Filed by Legacy Reserves LP
(Commission File No. 1-33249)
Pursuant to Rule 425 under the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
of the Securities Exchange Act of 1934
Subject Company: Legacy Reserves Inc.
(Registration No. 333-224182)
Legacy Reserves LP Announces First Quarter 2018 Results and Updated 2018 Guidance
MIDLAND, Texas, May 2, 2018- (PRNewswire) — Legacy Reserves LP (“Legacy”) (NASDAQ:LGCY) today announced first quarter results for 2018 including the following highlights:
| • | Announced transaction to transition from MLP to C-Corp; |
| • | Divested non-core Mid-Con assets with $15.4 million of plugging liability for $25.3 million in cash proceeds, further rationalizing our asset base and focusing our capital deployment; |
| • | Brought 20 wells online late in the quarter with average peak rates exceeding expectations. These additional wells bring the total to 67 wells drilled and completed since commencement of the horizontal drilling program; |
| • | Generated net income of $64.4 million; |
| • | Generated Adjusted EBITDA of $70.7 million; and |
| • | Reduced commodity price risk by adding 6,000 Bbls/d of 2019 WTI crude oil swaps at average swap price of $58.88 per barrel. |
Paul T. Horne, Chairman of the Board and Chief Executive Officer of Legacy’s general partner, commented, “We started 2018 focused on our two-rig horizontal Permian drilling program having brought an additional 20 wells online late in the quarter with peak rates, on average, exceeding our expectations. Due to our lease-wide development approach, we experienced significant non-productive time during the quarter including dewatering and temporary shut-ins of offset wells. While this operational approach enables us to focus on maximizing long-term lease-wide economics, it certainly can hamper short-term field-level production results. We remain excited about our previously-announced transaction that will transition Legacy to a C-Corp and currently anticipate a mid-2018 closing of the transaction. We continue to believe this transition will be a crucial step in our move to a growth-oriented development company and play an important part in future company success.”
Dan Westcott, President and Chief Financial Officer of Legacy’s general partner, commented, “Q1 proved to be an inflection point in Legacy’s history as we announced our intention to transition to a C-Corp. We remain convinced of the key benefits of the transaction and, as we continue to work through the requisite steps to complete this transition, we will continue to focus on the efficient operation of our PDP base and development of our substantial horizontal Permian resource.
“We are thankful for the recent rise in oil prices. However, such increase has heightened the level of industry activity in the oil-rich Permian Basin and we, like other operators in the Basin, are now seeing some associated negative effects including wider commodity price differentials, third-party service constraints and increased production interference from increased development in and offsetting our densely developed leasehold. As longstanding, experienced players in the Permian, we will continue to utilize our strong local relationships and work through these industry-wide challenges. Despite some newly-projected delays and recently widened price differentials, we are very pleased with our well performance and expect continued success in our revised 2018 outlook. Importantly, we remain confident that our asset quality is high and our opportunity set deep.”
1
Updated 2018 Guidance
The following table sets forth certain assumptions used by Legacy to estimate its anticipated results of operations for 2018 based on Legacy’s 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.”
| Q2-Q4 2018E Range | FY 2018E Range | |||||||||||||||||||||||
| ($ in thousands unless otherwise noted) | ||||||||||||||||||||||||
| Production: |
||||||||||||||||||||||||
| Oil (Bbls/d) |
18,400 | — | 21,000 | 18,101 | — | 20,060 | ||||||||||||||||||
| Natural gas liquids (Bbls/d) |
1,925 | — | 2,200 | 2,053 | — | 2,261 | ||||||||||||||||||
| Natural gas (MMcf/d) |
158 | — | 171 | 158 | — | 168 | ||||||||||||||||||
| Total (Boe/d) |
46,658 | — | 51,700 | 46,487 | — | 50,321 | ||||||||||||||||||
| Weighted average NYMEX differentials: |
||||||||||||||||||||||||
| Oil (per Bbl) |
$ | (10.00 | ) | — | $ | (7.50 | ) | $ | (7.94 | ) | — | $ | (6.06 | ) | ||||||||||
| NGL realization(1) |
54 | % | — | 60 | % | 54 | % | — | 59 | % | ||||||||||||||
| Natural gas (per Mcf) |
$ | (0.75 | ) | — | $ | (0.55 | ) | $ | (0.64 | ) | — | $ | (0.49 | ) | ||||||||||
| Expenses: |
||||||||||||||||||||||||
| Lease operating expenses(2) |
$ | 128,000 | — | $ | 138,000 | $ | 173,585 | — | $ | 183,585 | ||||||||||||||
| Ad valorem and production taxes (% of revenue) |
7.00 | % | — | 7.50 | % | 7.02 | % | — | 7.39 | % | ||||||||||||||
| Cash G&A expenses(3) |
$ | 25,000 | — | $ | 28,000 | $ | 34,502 | — | $ | 37,502 | ||||||||||||||
| Commodity derivative realizations |
$ | (6,000 | ) | — | $ | (6,000 | ) | $ | (8,795 | ) | — | $ | (8,795 | ) | ||||||||||
| Adjusted EBITDA(4): |
$ | 217,000 | — | $ | 262,000 | $ | 287,698 | — | $ | 332,698 | ||||||||||||||
| (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 Q1 2018 realized pricing and NYMEX strip pricing at April 25, 2018 (2018 Avg Oil $65.50 / $2.85 Gas).
