Legacy Reserves LP Announces Fourth Quarter and Annual 2017 Results, Updated 2018 Guidance, Dan Westcott's Promotion to President and Availability of Schedule K-1s
MIDLAND, Texas, Feb. 21, 2018 /PRNewswire/ -- Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced fourth quarter and annual results for 2017, which included the following highlights:
-- Generated record quarterly production of 49,185 Boe/d, a 7% increase
relative to Q3'17, and record annual production of 44,967 Boe/d.
-- Generated record quarterly oil production of 17,696 Bbls/d, a 23%
increase relative to Q3'17 and record annual oil production of 13,786
Bbls/d.
-- Generated a net loss of $53.9 million for the year ended December 31,
2017.
-- Generated Adjusted EBITDA of $226.2 million for the year ended December
31, 2017, representing a 45% year-over-year increase.
-- Amended and restated our Joint Development Agreement ("JDA") with TPG
Sixth Street Partners ("TSSP") and made an $141 million Acceleration
Payment (the "Acceleration Payment") increasing our working interest
from 20% to 85% in Tranche 1 wells and from 20% to 66.3% in a subsequent
tranche of wells.
-- Entered into an agreement on December 31, 2017 to repurchase $187
million of our 6.625% Senior unsecured notes due 2021 (the "2021 Senior
Notes") at $0.70 per $1.00 of principal amount. This transaction settled
on January 5, 2018.
-- Entered into an agreement to amend our second lien term loan credit
agreement to increase the amount of aggregate commitments from $300
million to $400 million and extend the availability of those commitments
to October 25, 2019 effective January 5, 2018.
-- Meaningfully improved our credit statistics including a reduction in our
Total Debt / EBITDA by 2.1x as calculated on a pro forma basis under our
credit documents relative to year-end 2016.
-- Brought online an additional 5 and 30 horizontal Permian wells during
the quarter and year, respectively, with an inventory of 21 drilled but
uncompleted wells at December 31, 2017.
Paul T. Horne, Chairman of the Board, President and Chief Executive Officer, commented, "We are excited about the progress we made in 2017 toward transitioning to a growth-oriented development company with an improved balance sheet. The Acceleration Payment, bond repurchase, expanded second lien commitments, continued efficient Permian horizontal development and prudent PDP management were instrumental in charting this path. While we are extremely proud of these cornerstone 2017 achievements, significant strides remain for us to fully realize our goals. As such, we continue to evaluate and opportunistically pursue alternatives that will enhance equity value."
Dan Westcott, Executive Vice President and Chief Financial Officer, commented, "2017 was an incredibly active year as we positioned Legacy for meaningful oil production growth that compressed leverage metrics and will drive equity value. We also reduced leverage by capturing discount in our bonds which allowed us to gain meaningful voting power in our senior notes. Undoubtedly, our operations team was the driving force in delivering our record-beating results through their continued capital-efficient horizontal development of our Permian resources and economic operation of our large PDP base. Focus on both of these arenas provided the foundation for our guidance-beating production of 49,185 Boe/d in Q4 and Adjusted EBITDA of $226.2 million in 2017 and is critical to the ongoing success of Legacy."
"While in 2016 we aimed to reduce debt outstanding, we shifted in 2017 to improve our overall credit metrics. These efforts decreased our year-over-year pro forma Total Debt / EBITDA by 2.1x. For 2018, our new financial guidance suggests Adjusted EBITDA of $330 million, a 46% increase compared to 2017. This tremendous growth hinges on our commitment to operational excellence which should continue to compress our leverage metrics as we evaluate and opportunistically pursue alternatives to change our legal and tax status, materially reduce our outstanding debt, extend our debt maturities, and otherwise position the company for long-term growth. We have a big year ahead of us and are excited for the opportunity to grow equity value through these efforts."
Proved Reserves
The following information represents estimates of our proved reserves as of December 31, 2017 which have been prepared in compliance with the SEC rules using an average WTI price, as posted by Plains Marketing L.P., of $47.79 per Bbl for oil and an average natural gas price, as posted by Platts Gas Daily, of $2.98 per MMBtu.
