89 per gallon in 2014 from $1.06 per gallon in 2013. This decrease is due to the inclusion of lower priced NGL production from the WPX Acquisition. The large majority of our separately reported NGL production is from the properties acquired in the WPX Acquisition and our Mid-Continent region.
  • Production expenses, excluding ad valorem taxes, increased 31% to $186.8 million in 2014 from $142.8 million in 2013. On an average cost per Boe basis, production expenses decreased 5% to $18.98 per Boe in 2014 from $19.89 per Boe in 2013, driven primarily by the inclusion of lower cost natural gas properties acquired in the WPX Acquisition.
  • Non-cash impairment expense totaled $448.7 million driven by the significant decline in oil and natural gas prices during the fourth quarter of 2014.
  • General and administrative expenses, excluding unit-based Long-Term Incentive Plan ("LTIP") compensation expense totaled $35.2 million in 2014 compared to $24.1 million in 2013. This increase was primarily due to $4.5 million of increased acquisition-related expenses and a $3.4 million increase in salary and benefit expenses.
  • Cash settlements received on our commodity derivatives during 2014 were $2.7 million, as the $8.1 million received on our natural gas hedges was partially offset by $5.4 million paid on our crude oil hedges. Comparably, in 2013 we paid cash settlements on our commodity derivatives of approximately $7.1 million.
  • Total development capital expenditures increased to $133.4 million in 2014 from $94.0 million in 2013, as we continued our one-rig Wolfberry program throughout 2014, drilled four horizontal Bone Spring wells, incurred capital costs related to our CO2 injection on properties acquired during 2014 and increased our other operated and non-operated drilling and capital workover activities, most of which were in the Permian Basin. Our non-operated capital expenditures were 28% of our total capital expenditures in 2014 as compared to 27% in 2013.

Financial and Operating Results - Fourth Quarter 2014 Compared to Fourth Quarter 2013

  • Production increased 69% to 32,772 Boe/d from 19,402 Boe/d primarily due to the WPX Acquisition and other recent acquisitions.
  • Average realized price, excluding net cash settlements from commodity derivatives, decreased 42% to $39.67 per Boe in 2014 from $68.37 per Boe in 2013 due to the significant increase in natural gas and NGL production as such products are generally less valuable per Boe than oil. Average realized oil price decreased 28% to $64.18 per Bbl in 2014 from $89.24 per Bbl in 2013. This decrease of $25.06 was primarily attributable to the sharp decline in the average WTI crude oil price of $24.30 combined with slightly higher realized regional differentials. Average realized natural gas prices declined 31% to $3.49 per Mcf in 2014 from $5.03 per Mcf in 2013. While the average Henry Hub natural gas price index increased by $0.23 per Mcf in 2014, this increase was more than offset by lower realized natural gas prices from natural gas production associated with the properties acquired in the WPX Acquisition. Finally, our average realized NGL price decreased 36% to $0.71 per gallon in 2014 from $1.11 per gallon in 2013 which was attributable to the lower priced production from the WPX Acquisition.
  • Production expenses, excluding ad valorem taxes, increased 35% to $53.2 million in 2014 from $39.5 million in 2013. Production expenses increased primarily due to expenses associated with our acquisitions, including $11.0 million related to the WPX Acquisition and, to a lesser extent, industry-wide cost increases. On a per Boe basis, production expenses decreased from $22.12 to $17.65 or 20% driven by acquisitions of properties with lower per Boe production expenses as well as cost reductions in our ongoing operations.
  • Non-cash impairment expense totaled $440.1 million due to the significant decline of oil and natural gas prices during the period.
  • General and administrative expenses, excluding LTIP compensation expense, increased to $8.3 million in 2014 from $6.4 million in 2013. This increase was primarily attributable to an increase in salary and benefit expenses related to the hiring of additional personnel to manage our larger asset base.
  • Cash settlements received on our commodity derivatives were $14.6 million during 2014 compared to cash settlements paid of $2.4 million in 2013, a reflection of the sharp decline in commodity prices during the fourth quarter of 2014. Additionally, as our crude oil derivatives settle one-month in arrears, we incurred a hedge-lag effect of approximately $10.5 million.
  • Total development capital expenditures were $42.0 million in the fourth quarter of 2014. Non-operated capital expenditures comprised 39% of our total capital expenditures during the period with activity primarily in the Permian.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of February 25, 2015, we had entered into derivative agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, NWPL, NGPA, SoCal, San Juan and CIG-Rockies natural gas prices as summarized below:

WTI Crude Oil Swaps:

Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl
2015 1,056,301 $93.93 $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:

Calendar Year Volumes (Bbls) Average Short Put
Price per Bbl
Average Long Put
Price per Bbl
Average Short Call
Price per Bbl
2015 1,362,800 $65.08 $89.69 $111.84
2016 621,300 $63.37 $88.37 $106.40
2017 72,400 $60.00 $85.00 $104.20

WTI Crude Oil Enhanced Swaps:

Calendar Year Volumes (Bbls) Average Short Put
Price per Bbl
Average Swap
Price per Bbl
2015 868,000 $76.59 $93.68
Calendar Year Volumes (Bbls) Average Long Put
Price per Bbl
Average Short Put
Price per Bbl
Average Swap
Price per Bbl
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

Midland-to-Cushing WTI Crude Oil Differential Swaps:

Time Period Volumes (Bbls) Average Price per Bbl Price Range per Bbl
2015 1,997,000 ($2.02) ($1.65) - ($2.55)

Natural Gas Swaps (Henry Hub, Waha and CIG-Rockies):

Calendar Year Volumes (MMBtu) Average
Price per MMBtu
Price Range per MMBtu
2015 18,619,300 $4.39 $3.98 - $5.82
2016 1,419,200 $4.30 $4.12 - $5.30

Natural Gas 3-Way Collars (Henry Hub):

Calendar Year Volumes
(MMBtu)
Average Short Put
Price per MMBtu
Average Long Put
Price per MMBtu
Average Short Call
Price per MMBtu
2015 8,040,000 $3.66 $4.21 $5.01
2016 5,580,000 $3.75 $4.25 $5.08
2017 5,040,000 $3.75 $4.25 $5.53

Natural Gas Basis Swaps (NWPL, NGPA, SoCal, San Juan and Waha):

2015
Volumes (MMBtu) Average
Price per MMBtu
NWPL 12,000,000 $(0.13)
NGPL 480,000 $(0.15)
SoCal 240,000 $0.19
San Juan 480,000 $(0.12)
WAHA 6,000,000 $(0.10)

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 2014 Form 10-K which will be filed on or about February 27, 2015.

Conference Call

As announced on January 23, 2015, Legacy will host an investor conference call to discuss Legacy's results on Thursday, February 26, 2015 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, March 5, 2015, by dialing 855-859-2056 or 404-537-3406 and entering replay code 70464452. 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, Rocky Mountain and Mid-Continent 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
December 31,
Twelve Months Ended
December 31,
2014 2013 2014 2013
(In thousands, except per unit data)
Revenues:
Oil sales $ 80,348 $ 100,931 $ 396,774 $ 405,536
Natural gas liquids (NGL) sales 8,002 3,906 27,483 14,095
Natural gas sales 31,256 17,204 108,042 65,858
Total revenues 119,606 122,041 532,299 485,489
Expenses:
Oil and natural gas production 54,967 42,443 198,801 154,679
Production and other taxes 7,242 7,425 31,534 29,508
General and administrative 8,199 7,629 38,980 28,907
Depletion, depreciation, amortization and accretion 53,436 39,933 173,686 158,415
Impairment of long-lived assets 440,130 62,405 448,714 85,757
(Gain) loss on disposal of assets 756 86 (2,479) 579
Total expenses 564,730 159,921 889,236 457,845
Operating income (loss) (445,124) (37,880) (356,937) 27,644
Other income (expense):
Interest income 211 207 873 776
Interest expense (17,971) (13,985) (67,218) (50,089)
Equity in income of equity method investees 119 203 428 559
Net gains (losses) on commodity derivatives 129,417 4,568 138,092 (13,531)
Other 120 29 258 18
Income (loss) before income taxes (333,228) (46,858) (284,504) (34,623)
Income tax (expense) benefit 1,729 (41) 859 (649)
Net income (loss) $ (331,499) $ (46,899) $ (283,645) $ (35,272)
Distributions to preferred unitholders (4,750) (11,694)
Net income (loss) attributable to unitholders $ (336,249) $ (46,899) $ (295,339) $ (35,272)
Income (loss) per unit — basic and diluted $ (4.94) $ (0.82) $ (4.92) $ (0.62)
Weighted average number of units used in
computing income (loss) per unit —
Basic 68,035 57,280 60,053 57,220
Diluted 68,035 57,280 60,053 57,220
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
December 31,
2014 2013
(In thousands)
ASSETS
Current assets:
Cash $ 725 $ 2,584
Accounts receivable, net:
Oil and natural gas 49,390 47,429
Joint interest owners 16,235 16,532
Other 237 626
Fair value of derivatives 120,305 3,801
Prepaid expenses and other current assets 5,362 3,727
Total current assets 192,254 74,699
Oil and natural gas properties, at cost:
Proved oil and natural gas properties using the successful efforts method of accounting 2,946,820 2,265,788
Unproved properties 47,613 58,392
Accumulated depletion, depreciation, amortization and impairment (1,354,459) (788,751)
1,639,974 1,535,429
Other property and equipment, net of accumulated depreciation and amortization of $7,446 and $6,053, respectively 3,767 3,688
Operating rights, net of amortization of $4,509 and $4,024, respectively 2,508 2,992
Fair value of derivatives 32,794 21,292
Other assets, net of amortization of $12,551 and $10,097, respectively 24,255 17,641
Investments in equity method investees 3,054 4,092
Total assets $ 1,898,606 $ 1,659,833
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable $ 2,787 $ 6,016
Accrued oil and natural gas liabilities 78,615 63,161
Fair value of derivatives 2,080 10,060
Asset retirement obligation 3,028 2,610
Other 11,066 12,043
Total current liabilities 97,576 93,890
Long-term debt 938,876 878,693
Asset retirement obligation 223,497 173,176
Fair value of derivatives 2,119
Other long-term liabilities 1,452 1,559
Total liabilities 1,261,401 1,149,437
Commitments and contingencies
Partners' equity:
Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2014 55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2014 174,261
Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2014 30,814
Limited partners' equity - 68,910,784 and 57,280,049 units issued and outstanding at December 31, 2014 and 2013, respectively 376,885 510,322
General partner's equity (approximately 0.03%) 53 74
Total partners' equity 637,205 510,396
Total liabilities and partners' equity $ 1,898,606 $ 1,659,833

