Legacy Reserves 8-K Legacy Reserves Inc. Announces Third Quarter 2018 Results

Exhibit 99.1

Legacy Reserves Inc. Announces Third Quarter 2018 Results

MIDLAND, Texas, October 31, 2018—(PRNewswire) — Legacy Reserves Inc. (“Legacy”) (NASDAQ:LGCY) today announced 2018 third quarter results including the following highlights:

• Completed our corporate reorganization to become aC-Corp; commenced trading as Legacy Reserves Inc.;

• Generated record quarterly oil production of 18,902 Bbls/d, a 5.6% increase relative to Q2’18, and 31% relative to Q3’17;

• Brought 7 Permian horizontal wells online during the quarter, totaling 36 of such wellsyear-to-date;

• Commenced Wolfcamp drilling in the Delaware Basin in Lea County, NM; preparing to mobilize Midland Basin horizontal rig from Martin to Midland County, TX;

• Completed $21.7 million of asset sales to date since June 30, 2018, bringing ouryear-to-date statistics (inclusive of transactions postquarter-end) to the following:

• 24 transactions generating $50.9 million of proceeds;

• 1,454 gross wells producing ~1,600 boe/d;

• $18.3 million of P&A liability relieved; and

• Implied 5.9x EBITDA transaction multiple;

• Completed exchange of $130 million of Senior Notes due 2020 and 2021 for $130 million of Convertible Senior Notes due 2023 and 105,020 shares of common stock;

• Obtained borrowing base reaffirmation at $575 million; and

• Generated Adjusted EBITDA of $78.4 million, an 8.7% increase relative to Q2’18, from a net loss of $47.9 million.

Paul T. Horne, Legacy’s Chairman of the Board and Chief Executive Officer, commented, “The team completed our first quarter as aC-Corp with a bang as we delivered record oil production that represented 31% year-over-year growth. We continue to focus on our Permian development as we have maintained a rig in Lea County, New Mexico and we are about to move our second rig from Martin to Midland County. Our technical teams continue to hone our well and completion designs and, although basin-wide pressures persist, we are leveraging our long-established relationships to secure services and drive efficiencies. I am also pleased to have validated our theory that theC-Corp would enhance our access to capital as we completed a convertible exchange transaction that extends maturities and provides a path to equitize a significant portion of our debt. As mentioned in today’s other press release, I am excited to see our upcoming senior management team continue our growth efforts while targeting free cash flow neutrality.”

Dan Westcott, Legacy’s President and Chief Financial Officer, commented, “Strong production growth drove Adjusted EBITDA higher despite a challenged Midland oil price this quarter. The team continued to execute, completing several critical, leverage-accretive asset sales. We have also moved the ball forward on several new horizontal prospects and look forward to efficiently developing that resource as we head intoyear-end planning for 2019.”

LEGACY RESERVES INC.

SELECTED FINANCIAL AND OPERATING DATA

	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
	(In thousands, except per unit data)
Revenues:
Oil sales	$	98,779		$	59,060	$	291,989		$	154,298
Natural gas liquids (NGL) sales		7,771			6,720		20,902			16,691
Natural gas sales		38,657			41,035		109,076			128,220
Total revenue	$	145,207		$	106,815	$	421,967		$	299,209
Expenses:
Oil and natural gas production, excluding ad valorem taxes	$	49,431		$	39,515	$	141,898		$	131,005
Ad valorem taxes		1,873			2,564		6,804			7,093
Total oil and natural gas production	$	51,304		$	42,079	$	148,702		$	138,098
Production and other taxes	$	7,721		$	5,475	$	22,705		$	13,779
General and administrative, excluding transaction costs and LTIP	$	9,852		$	8,418	$	27,357		$	24,087
Transaction costs		1,451			54		4,840			138
LTIP expense		6,475			1,551		32,167			4,931
Total general and administrative	$	17,778		$	10,023	$	64,364		$	29,156
Depletion, depreciation, amortization and accretion	$	39,588		$	33,715	$	114,274		$	90,200
Commodity derivative cash settlements:
Oil derivative cash settlements (paid) received	$	(1,702	)	$	3,102	$	(12,905	)	$	9,800
Natural gas derivative cash settlements received	$	2,919		$	3,870	$	8,913		$	7,979
Production:
Oil (MBbls)		1,739			1,323		4,915			3,404
Natural gas liquids (MGal)		11,427			11,375		32,003			27,542
Natural gas (MMcf)		15,026			15,771		43,861			46,967
Total (MBoe)		4,515			4,222		12,987			11,888
Average daily production (Boe/d)		49,076			45,891		47,571			43,542
Average sales price per unit (excluding derivative cash settlements):
Oil price (per Bbl)	$	56.80		$	44.64	$	59.41		$	45.33
Natural gas liquids price (per Gal)	$	0.68		$	0.59	$	0.65		$	0.61
Natural gas price (per Mcf)	$	2.57		$	2.60	$	2.49		$	2.73
Combined (per Boe)	$	32.16		$	25.30	$	32.49		$	25.17
Average sales price per unit (including derivative cash settlements):
Oil price (per Bbl)	$	55.82		$	46.99	$	56.78		$	48.21
Natural gas liquids price (per Gal)	$	0.68		$	0.59	$	0.65		$	0.61
Natural gas price (per Mcf)	$	2.77		$	2.85	$	2.69		$	2.90
Combined (per Boe)	$	32.43		$	26.95	$	32.18		$	26.67
Average WTI oil spot price (per Bbl)	$	69.69		$	48.18	$	66.93		$	49.30
Average Henry Hub natural gas index price (per MMbtu)	$	2.93		$	2.95	$	2.95		$	3.01
Average unit costs per Boe:
Oil and natural gas production, excluding ad valorem taxes	$	10.95		$	9.36	$	10.93		$	11.02
Ad valorem taxes	$	0.41		$	0.61	$	0.52		$	0.60
Production and other taxes	$	1.71		$	1.30	$	1.75		$	1.16
General and administrative excluding transaction costs and LTIP	$	2.18		$	1.99	$	2.11		$	2.03
Total general and administrative	$	3.94		$	2.37	$	4.96		$	2.45
Depletion, depreciation, amortization and accretion	$	8.77		$	7.98	$	8.80		$	7.59