Operating Regions Oil Natural NGLs Total % % PDP % Total Standardized
(MBbls) (MBbls) (MBoe) Liquids Measure
Gas
(MMcf) ($ thousands)
--- ----- ------------
Permian Basin 43,023 125,810 1,433 65,424 68% 87% 36% $750,730
East Texas 79 343,720 216 57,582 1% 98% 32% 197,186
Rocky Mountain 5,987 234,176 5,338 50,354 22% 99% 28% 182,181
Mid-Continent 2,057 12,428 2,465 6,593 69% 96% 4% 42,051
Total 51,146 716,134 9,452 179,953 34% 94% 100% $1,172,148
2018 Capital Program By Category
Gross Net Percent of Net
----- --- --------------
(In millions)
Horizontal Permian
development $290 $203 91%
Other drilling 34 5 2%
Other workovers 16 12 5%
East Texas (workovers,
G&P, facilities) 3 3 1%
Other facilities 2 2 1%
Total capital
expenditures $345 $225 100%
==== ==== ===
We serve as operator of approximately 98% of our anticipated capital program, and accordingly, maintain significant control of the capital program budget and may deviate materially from the figures above based on market conditions (or otherwise).
Updated 2018 Guidance
The following table sets forth certain assumptions used by Legacy to estimate its anticipated results of operations for 2018 based on the aforementioned expected 2018 capital program. These estimates do not include any acquisitions of additional oil or natural gas properties. In addition, these estimates are based on, among other things, assumptions of capital expenditure levels, current indications of supply and demand for oil and natural gas and current operating and labor costs. The guidance set forth below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. The guidance below sets forth management's best estimate based on current and anticipated market conditions and other factors. While we believe that these estimates and assumptions are reasonable, they are inherently uncertain and are subject to, among other things, significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate, as set forth under "Cautionary Statement Relevant to Forward-Looking Information."
FY 2018E Range
--------------
($ in thousands unless otherwise
noted)
Production:
Oil (Bbls/d) 19,000 - 21,400
Natural gas liquids
(Bbls/d) 1,875 - 2,075
Natural gas (MMcf/d) 162 - 176
Total (Boe/d) 47,875 - 52,808
Weighted average NYMEX
differentials:
Oil (per Bbl) $(4.00) - $(3.25)
NGL realization(1) 52% - 63%
Natural gas (per Mcf) $(0.35) - $(0.20)
Expenses:
Lease operating
expenses(2) $175,000 - $195,000
Ad valorem and
production taxes (%
of revenue) 7.40% - 7.90%
Cash G&A expenses(3) $34,000 - $38,000
Adjusted EBITDA(4): $300,000 - $360,000
(1) Represents the projected
percentage of assumed WTI crude
oil prices.
(2) Excludes ad valorem and
production taxes.
(3) Consistent with our definition of
Adjusted EBITDA, these figures
exclude LTIP and transaction
costs.
(4) Adjusted EBITDA is a Non-GAAP
financial measure. This measure
does not include pro forma
adjustments permitted under our
credit agreements relating to
acquired and divested oil or gas
properties. A reconciliation of
this measure to the nearest
comparable GAAP measure is
available on our website.
Note: Figures above assume NYMEX strip
pricing at 2/15/2018 (2018 Avg Oil $59.59 /
$2.80 Gas).
Dan Westcott's Promotion to President
Effective March 1, 2018 Dan Westcott, Legacy's Chief Financial Officer will also assume the position of Legacy's President. Effective March 1, 2018, Paul Horne has resigned his position as President but will remain Chairman and Chief Executive Officer.
Mr. Horne commented, "Dan has done an outstanding job helping the company navigate the challenging landscape we have faced over the past three years. His focus and diligence on improving our financial condition and balance sheet are evident in our results. We are very excited about the future of Legacy and the critical role he has played and will play in that future. Dan's promotion to President acknowledges both and is well deserved."