2
LEGACY RESERVES LP
SELECTED FINANCIAL AND OPERATING DATA
| Three Months Ended March 31, |
||||||||
| 2018 | 2017 | |||||||
| (In thousands, except per unit data) |
||||||||
| Revenues: |
||||||||
| Oil sales |
$ | 93,411 | $ | 49,142 | ||||
| Natural gas liquids (NGL) sales |
7,396 | 5,050 | ||||||
| Natural gas sales |
36,672 | 45,355 | ||||||
|
|
|
|
|
|||||
| Total revenue |
$ | 137,479 | $ | 99,547 | ||||
|
|
|
|
|
|||||
| Expenses: |
||||||||
| Oil and natural gas production, excluding ad valorem taxes |
$ | 45,585 | $ | 49,228 | ||||
| Ad valorem taxes |
2,382 | 1,989 | ||||||
|
|
|
|
|
|||||
| Total oil and natural gas production |
$ | 47,967 | $ | 51,217 | ||||
| Production and other taxes |
$ | 7,326 | $ | 4,159 | ||||
| General and administrative, excluding LTIP and transaction costs |
$ | 9,502 | $ | 8,623 | ||||
| Transaction costs |
1,782 | 32 | ||||||
| LTIP expense |
12,806 | 1,897 | ||||||
|
|
|
|
|
|||||
| Total general and administrative |
$ | 24,090 | $ | 10,552 | ||||
| Depletion, depreciation, amortization and accretion |
$ | 36,547 | $ | 28,796 | ||||
| Commodity derivative cash settlements: |
||||||||
| Oil derivative cash settlements (paid) received |
$ | (4,894 | ) | $ | 3,139 | |||
| Natural gas derivative cash settlements received |
$ | 2,099 | $ | 1,097 | ||||
| Production: |
||||||||
| Oil (MBbls) |
1,547 | 1,037 | ||||||
| Natural gas liquids (MGal) |
9,244 | 7,653 | ||||||
| Natural gas (MMcf) |
14,280 | 15,592 | ||||||
| Total (MBoe) |
4,147 | 3,818 | ||||||
| Average daily production (Boe/d) |
46,078 | 42,422 | ||||||
| Average sales price per unit (excluding derivative cash settlements): |
||||||||
| Oil price (per Bbl) |
$ | 60.38 | $ | 47.39 | ||||
| Natural gas liquids price (per Gal) |
$ | 0.80 | $ | 0.66 | ||||
| Natural gas price (per Mcf) |
$ | 2.57 | $ | 2.91 | ||||
| Combined (per Boe) |
$ | 33.15 | $ | 26.07 | ||||
| Average sales price per unit (including derivative cash settlements): |
||||||||
| Oil price (per Bbl) |
$ | 57.22 | $ | 50.42 | ||||
| Natural gas liquids price (per Gal) |
$ | 0.80 | $ | 0.66 | ||||
| Natural gas price (per Mcf) |
$ | 2.72 | $ | 2.98 | ||||
| Combined (per Boe) |
$ | 32.48 | $ | 27.18 | ||||
| Average WTI oil spot price (per Bbl) |
$ | 62.91 | $ | 51.62 | ||||
| Average Henry Hub natural gas index price (per MMbtu) |
$ | 3.08 | $ | 3.02 | ||||
| Average unit costs per Boe: |
||||||||
| Oil and natural gas production, excluding ad valorem taxes |
$ | 10.99 | $ | 12.89 | ||||
| Ad valorem taxes |
$ | 0.57 | $ | 0.52 | ||||
| Production and other taxes |
$ | 1.77 | $ | 1.09 | ||||
| General and administrative excluding transaction costs and LTIP |
$ | 2.29 | $ | 2.26 | ||||
| Total general and administrative |
$ | 5.81 | $ | 2.76 | ||||
| Depletion, depreciation, amortization and accretion |
$ | 8.81 | $ | 7.54 | ||||
3
Financial and Operating Results—Three-Month Period Ended March 31, 2018 Compared to Three-Month Period Ended March 31, 2017
| • | Production increased 9% to 46,078 Boe/d from 42,422 Boe/d primarily due to additional oil production from our horizontal drilling operations in Howard County, Texas and Lea County, New Mexico and production attributable to the additional working interests that reverted to us in connection with making an acceleration payment (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 27% to $33.15 per Boe in 2018 from $26.07 per Boe in 2017 driven by the significant increase in commodity prices and increase in oil production as a percentage of total production. Average realized oil price increased 27% to $60.38 in 2018 from $47.39 in 2017 driven by an increase in the average WTI crude oil price of $11.29 per Bbl and increased Permian production which has realized better differentials than our other regions. Average realized natural gas price decreased 12% to $2.57 per Mcf in 2018 from $2.91 per Mcf in 2017. This decrease is primarily a result of widening realized regional differentials and our adoption of ASC 606 partially offset by an increase in average Henry Hub natural gas index price of $0.06 per Mcf. Finally, our average realized NGL price increased 21% to $0.80 per gallon in 2018 from $0.66 per gallon in 2017. |