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

• Production increased 7% to 49,076 Boe/d from 45,891 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests under our amended and restated joint development agreement with TPG Sixth Street Partners (the “Amended and Restated Development Agreement”). 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 27% to $32.16 per Boe in 2018 from $25.30 per Boe in 2017 driven by an increase in oil production as a percentage of total production and the significant increase in oil prices, partially offset by widening regional differentials. Average realized oil price increased 27% to $56.80 in 2018 from $44.64 in 2017 driven by an increase in the average WTI crude oil price of $21.51 per Bbl, partially offset by the wideningMid-Cush differential. Average realized natural gas price decreased 1% to $2.57 per Mcf in 2018 from $2.60 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. These decreases were partially offset by an increase in Permian natural gas production which is sold inclusive of NGL content and therefore increases realized pricing for those volumes. Finally, our average realized NGL price increased 15% to $0.68 per gallon in 2018 from $0.59 per gallon in 2017.

• Production expenses, excluding ad valorem taxes, increased to $49.4 million in 2018 from $39.5 million in 2017, primarily due to increased well count due to our Permian horizontal drilling program, increased working interests under our Amended and Restated Development Agreement and general cost inflation.

• Non-cash impairment expense totaled $19.0 million primarily due to the write down of assetsheld-for-sale and the decline in natural gas futures prices.

• General and administrative expenses, excluding unit-based Long-Term Incentive Plan (“LTIP”) compensation expense, increased to $11.3 million in 2018 from $8.5 million in 2017 due to a $1.4 million increase in transaction costs and general cost increases. LTIP compensation expense increased due to the recent rise in our share price and accelerated vesting in connection with the Corporate Reorganization. Had the Corporate Reorganization not occurred, general and administrative expenses, excluding LTIP, would have decreased by $2.0 million.

• Cash settlements received on our commodity derivatives during 2018 were $1.2 million compared to $7.0 million in 2017. The decrease 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 ourMid-Cush derivatives.

• Total development capital expenditures decreased to $31.2 million in 2018 from $93.2 million in 2017. The 2018 activity was comprised mainly of our Permian horizontal drilling program. The 2017 activity was comprised mainly of the drilling and completion of joint development agreement wells. After the acceleration payment under our joint development agreement, we became responsible for 85% of the parties’ combined interests of all remaining Tranche 1 capital costs to be paid regardless of when such costs were incurred, resulting in a larger increase in capital expenditures.

Financial and Operating Results—Nine-Month Period Ended September 30, 2018 Compared to Nine-Month Period Ended September 30, 2017

• Production increased 9% to 47,571 Boe/d from 43,542 Boe/d primarily due to additional oil production from our Permian Basin horizontal drilling operations and production attributable to the additional working interests under the Amended and Restated Development Agreement. 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 29% to $32.49 per Boe in 2018 from $25.17 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 31% to $59.41 in 2018 from $45.33 in 2017 driven by an increase in the average WTI crude oil price of $17.63 per Bbl, partially offset by the wideningMid-Cush differential. Average realized natural gas price decreased 9% to $2.49 per Mcf in 2018 from $2.73 per Mcf in 2017. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $0.06 per Mcf, widening realized regional differentials and our adoption of ASC 606. Finally, our average realized NGL price increased 7% to $0.65 per gallon in 2018 from $0.61 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 $141.9 million in 2018 from $131.0 million in 2017. This increase was due to increased well count due to our Permian horizontal drilling program, increased working interests under our Amended and Restated Development Agreement and general cost inflation.