Schedules K-1 Available
Legacy also announced today that it has completed the 2017 tax packages for unitholders of LGCY, LGCYP and LGCYO including Schedules K-1. Schedules K-1 for LGCYP and LGCYO each reflect $0.166667 of income for each month such security was owned in 2017 ($2.00 in total assuming a full year of ownership) irrespective of the fact that (i) no 2017 distributions were paid and (ii) the Partnership generated a net loss in 2017. Each holder of LGCY, LGCYO and LGCYP is encouraged to consult with its tax advisor with respect to the Schedule K-1 information and individual tax circumstances.
The tax packages are currently available online and may be accessed via Legacy's website at www.LegacyLP.com by clicking on the "Tax Information" link on the website. Legacy will begin mailing the Schedules K-1 to unitholders on Friday, February 23, 2018. For additional information, unitholders may also contact Legacy's K-1 Partner Data Link call center toll free at (877) 504-5606 between 8:00 a.m. and 5:00 p.m. CST Monday through Friday.
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
(Unaudited)
Three Months Ended Twelve Months Ended
December 31, December 31,
2017 2016 2017 2016
---- ---- ---- ----
(In thousands, except per unit data)
Revenues
Oil sales $85,150 $42,164 $239,448 $152,507
Natural gas liquids sales 8,105 5,574 24,796 15,406
Natural gas sales 43,837 43,853 172,057 146,444
------ ------ ------- -------
Total revenues $137,092 $91,591 $436,301 $314,357
======== ======= ======== ========
Expenses:
Oil and natural gas production $42,594 $41,456 $173,599 $169,755
Ad valorem taxes 2,527 172 9,620 9,578
----- --- ----- -----
Total $45,121 $41,628 $183,219 $179,333
Production and other taxes $6,046 $4,318 $19,825 $14,267
General and administrative excluding
transaction costs and LTIP $9,919 $8,237 $34,006 $31,196
Transaction costs 8,631 4,158 8,769 5,245
LTIP expense 1,666 1,586 6,597 7,198
----- ----- ----- -----
Total general and administrative $20,216 $13,981 $49,372 $43,639
Depletion, depreciation, amortization
and accretion $36,738 $39,719 $126,938 $150,414
Commodity derivative cash settlements:
Oil derivative cash settlements
received $2,040 $7,030 $11,840 $37,464
Natural gas derivative cash
settlements received 4,337 992 12,316 27,041
Total commodity derivative cash
settlements $6,377 $8,022 $24,156 $64,505
Production:
Oil (MBbls) 1,628 949 5,032 4,019
Natural gas liquids (MGal) 10,617 9,111 38,159 36,757
Natural gas (MMcf) 15,866 16,243 62,833 66,824
Total (MBoe) 4,525 3,873 16,413 16,032
Average daily production (Boe/d) 49,185 42,098 44,967 43,803
Average sales price per unit (excluding commodity derivative cash settlements):
Oil price (per Bbl) $52.30 $44.43 $47.59 $37.95
Natural gas liquids price (per Gal) $0.76 $0.61 $0.65 $0.42
Natural gas price (per Mcf)(a) $2.76 $2.70 $2.74 $2.19
Combined (per Boe) $30.30 $23.65 $26.58 $19.61
Average sales price per unit (including commodity derivative cash settlements):
Oil price (per Bbl) $53.56 $51.84 $49.94 $47.27
Natural gas liquids price (per Gal) $0.76 $0.61 $0.65 $0.42
Natural gas price (per Mcf)(a) $3.04 $2.76 $2.93 $2.60
Combined (per Boe) $31.71 $25.72 $28.05 $23.63
Average WTI oil spot price (per Bbl) $55.27 $49.14 $50.80 $43.29
Average Henry Hub natural gas index
price (per MMbtu) $2.91 $3.04 $2.99 $2.52
Average unit costs per Boe:
Production costs, excluding production
and other taxes $9.41 $10.70 $10.58 $10.59
Ad valorem taxes $0.56 $0.04 $0.59 $0.60
Production and other taxes $1.34 $1.11 $1.21 $0.89
General and administrative excluding
transaction costs and LTIP $2.19 $2.13 $2.07 $1.95
Total general and administrative $4.47 $3.61 $3.01 $2.72
Depletion, depreciation, amortization
and accretion $8.12 $10.26 $7.73 $9.38
Annual Financial and Operating Results - 2017 Compared to 2016
-- Production increased 3% to an annual record of 44,967 Boe/d in 2017 from
43,803 Boe/d in 2016 primarily due to increased oil production from
increased working interests as a result of the Acceleration Payment and
increased Permian Basin horizontal development, partially offset by
individually immaterial divestitures and natural production declines.