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, that is to be distributed to our 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;
  • Net cash settlements received (paid) on commodity derivatives; and
  • Transaction expenses related to acquisitions.

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;
  • Estimated maintenance capital expenditures; and
  • Distributions on Series A and Series B preferred units.

The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:

Three Months Ended
December 31,
Twelve Months Ended
December 31,
2014 2013 2014 2013
(In thousands)
Net income (loss) $ (331,499) $ (46,899) $ (283,645) $ (35,272)
Plus:
Interest expense 17,971 13,985 67,218 50,089
Income tax expense (benefit) (1,729) 41 (859) 649
Depletion, depreciation, amortization and accretion 53,436 39,933 173,686 158,415
Impairment of long-lived assets 440,130 62,405 448,714 85,757
(Gain) loss on disposal of assets 756 86 (2,479) 579
Equity in income of equity method investees (119) (203) (428) (559)
Unit-based compensation expense (60) 1,200 3,795 4,814
Minimum payments received in excess of overriding royalty interest earned(1) 358 325 1,381 1,051
Equity in EBITDA of equity method investee(2) 156 282 805 727
Net (gains) losses on commodity derivatives (129,417) (4,568) (138,092) 13,531
Net cash settlements received (paid) on commodity derivatives 14,640 (2,391) 2,666 (7,056)
Transaction expenses related to acquisitions 95 35 5,425 722
Adjusted EBITDA $ 64,718 $ 64,231 $ 278,187 $ 273,447
Less:
Cash interest expense 17,597 13,918 65,236 51,171
Cash settlements of LTIP unit awards 1 36 772 1,496
Estimated maintenance capital expenditures(3) 18,200 17,800 72,400 69,600
Distributions on Series A and Series B preferred units 4,750 11,694
Distributable Cash Flow(3) $ 24,170 $ 32,477 $ 128,085 $ 151,180
Distributions Attributable to Each Period(4) $ 42,208 $ 33,934 $ 153,829 $ 133,956
Distribution Coverage Ratio(3)(5) 0.57x 0.96x 0.83x 1.13x
(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 or loss plus interest expense and depreciation.
(3) 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 exisiting 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 to our unitholders 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" available for distribution to our unitholders 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 to our unitholders 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 to our unitholders and we must borrow funds or use cash reserves established in prior periods to cover our quarterly distributions to our unitholders. 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