Legacy Reserves LP Announces Second Quarter 2018 Results

MIDLAND, Texas, Aug. 1, 2018 /PRNewswire/ -- Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced second quarter results for 2018 including the following highlights:

Generated record quarterly oil production of 17,901 Bbls/d, a 4% increase relative to Q1'18;
Commenced Wolfcamp drilling in Martin County and began preparing surface locations ahead of a rig move into Midland County;
Brought 9 Permian horizontal wells online during the quarter, bringing the total to 29 Permian horizontal wells brought online year-to-date;
Completed multiple strategic Permian acreage trades requiring no net cash outlay which enhanced projected economics for 33 gross drilling locations:

Increased average lateral lengths for 3 of Legacy's core Midland Basin tracts by 58%, resulting in an increase in net lateral footage by 45,000 feet;

Generated a net loss of $50.7 million;
Generated Adjusted EBITDA of $72.1 million; and
Subsequent to quarter-end, Legacy achieved meaningful progress related to our previously announced Corporate Reorganization including:

Entered into a Stipulation and Agreement of Settlement (the "Settlement Agreement") to settle the previously announced class action lawsuit filed by holders of Preferred Units; and
Now anticipate filing definitive proxy statement and commencing unitholder solicitation in the coming days incorporating a special meeting of unitholders to approve the Corporate Reorganization on September 19, 2018 for unitholders of record as of the close of business on July 26, 2018.

Paul T. Horne, Chairman of the Board and Chief Executive Officer of Legacy's general partner, commented, "I am really proud of the strong results reported by all of our business units this quarter. Our business development and land teams created significant potential value by completing several complicated trades involving a puzzle of 11 tracts across the Permian Basin and many counterparties. Our team fit those pieces together in an optimized fashion that substantially improves the projected economics of some of our core inventory. Our operations team continues to find ways to improve leasehold economics by leveraging our longstanding Permian position. We remain committed to our lease-wide development approach, focused on maximizing return on investment, production, reserves and cash flow and we look forward to continuing this program as we transition to a C-Corp."

Dan Westcott, President and Chief Financial Officer of Legacy's general partner, commented, "Our team continues to execute and we are glad to report oil production growth that drives growth in EBITDA. While we have limited control over the widening of our oil differentials that occurred this quarter due to the widening of Mid-Cush basis, we are happy that we have hedged most of that exposure in 2018 and a bit of it in 2019. We gained good momentum in the field this quarter, and when combined with our expanded Permian Basin footprint, we believe we are well-positioned for success and are excited to realize Legacy's transition to becoming a growth-oriented development company."

LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA

	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	2018		2017		2018		2017

	(In thousands, except per unit data)
Revenues:
Oil sales	$	99,799	$	46,096	$	193,210	$	95,238
Natural gas liquids (NGL) sales	5,735		4,921		13,131		9,971
Natural gas sales	33,747		41,830		70,419		87,185
Total revenue	$	139,281	$	92,847	$	276,760	$	192,394
Expenses:
Oil and natural gas production, excluding ad valorem taxes	$	46,882	$	42,262	$	92,467	$	91,490
Ad valorem taxes	2,549		2,540		4,931		4,529
Total oil and natural gas production	$	49,431	$	44,802	$	97,398	$	96,019
Production and other taxes	$	7,658	$	4,145	$	14,984	$	8,304
General and administrative, excluding transaction costs and LTIP	$	8,003	$	7,046	$	17,505	$	15,669
Transaction costs	1,607		52		3,389		84
LTIP expense	12,886		1,483		25,692		3,380
Total general and administrative	$	22,496	$	8,581	$	46,586	$	19,133
Depletion, depreciation, amortization and accretion	$	38,139	$	27,689	$	74,686	$	56,485
Commodity derivative cash settlements:
Oil derivative cash settlements (paid) received	$	(6,309)	$	3,559	$	(11,203)	$	6,698
Natural gas derivative cash settlements received	$	3,895	$	3,012	$	5,994	$	4,109
Production:
Oil (MBbls)	1,629		1,044		3,176		2,081
Natural gas liquids (MGal)	11,332		8,514		20,576		16,167
Natural gas (MMcf)	14,555		15,604		28,835		31,196
Total (MBoe)	4,325		3,847		8,472		7,665
Average daily production (Boe/d)	47,527		42,275		46,807		42,348
Average sales price per unit (excluding derivative cash settlements):
Oil price (per Bbl)	$	61.26	$	44.15	$	60.83	$	45.77
Natural gas liquids price (per Gal)	$	0.51	$	0.58	$	0.64	$	0.62
Natural gas price (per Mcf)	$	2.32	$	2.68	$	2.44	$	2.79
Combined (per Boe)	$	32.20	$	24.13	$	32.67	$	25.10
Average sales price per unit (including derivative cash settlements):
Oil price (per Bbl)	$	57.39	$	47.56	$	57.31	$	48.98
Natural gas liquids price (per Gal)	$	0.51	$	0.58	$	0.64	$	0.62
Natural gas price (per Mcf)	$	2.59	$	2.87	$	2.65	$	2.93
Combined (per Boe)	$	31.65	$	25.84	$	32.05	$	26.51
Average WTI oil spot price (per Bbl)	$	68.07	$	48.10	$	65.55	$	49.85
Average Henry Hub natural gas index price (per MMbtu)	$	2.85	$	3.08	$	2.96	$	3.05
Average unit costs per Boe:
Oil and natural gas production, excluding ad valorem taxes	$	10.84	$	10.99	$	10.91	$	11.94
Ad valorem taxes	$	0.59	$	0.66	$	0.58	$	0.59
Production and other taxes	$	1.77	$	1.08	$	1.77	$	1.08
General and administrative excluding transaction costs and LTIP	$	1.85	$	1.83	$	2.07	$	2.04
Total general and administrative	$	5.20	$	2.23	$	5.50	$	2.50
Depletion, depreciation, amortization and accretion	$	8.82	$	7.20	$	8.82	$	7.37

Financial and Operating Results - Three-Month Period Ended June 30, 2018 Compared to Three-Month Period Ended June 30, 2017

Production increased 12% to 47,527 Boe/d from 42,275 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests that reverted to us in connection with making an acceleration payment on August 1, 2017 (the "Acceleration Payment") under our amended and restated joint development agreement with TSSP. This was partially offset by natural production declines and individually immaterial divestitures completed in 2018 and 2017.
Average realized price, excluding net cash settlements from commodity derivatives, increased 33% to $32.20 per Boe in 2018 from $24.13 per Boe in 2017 driven by the significant increase in oil prices and an increase in oil production as a percentage of total production, partially offset by widening regional differentials. Average realized oil price increased 39% to $61.26 in 2018 from $44.15 in 2017 driven by an increase in the average WTI crude oil price of $19.97 per Bbl, partially offset by the widening Mid-Cush differential. Average realized natural gas price decreased 13% to $2.32 per Mcf in 2018 from $2.68 per Mcf in 2017. This decrease is primarily the result of a decrease in NYMEX pricing, widening realized regional differentials and our adoption of ASC 606. Finally, our average realized NGL price decreased 12% to $0.51 per gallon in 2018 from $0.58 per gallon in 2017 due to increased volumes with a higher percentage of lower-priced ethane.
Production expenses, excluding ad valorem taxes, increased to $46.9 million in 2018 from $42.3 million in 2017, primarily due to additional costs associated with increased production related to our Permian horizontal drilling program as well as increased working interests following the Acceleration Payment. On an average cost per Boe basis, production expenses excluding ad valorem taxes decreased 1% to $10.84 per Boe in 2018 from $10.99 per Boe in 2017.
Non-cash impairment expense totaled $35.4 million driven by the decline in natural gas futures prices.
General and administrative expenses, excluding unit-based Long-Term Incentive Plan ("LTIP") compensation expense, increased to $9.6 million in 2018 from $7.1 million in 2017 due to a $1.5 million increase in transaction costs and general cost increases. LTIP compensation expense increased $11.4 million due to the recent rise in our unit price.
Cash settlements paid on our commodity derivatives during 2018 were $2.4 million compared to cash receipts of $6.6 million in 2017. The change in cash settlements is a result of higher commodity prices, reduced nominal volumes hedged in Q2 2018 compared to Q2 2017 and lower contracted hedge prices. This was partially offset by an increase in cash receipts of our Mid-Cush derivatives.
Total development capital expenditures increased to $80.7 million in 2018 from $24.6 million in 2017. The 2018 activity was comprised mainly of our Permian horizontal drilling program.