-- Average realized price, excluding net cash settlements from commodity
derivatives, increased 36% to $26.58 per Boe in 2017 from $19.61 per Boe
in 2016. Average realized oil price increased 25% to $47.59 in 2017 from
$37.95 in 2016. This increase was primarily driven by an increase in the
average West Texas Intermediate ("WTI") crude oil price of $7.51 per Bbl
and improving realized regional differentials. Average realized natural
gas price increased 25% to $2.74 per Mcf in 2017 from $2.19 per Mcf in
2016. This increase was primarily driven by an increase in the average
Henry Hub natural gas index price of $0.47 per Mcf and increased natural
gas volumes produced from assets in the Permian Basin which are
accounted for inclusive of the NGL content contained within the natural
gas volumes, resulting in a realized gas price for those assets that is
higher than the NYMEX Henry Hub index price. Finally, our average
realized NGL price increased 55% to $0.65 per gallon in 2017 from $0.42
per gallon in 2016.
-- Production expenses, excluding ad valorem taxes, increased 2% to $173.6
million in 2017 from $169.8 million in 2016 primarily due to increased
workover and repair activity across all operating regions, increased
well count due to our Permian horizontal drilling program and increased
working interests as a result of the Acceleration Payment, partially
offset by general cost reduction efforts. On an average cost per Boe
basis, production expenses decreased to $10.58 per Boe in 2017 from
$10.59 per Boe in 2016, driven primarily by increased low cost oil and
NGL production.
-- Non-cash impairment expense totaled $37.3 million in 2017 primarily
driven by the further decline in oil and natural gas futures prices in
early 2017 as well as increased expenses and well performance during
2017.
-- General and administrative expenses, excluding transaction-related
expenses and unit-based Long-Term Incentive Plan ("LTIP") compensation
expense increased to $34.0 million in 2017 compared to $31.2 million in
2016 due to general cost increases.
-- Cash settlements received on our commodity derivatives during 2017 were
$24.2 million as compared to $64.5 million in 2016. The decrease was due
to increased average commodity prices and lower volumes under derivative
contracts.
-- Total development capital expenditures increased to $176.8 million in
2017 from $29.5 million in 2016 primarily due to our increased exposure
to our Permian horizontal development under our JDA.
Financial and Operating Results - Fourth Quarter 2017 Compared to Fourth Quarter 2016
-- Production increased 17% to 49,185 Boe/d from 42,098 Boe/d primarily due
to increased oil production from increased working interests as a result
of the Acceleration Payment and increased Permian horizontal
development, partially offset by individually immaterial divestitures
and natural production declines.
-- Average realized price, excluding net cash settlements from commodity
derivatives, increased 28% to $30.30 per Boe in 2017 from $23.65 per Boe
in 2016. Average realized oil price increased 18% to $52.30 per Bbl in
2017 from $44.43 per Bbl in 2016. This increase of $7.87 was primarily
attributable to the increase in the average WTI crude oil price of $6.13
and improving realized regional differentials. Average realized natural
gas prices increased 2% to $2.76 per Mcf in 2017 from $2.70 per Mcf in
2016. This increase of $0.06 was primarily attributable to increased
natural gas volumes produced from assets in the Permian Basin which are
accounted for inclusive of the NGL content contained within the natural
gas volumes, resulting in a realized gas price for those assets that is
higher than the NYMEX Henry Hub index price. This was partially offset
by a decline in the average Henry Hub gas price. Finally, our average
realized NGL price increased 25% to $0.76 per gallon in 2017 from $0.61
per gallon in 2016.
-- Production expenses, excluding ad valorem taxes, increased 3% to $42.6
million in 2017 from $41.5 million in 2016. Production expenses
increased due to our Permian horizontal drilling program and increased
working interests as a result of the Acceleration Payment partially
offset by general cost reduction efforts. On a per Boe basis, production
expenses decreased to $9.41 from $10.70 or 12% driven primarily by
increased low cost oil production.