• Non-cash impairment expense totaled $54.4 million related to the decline in natural gas prices and the write-down of assetsheld-for-sale to their fair market value.

• General and administrative expenses, excluding unit-based LTIP compensation expense totaled $32.2 million in 2018 compared to $24.2 million in 2017, reflecting a $4.7 million increase in transaction costs and general cost increases. LTIP compensation expense increased $27.2 million due to the recent rise in our share price and accelerated vesting in connection with the Corporate Reorganization. Had the Corporate Reorganization not occurred, general and administrative expenses, excluding LTIP, would have decreased by $2.0 million.

• Cash settlements paid on our commodity derivatives during 2018 were $4.0 million compared to cash receipts of $17.8 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 ourMid-Cush derivatives.

• Total development capital expenditures increased to $171.6 million in 2018 from $141.5 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 October 29, 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
October-December 2018		763,600	$	54.76	$	51.20 - $63.68
2019		3,285,000	$	61.33	$	57.15 - $67.65

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.

Time Period	Volumes (Bbls)		Average Long Put Price per Bbl		Average Short Call Price per Bbl
October-December 2018		391,000	$	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.

Time Period	Volumes (Bbls)		Average Long Put Price per Bbl		Average Short Put Price per Bbl		Average Swap Price per Bbl
October-December 2018		32,200	$	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
October-December 2018		1,012,000	$	(1.13	)	$	(1.25) - $(0.80)
2019		2,193,000	$	(3.62	)	$	(5.60) - $(1.15)

Midland-to-Cushing WTI Crude Oil Differential Enhanced Swaps

Time Period	Volumes (Bbls)		Average Short Price Call per Bbl		Average Swap Price per Bbl
2019		1,460,000	$	70.00	$	(2.91	)

NYMEX Natural Gas Swaps (Henry Hub):

Time Period	Volumes (MMBtu)		Average Price per MMBtu		Price Range per MMBtu
October-December 2018		9,080,000	$	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 Form10-Q

Financial results contained herein are preliminary and subject to the final, unaudited financial statements and related footnotes included in Legacy’s Form10-Q which will be filed on or about October 31, 2018.

Conference Call

As announced on October 17, 2018, Legacy will host an investor conference call to discuss Legacy’s results on Thursday, November 1, 2018 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial888-346-9287. A replay of the call will be available through Thursday, November 8, 2018, by dialing877-344-7529 and entering replay code 10125178. Those wishing to listen to the live or archived webcast via the Internet should go to the Investor Relations tab of our website atwww.LegacyReserves.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 Inc.

Legacy is an independent energy company engaged in the development, production and acquisition of oil and natural gas properties in the United States. Its current operations are focused on the horizontal development of unconventional plays in the Permian Basin and the cost-efficient management of shallow-decline oil and natural gas wells in the Permian Basin, East Texas, Rocky Mountain andMid-Continent regions. Additional information is available atwww.LegacyReserves.com.

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 future growth and dividends of the 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 and Legacy LP’s filings with the U.S. Securities and Exchange Commission, including its Annual Report on Form10-K, Quarterly Reports on Form10-Q and Current Reports on Form8-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 INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In thousands, except per share / unit data)
Revenues:
Oil sales	$	98,779		$	59,060		$	291,989		$	154,298
Natural gas liquids (NGL) sales		7,771			6,720			20,902			16,691
Natural gas sales		38,657			41,035			109,076			128,220
Total revenues		145,207			106,815			421,967			299,209
Expenses:
Oil and natural gas production		51,304			42,079			148,702			138,098
Production and other taxes		7,721			5,475			22,705			13,779
General and administrative		17,778			10,023			64,364			29,156
Depletion, depreciation, amortization and accretion		39,588			33,715			114,274			90,200
Impairment of long-lived assets		18,994			14,665			54,375			24,548
(Gains) losses on disposal of assets		7,368			(2,034	)		(14,172	)		3,491
Total expenses		142,753			103,923			390,248			299,272
Operating income (loss)		2,454			2,892			31,719			(63	)
Other income (expense):
Interest income		16			35			31			44
Interest expense		(29,383	)		(23,621	)		(85,340	)		(64,368	)
Gain on extinguishment of debt		12,107			—			63,800			—
Equity in income (loss) of equity method investees		(30	)		—			(10	)		12
Net gains (losses) on commodity derivatives		(30,867	)		(13,309	)		(41,886	)		35,876
Other		350			403			623			765
Loss before income taxes		(45,353	)		(33,600	)		(31,063	)		(27,734	)
Income tax expense		(2,499	)		(266	)		(3,116	)		(837	)
Net loss	$	(47,852	)	$	(33,866	)	$	(34,179	)	$	(28,571	)
Loss per share / unit—basic & diluted	$	(0.46	)	$	(0.34	)	$	(0.33	)	$	(0.29	)
Weighted average number of shares / units used in computing net loss per share / unit -
Basic		104,637			100,206			104,336			99,985
Diluted		104,637			100,206			104,336			99,985