Financial and Operating Results - Six-Month Period Ended June 30, 2018 Compared to Six-Month Period Ended June 30, 2017

Production increased 11% to 46,807 Boe/d from 42,348 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests that reverted to us in connection with the August 1, 2017 Acceleration Payment. This was partially offset by natural production declines and individually immaterial divestitures completed in 2018 and 2017.
Average realized price, excluding net cash settlements from commodity derivatives, increased 30% to $32.67 per Boe in 2018 from $25.10 per Boe in 2017 driven by the significant increase in oil prices and an increase in oil production as a percentage of total production, partially offset by widening regional differentials. Average realized oil price increased 33% to $60.83 in 2018 from $45.77 in 2017 driven by an increase in the average WTI crude oil price of $15.70 per Bbl, partially offset by the widening Mid-Cush differential. Average realized natural gas price decreased 13% to $2.44 per Mcf in 2018 from $2.79 per Mcf in 2017. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $0.09 per Mcf and widening realized regional differentials. Finally, our average realized NGL price increased 3% to $0.64 per gallon in 2018 from $0.62 per gallon in 2017 due to higher commodity prices partially offset by increased volumes with a higher percentage of lower-priced ethane.
Our production expenses, excluding ad valorem taxes, increased to $92.5 million in 2018 from $91.5 million in 2017. This increase was due to increased production related to our Permian horizontal drilling program as well as increased working interests following the Acceleration Payment, partially offset by cost containment efforts. On an average cost per Boe basis, production expenses decreased 9% to $10.91 per Boe in 2018 from $11.94 per Boe in 2017.
Non-cash impairment expense totaled $35.4 million driven by the decline in natural gas futures prices.
General and administrative expenses, excluding unit-based LTIP compensation expense totaled $20.9 million in 2018 compared to $15.8 million in 2017, reflecting a $3.3 million increase in transaction costs and general cost increases. LTIP compensation expense increased $21.8 million due to the recent rise in our unit price.
Cash settlements paid on our commodity derivatives during 2018 were $5.2 million compared to cash receipts of $10.8 million in 2017. The change in cash settlements is a result of higher commodity prices, reduced nominal volumes hedged in 2018 compared to 2017 and lower contracted hedge prices. This was partially offset by an increase in cash receipts of our Mid-Cush derivatives.
Total development capital expenditures increased to $140.4 million in 2018 from $48.3 million in 2017. The 2018 activity was comprised mainly of our Permian horizontal drilling program.

Commodity Derivative Contracts

We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of July 31, 2018, we had entered into derivative agreements to receive average prices as summarized below.

NYMEX WTI Crude Oil Swaps:

Time Period	Volumes (Bbls)	Average Price per Bbl	Price Range per Bbl
July-December 2018	1,527,200	$54.76	$51.20	-	$63.68
2019	2,190,000	$58.88	$57.15	-	$61.20

NYMEX WTI Crude Oil Costless Collars. 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
July-December 2018	782,000	$47.06	$60.29

NYMEX WTI Crude Oil Enhanced Swaps. 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
Time Period	Volumes (Bbls)	Price per Bbl	Price per Bbl	Price per Bbl
July-December 2018	64,400	$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
July-December 2018	2,024,000	$(1.13)	$(1.25)	-	$(0.80)
2019	730,000	$(1.15)	$(1.15)

NYMEX Natural Gas Swaps (Henry Hub):

		Average	Price Range per
Time Period	Volumes (MMBtu)	Price per MMBtu	MMBtu
July-December 2018	18,160,000	$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.

Quarterly Report on Form 10-Q

Financial results contained herein are preliminary and subject to the final, unaudited financial statements and related footnotes included in Legacy's Form 10-Q which will be filed on or about August 7, 2018.