-- Non-cash impairment expense totaled $12.7 million in 2017 primarily
driven by declining natural gas futures prices, increased costs and well
performance.
-- General and administrative expenses, excluding acquisition costs and
LTIP compensation expense, increased to $9.9 million in 2017 from $8.2
million in 2016 due to general cost increases.
-- Cash settlements received on our commodity derivatives were $6.4 million
during 2017 compared to $8.0 million in 2016.
-- Total development capital expenditures were $35.3 million in the fourth
quarter of 2017.
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of February 21, 2018, we had entered into derivative agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub natural gas prices as summarized below:
WTI Crude Oil Swaps:
Calendar
Year Volumes (Bbls) Average Price per Price Range per
Bbl Bbl
--- ---
2018 2,998,500 $54.67 $51.20 - $63.68
WTI Crude Oil Costless Collars. As an illustrative example, at an annual WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $47.06, $50.00 and $60.29, respectively for 2018.
Average Long Average Short
Time
Period Volumes (Bbls) Put Price per Bbl Call Price per Bbl
------ ------------- ----------------- ------------------
2018 1,551,250 $47.06 $60.29
Crude Oil Enhanced Swaps. As an illustrative example, at an annual average WTI market price of $40.00, $50.00 and $65.00, the summary positions below would result in a net price of $65.50, $65.50 and $73.50, respectively for 2018.
Average Long Put Average Short Put Average Swap
Calendar
Year Volumes (Bbls) Price per Bbl Price per Bbl Price per Bbl
-------- ------------- ------------- ------------- -------------
2018 127,750 $57.00 $82.00 $90.50
Midland-to-Cushing WTI Crude Oil Differential Swaps:
Time
Period Volumes (Bbls) Average Price per Price Range per
Bbl Bbl
--- ---
2018 4,015,000 $(1.13) $(1.25) - $(0.80)
2019 730,000 $(1.15) $(1.15)
Natural Gas Swaps (Henry Hub):
Average Price Range per
Calendar Year Volumes (MMBtu) Price per MMBtu MMBtu
------------- -------------- --------------- -----
2018 36,200,000 $3.23 $3.04 - $3.39
2019 25,800,000 $3.36 $3.29 - $3.39
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 2017 Form 10-K which will be filed on or about February 23, 2018.
Conference Call
As announced on February 8, 2018, Legacy will host an investor conference call to discuss Legacy's results and corresponding presentation materials on Thursday, February 22, 2018 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-870-4623. A replay of the call will be available through Thursday, March 1, 2018, by dialing 877-344-7529 and entering replay code 10116400. Those wishing to listen to the live or archived web cast via the Internet or view the corresponding presentation materials 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 development of oil and natural gas properties primarily located in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions of the United States. Additional information is available at www.LegacyLP.com.
Additional Information for Holders of Legacy Units
Although Legacy has suspended distributions to both the 8% Series A and Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Preferred Units"), such distributions continue to accrue. Pursuant to the terms of Legacy's partnership agreement, Legacy is required to pay or set aside for payment all accrued but unpaid distributions with respect to the Preferred Units prior to or contemporaneously with making any distribution with respect to Legacy's units. Accruals of distributions on the Preferred Units are treated for tax purposes as guaranteed payments for the use of capital that will generally be taxable to the holders of such Preferred Units as ordinary income even in the absence of contemporaneous distributions.