LEGACY RESERVES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

ASSETS

	September 30, 2018			December 31, 2017
	(In thousands)
Current assets:
Cash	$	3,305		$	1,246
Accounts receivable, net:
Oil and natural gas		61,109			62,755
Joint interest owners		14,516			27,420
Other		2			2
Fair value of derivatives		19,228			13,424
Prepaid expenses and other current assets		10,231			7,757
Total current assets		108,391			112,604
Oil and natural gas properties using the successful efforts method, at cost:
Proved properties		3,497,024			3,529,971
Unproved properties		28,897			28,023
Accumulated depletion, depreciation, amortization and impairment		(2,192,877	)		(2,204,638	)
		1,333,044			1,353,356
Other property and equipment, net of accumulated depreciation and amortization of $12,179 and $11,467, respectively		2,464			2,961	��
Operating rights, net of amortization of $6,034 and $5,765, respectively		983			1,251
Fair value of derivatives		3,183			14,099
Other assets		3,671			8,811
Total assets	$	1,451,736		$	1,493,082
LIABILITIES AND STOCKHOLDERS’ DEFICIT / PARTNERS’ DEFICIT
Current liabilities:
Current debt, net		527,391		$	—
Accounts payable		7,838			13,093
Accrued oil and natural gas liabilities		83,216			81,318
Fair value of derivatives		39,072			18,013
Asset retirement obligation		3,214			3,214
Other		43,163			29,172
Total current liabilities		703,894			144,810
Long-term debt, net		755,784			1,346,769
Asset retirement obligation		261,260			271,472
Fair value of derivatives		12,114			1,075
Other long-term liabilities		641			643
Total liabilities		1,733,693			1,764,769
Commitments and contingencies
Partners’ deficit
Series A Preferred equity—2,300,000 units issued and outstanding at December 31, 2017		—			55,192
Series B Preferred equity—7,200,000 units issued and outstanding at December 31, 2017		—			174,261
Incentive distribution equity—100,000 units issued and outstanding at December 31, 2017		—			30,814
Limited partners’ deficit—72,594,620 units issued and outstanding at December 31, 2017		—			(531,794	)
General partner’s deficit (approximately 0.02%)		—			(160	)
Common stock, $0.01 par value; 945,000,000 shares authorized, 106,113,000 shares outstanding at September 30, 2018		1,061			—
Additionalpaid-in capital		13,471			—
Accumulated deficit		(296,489	)		—
Total stockholders’ deficit		(281,957	)		(271,687	)
Total liabilities and stockholders’ / partners’ deficit	$	1,451,736		$	1,493,082

Non-GAAP Financial Measures

“Adjusted EBITDA” is anon-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 thisnon-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 loss to Adjusted EBITDA:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In thousands)
Net loss	$	(47,852	)	$	(33,866	)	$	(34,179	)	$	(28,571	)
Plus:
Interest expense		29,383			23,621			85,340			64,368
Gain on extinguishment of debt		(12,107	)		—			(63,800	)		—
Income tax expense		2,499			266			3,116			837
Depletion, depreciation, amortization and accretion		39,588			33,715			114,274			90,200
Impairment of long-lived assets		18,994			14,665			54,375			24,548
(Gain) loss on disposal of assets		7,368			(2,034	)		(14,172	)		3,491
Equity in (income) loss of equity method investees		30			—			10			(12	)
Share-based compensation expense		6,475			1,551			32,167			4,931
Minimum payments received in excess of overriding royalty interest earned(1)		516			512			1,373			1,427
Net (gains) losses on commodity derivatives		30,867			13,309			41,886			(35,876	)
Net cash settlements (paid) received on commodity derivatives		1,217			6,972			(3,992	)		17,779
Transaction costs		1,451			54			4,840			138
Adjusted EBITDA(2)	$	78,429		$	58,765		$	221,238		$	143,260

(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.

(2) Had the Corporate Reorganization not occurred on September 20, 2018, EBITDA would have increased to $80.4 million and $223.2 million for the three and nine month periods ending September 30, 2018, respectively.

CONTACT: Legacy Reserves Inc.

Dan Westcott

President and Chief Financial Officer

(432)689-5200