Credit Agreement Waiver

On July 31, 2018, the lenders for our credit agreement agreed to waive our compliance with the ratio of consolidated current assets to consolidated current liabilities covenant contained in the credit agreement for the fiscal quarter ended June 30, 2018.

Conference Call

As announced on July 18, 2018, Legacy will host an investor conference call to discuss Legacy's results on Thursday, August 2, 2018 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-870-4263. A replay of the call will be available through Thursday, August 9, 2018, by dialing 877-344-7529 and entering replay code 10122434. Those wishing to listen to the live or archived webcast 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 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 and Where to Find It

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.

In connection with the proposed transaction that will transition Legacy from an MLP to a C-Corp (the "Transaction"), Legacy Reserves Inc. ("New Legacy") has filed with the U.S. Securities and Exchange Commission (the "SEC") a registration statement on Form S-4, which includes a preliminary proxy statement of Legacy and a preliminary prospectus of New Legacy (the "proxy statement/prospectus") which Legacy plans to mail to its unitholders to solicit approval for the merger.

INVESTORS AND UNITHOLDERS ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT LEGACY AND NEW LEGACY, AS WELL AS THE TRANSACTION AND RELATED MATTERS.

This press release does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the U.S. Securities Act of 1933, as amended.

A free copy of the proxy statement/prospectus and other filings containing information about Legacy and New Legacy may be obtained at the SEC's Internet site at www.sec.gov. In addition, the documents filed with the SEC by Legacy and New Legacy may be obtained free of charge by directing such request to: Legacy Reserves LP, Attention: Investor Relations, at 303 W. Wall, Suite 1800, Midland, Texas 79701 or emailing IR@legacylp.com or calling 855-534-5200. These documents may also be obtained for free from Legacy's investor relations website at https://www.legacylp.com/investor-relations.

Legacy and its general partner's directors, executive officers, other members of management and employees may be deemed to be participants in the solicitation of proxies from Legacy's unitholders in respect of the Transaction described in the proxy statement/prospectus. Information regarding the directors and executive officers of Legacy's general partner is contained in Legacy's public filings with the SEC, including its definitive proxy statement on Form DEF 14A filed with the SEC on April 6, 2018.

A more complete description is available in the registration statement and the proxy statement/prospectus.

Cautionary Statement Relevant to Forward-Looking Information

This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, without limitation, statements regarding the expected benefits of the Transaction to Legacy and its unitholders, final court approval of the Settlement Agreement, the anticipated completion of the Transaction or the timing thereof, the expected future growth, dividends, distributions of the reorganized company, and plans and objectives of management for future operations. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Legacy expects, believes or anticipates will or may occur in the future, are forward-looking statements. 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 forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the control of Legacy, which could cause results to differ materially from those expected by management of Legacy. Such risks and uncertainties include, but are not limited to, 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 Legacy's filings with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. 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				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017

	(In thousands, except per unit data)
Revenues:
Oil sales	$	99,799	$	46,096	$	193,210	$	95,238
Natural gas liquids (NGL) sales	5,735		4,921		13,131		9,971
Natural gas sales	33,747		41,830		70,419		87,185
Total revenues	139,281		92,847		276,760		192,394

Expenses:
Oil and natural gas production	49,431		44,802		97,398		96,019
Production and other taxes	7,658		4,145		14,984		8,304
General and administrative	22,496		8,581		46,586		19,133
Depletion, depreciation, amortization and accretion	38,139		27,689		74,686		56,485
Impairment of long-lived assets	35,381		1,821		35,381		9,883
(Gains) losses on disposal of assets	(1,145)		11,049		(21,540)		5,525
Total expenses	151,960		98,087		247,495		195,349

Operating (loss) income	(12,679)		(5,240)		29,265		(2,955)

Other income (expense):
Interest income	3		8		15		9
Interest expense	(28,589)		(20,614)		(55,957)		(40,747)
Gain on extinguishment of debt	—		—		51,693		—
Equity in income of equity method investees	3		1		20		12
Net gains (losses) on commodity derivatives	(9,315)		14,516		(11,019)		49,185
Other	(2)		402		273		362
Income (loss) before income taxes	(50,579)		(10,927)		14,290		5,866
Income tax expense	(130)		(150)		(617)		(571)
Net income (loss)	$	(50,709)	$	(11,077)	$	13,673	$	5,295
Distributions to preferred unitholders	(4,750)		(4,750)		(9,500)		(9,500)
Net income (loss) attributable to unitholders	$	(55,459)	$	(15,827)	$	4,173	$	(4,205)