In addition, Legacy's unitholders, just like unitholders of other master limited partnerships, are allocated taxable income irrespective of cash distributions paid. Because Legacy's unitholders are treated as partners that are allocated a share of Legacy's taxable income irrespective of the amount of cash, if any, distributed by Legacy, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of Legacy's taxable income, including its taxable income associated with cancellation of debt ("COD income") or a disposition of property by Legacy, even if they receive no cash distributions from Legacy. As of January 21, 2016, Legacy has suspended all cash distributions to unitholders and holders of the Preferred Units. Legacy may engage in transactions to de-lever the Partnership and manage its liquidity that may result in the allocation of income and gain to its unitholders without a corresponding cash distribution. For example, if Legacy sells assets and uses the proceeds to repay existing debt or fund capital or operating expenditures, Legacy's unitholders may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, if Legacy engages in debt exchanges, debt repurchases, or modifications of its existing debt, these or similar transactions could result in "cancellation of indebtedness" or COD income being allocated to Legacy's unitholders as taxable income. For tax purposes, Legacy repurchased $187 million of its 6.625% Senior Notes at $0.70 per $1.00 principal amount on December 31, 2017. Unitholders will be allocated gain and income from asset sales and COD income and may owe income tax as a result of such allocations notwithstanding the fact that Legacy has suspended cash distributions to its unitholders. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential transactions that may result in income and gain to unitholders.
Additionally, if Legacy's unitholders, just like unitholders of other master limited partnerships, sell any of their units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions to unitholders that in the aggregate exceeded the cumulative net taxable income they were allocated for a unit decreased the tax basis in that unit, and will, in effect, become taxable income to Legacy's unitholders if the unit is sold at a price greater than their tax basis in that unit, even if the price received is less than original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to Legacy's unitholders due to the potential recapture items, including depreciation, depletion and intangible drilling.
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, December 31,
2017 2016 2017 2016
---- ---- ---- ----
(In thousands, except per unit data)
Revenues:
Oil sales $85,150 $42,164 $239,448 $152,507
Natural gas liquids (NGL) sales 8,105 5,574 24,796 15,406
Natural gas sales 43,837 43,853 172,057 146,444
------ ------ ------- -------
Total revenues 137,092 91,591 436,301 314,357
------- ------ ------- -------
Expenses:
Oil and natural gas production 45,121 41,628 183,219 179,333
Production and other taxes 6,046 4,318 19,825 14,267
General and administrative 20,216 13,981 49,372 43,639
Depletion, depreciation,
amortization and accretion 36,738 39,719 126,938 150,414
Impairment of long-lived assets 12,735 41,731 37,283 61,796
(Gain) loss on disposal of assets (1,885) (806) 1,606 (50,095)
------ ---- ----- -------
Total expenses 118,971 140,571 418,243 399,354
------- ------- ------- -------
Operating income (loss) 18,121 (48,980) 18,058 (84,997)
Other income (expense):
Interest income 20 13 64 67
Interest expense (24,838) (16,502) (89,206) (79,060)
Gain on extinguishment of debt - - - 150,802
Equity in income of equity method
investees 5 7 17 -
Net gains (losses) on commodity
derivatives (18,100) (38,913) 17,776 (41,224)
Other 27 309 792 (179)
--- --- --- ----
Loss before income taxes (24,765) (104,066) (52,499) (54,591)
Income tax expense (561) (519) (1,398) (1,229)
---- ---- ------ ------
Net Loss $(25,326) $(104,585) $(53,897) $(55,820)
Distributions to preferred
unitholders (4,750) (5,542) (19,000) (19,000)
------ ------ ------- -------
Net loss attributable to unitholders $(30,076) $(110,127) $(72,897) $(74,820)
======== ========= ======== ========
Loss per unit - basic and diluted $(0.41) $(1.53) $(1.01) $(1.06)
====== ====== ====== ======
Weighted average number of units used in computing
loss per unit -
Basic and diluted 72,595 72,056 72,405 70,605
====== ====== ====== ======
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
December 31,
2017 2016
---- ----
(In thousands)
ASSETS
Current assets:
Cash $1,246 $2,555
Accounts receivable, net:
Oil and natural gas 62,755 43,192
Joint interest owners 27,420 23,414
Other 2 2