Income (loss) per unit - basic & diluted	$	(0.72)	$	(0.22)	$	0.05	$	(0.06)
Weighted average number of units used in computing net income (loss) per unit -
Basic	76,725		72,354		76,539		72,229
Diluted	76,725		72,354		77,433		72,229

LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

ASSETS
	June 30, 2018		December 31, 2017
	(In thousands)
Current assets:
Cash	$	5,948	$	1,246
Accounts receivable, net:
Oil and natural gas	57,676		62,755
Joint interest owners	16,515		27,420
Other	6		2
Fair value of derivatives	28,046		13,424
Prepaid expenses and other current assets	10,457		7,757
Total current assets	118,648		112,604
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties	3,497,220		3,529,971
Unproved properties	31,661		28,023
Accumulated depletion, depreciation, amortization and impairment	(2,157,542)		(2,204,638)
	1,371,339		1,353,356
Other property and equipment, net of accumulated depreciation and amortization of $11,971 and $11,467, respectively	2,532		2,961
Operating rights, net of amortization of $5,944 and $5,765, respectively	1,072		1,251
Fair value of derivatives	9,968		14,099
Other assets	6,991		8,811
Total assets	$	1,510,550	$	1,493,082
LIABILITIES AND PARTNERS' DEFICIT
Current liabilities:
Current debt, net	$	505,222	$	—
Accounts payable	6,626		13,093
Accrued oil and natural gas liabilities	119,086		81,318
Fair value of derivatives	27,740		18,013
Asset retirement obligation	3,214		3,214
Other	46,538		29,172
Total current liabilities	708,426		144,810
Long-term debt, net	784,753		1,346,769
Asset retirement obligation	261,031		271,472
Fair value of derivatives	6,682		1,075
Other long-term liabilities	643		643
Total liabilities	1,761,535		1,764,769
Commitments and contingencies
Partners' deficit
Series A Preferred equity - 2,300,000 units issued and outstanding at June 30, 2018 and December 31, 2017	55,192		55,192
Series B Preferred equity - 7,200,000 units issued and outstanding at June 30, 2018 and December 31, 2017	174,261		174,261
Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2018 and December 31, 2017	30,814		30,814
Limited partners' deficit - 76,793,940 and 72,594,620 units issued and outstanding at June 30, 2018 and December 31, 2017, respectively	(511,095)		(531,794)
General partner's deficit (approximately 0.02%)	(157)		(160)
Total partners' deficit	(250,985)		(271,687)
Total liabilities and partners' deficit	$	1,510,550	$	1,493,082

Non-GAAP Financial Measures

"Adjusted EBITDA" 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.

"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.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
	(In thousands)
Net income (loss)	$	(50,709)	$	(11,077)	$	13,673	$	5,295
Plus:
Interest expense	28,589		20,614		55,957		40,747
Gain on extinguishment of debt	—		—		(51,693)		—
Income tax expense	130		150		617		571
Depletion, depreciation, amortization and accretion	38,139		27,689		74,686		56,485
Impairment of long-lived assets	35,381		1,821		35,381		9,883
(Gain) loss on disposal of assets	(1,145)		11,049		(21,540)		5,525
Equity in income of equity method investees	(3)		(1)		(20)		(12)
Unit-based compensation expense	12,886		1,483		25,692		3,380
Minimum payments received in excess of overriding royalty interest earned⁽¹⁾	334		470		856		915
Net (gains) losses on commodity derivatives	9,315		(14,516)		11,019		(49,185)
Net cash settlements (paid) received on commodity derivatives	(2,414)		6,571		(5,209)		10,807
Transaction costs	1,607		52		3,389		84
Adjusted EBITDA	$	72,110	$	44,305	$	142,808	$	84,495


(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 is recognized in net income.

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

LEGACY RESERVES LP 8-K