Fair value of derivatives 13,424 6,162
Prepaid expenses and other current
assets 7,757 7,447
----- -----
Total current assets 112,604 82,772
------- ------
Oil and natural gas properties, at cost:
Proved oil and natural gas properties
using the successful efforts method
of accounting 3,529,971 3,305,856
Unproved properties 28,023 13,448
Accumulated depletion, depreciation,
amortization and impairment (2,204,638) (2,137,395)
---------- ----------
1,353,356 1,181,909
--------- ---------
Other property and equipment, net of
accumulated depreciation and
amortization of $11,467 and $10,412,
respectively 2,961 3,423
Operating rights, net of amortization
of $5,765 and $5,369, respectively 1,251 1,648
Fair value of derivatives 14,099 20,553
Other assets 8,811 9,521
Total assets $1,493,082 $1,299,826
========== ==========
LIABILITIES AND PARTNERS' DEFICIT
Current liabilities:
Accounts payable $13,093 $9,092
Accrued oil and natural gas
liabilities 81,318 53,248
Fair value of derivatives 18,013 9,743
Asset retirement obligation 3,214 2,980
Other 29,172 11,546
------ ------
Total current liabilities 144,810 86,609
------- ------
Long-term debt 1,346,769 1,161,394
Asset retirement obligation 271,472 269,168
Fair value of derivatives 1,075 4,091
Other long-term liabilities 643 643
--- ---
Total liabilities 1,764,769 1,521,905
--------- ---------
Commitments and contingencies
Partners' equity (deficit):
Series A Preferred equity -2,300,000
units issued and outstanding at
December 31, 2017 and December 31,
2016 55,192 55,192
Series B Preferred equity -7,200,000
units issued and outstanding at
December 31, 2017 and December 31,
2016 174,261 174,261
Incentive distribution equity -
100,000 units issued and outstanding
at December 31, 2017 and December
31, 2016 30,814 30,814
Limited partners' deficit -
72,594,620 and 72,056,097 units
issued and outstanding at December
31, 2017 and 2016, respectively (531,794) (482,200)
General partner's deficit
(approximately 0.03%) (160) (146)
---- ----
Total partners' deficit (271,687) (222,079)
-------- --------
Total liabilities and partners'
deficit $1,493,082 $1,299,826
========== ==========
Non-GAAP Financial Measures
This press release, the financial tables and other supplemental information include "Adjusted EBITDA" which is a non-generally accepted accounting principles ("non-GAAP") measure which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of this non-GAAP financial measure to its nearest comparable generally accepted accounting principles ("GAAP") measure.
Adjusted EBITDA is presented as management believes it provides additional information concerning the performance of our business and is 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 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.
Certain factors impacting Adjusted EBITDA 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 of directors of our general partner historically has not varied the distribution it declares based on such timing effects.
"Adjusted EBITDA" should not be considered as an alternative 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;
-- (Gain) loss on extinguishment of debt;
-- Income tax expense (benefit);
-- Depletion, depreciation, amortization and accretion;
-- Impairment of long-lived assets;
-- (Gain) loss on sale of partnership investment;
-- Loss (gain) 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 costs.
The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA:
Three Months Ended Twelve Months Ended
December 31, December 31,
2017 2016 2017 2016
---- ---- ---- ----
(In thousands)
Net loss $(25,326) $(104,585) $(53,897) $(55,820)
Plus:
Interest expense 24,838 16,502 89,206 79,060
Gain on debt extinguishment - - - (150,802)
Income tax expense 561 519 1,398 1,229
Depletion, depreciation, amortization
and accretion 36,738 39,719 126,938 150,414
Impairment of long-lived assets 12,735 41,731 37,283 61,796
(Gain) loss on disposal of assets (1,885) (806) 1,606 (50,095)
Equity in income of equity method
investees (5) (7) (17) -
Unit-based compensation expense 1,666 1,586 6,597 7,198
Minimum payments received in excess
of overriding royalty interest
earned(1) 509 434 1,936 1,659
Net (gains) losses on commodity
derivatives 18,100 38,913 (17,776) 41,224
Net cash settlements received on
commodity derivatives 6,377 8,022 24,156 64,505
Transaction costs 8,631 4,158 8,769 5,245
----- ----- -----
Adjusted EBITDA $82,939 $46,186 $226,199 $155,613
======= ======= ======== ========
(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.
CONTACT:
Legacy Reserves LP
Dan Westcott
Executive Vice President and Chief Financial Officer
432-689-5200
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SOURCE Legacy Reserves LP