| • | Production expenses, excluding ad valorem taxes, decreased to $45.6 million in 2018 from $49.2 million in 2017, primarily due to cost containment efforts across all operating regions partially offset by increased well count related to our Permian horizontal drilling program and expenses associated with the additional working interests that reverted to us in connection with making the Acceleration Payment. On an average cost per Boe basis, production expenses excluding ad valorem taxes decreased 15% to $10.99 per Boe in 2018 from $12.89 per Boe in 2017. |
| • | General and administrative expenses, excluding unit-based Long-Term Incentive Plan (“LTIP”) compensation expense, increased to $11.3 million in 2018 from $8.7 million in 2017 due to general cost increases. LTIP compensation expense increased $10.9 million due to the recent rise in our unit price. |
| • | Cash settlements paid on our commodity derivatives during 2018 were $2.8 million compared to cash receipts of $4.2 million in 2017. The change in cash settlements is a result of the combination of higher commodity prices and reduced nominal volumes hedged in Q1 2018 compared to Q1 2017 as well as lower contracted hedge prices. |
| • | Total development capital expenditures increased to $59.7 million in 2018 from $23.7 million in 2017. The 2018 activity was comprised mainly of our horizontal drilling program in Lea County, NM and Howard County, TX. |
4
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of April 30, 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 | |||||||||||||||||
| April-December 2018 |
2,282,500 | $ | 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.
| Time Period |
Volumes (Bbls) | Average Long Put Price per Bbl |
Average Short Call Price per Bbl |
|||||||||
| April-December 2018 |
1,168,750 | $ | 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 |
||||||||||||
| April-December 2018 |
96,250 | $ | 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 | |||||||||||||||||
| April-December 2018 |
3,025,000 | $ | (1.13 | ) | $ | (1.25 | ) | — | $ | (0.80 | ) | |||||||||
| 2019 |
730,000 | $ | (1.15 | ) | $(1.15) | |||||||||||||||
NYMEX Natural Gas Swaps (Henry Hub):
| Time Period |
Volumes (MMBtu) | Average Price per MMBtu |
Price Range per MMBtu |
|||||||||||||||||
| April-December 2018 |
27,200,000 | $ | 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.
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 May 2, 2018.
5
Conference Call
As announced on April 19, 2018, Legacy will host an investor conference call to discuss Legacy’s results on Thursday, May 3, 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, May 10, 2018, by dialing 877-344-7529 and entering replay code 10119507. 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.
6
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 that will be 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 will be 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, 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.
7
LEGACY RESERVES LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
| Three Months Ended March 31, |
||||||||
| 2018 | 2017 | |||||||
| (In thousands, except per unit data) |
||||||||
| Revenues: |
||||||||
| Oil sales |
$ | 93,411 | $ | 49,142 | ||||
| Natural gas liquids (NGL) sales |
7,396 | 5,050 | ||||||
| Natural gas sales |
36,672 | 45,355 | ||||||
|
|
|
|
|
|||||
| Total revenues |
137,479 | 99,547 | ||||||
|
|
|
|
|
|||||
| Expenses: |
||||||||
| Oil and natural gas production |
47,967 | 51,217 | ||||||
| Production and other taxes |
7,326 | 4,159 | ||||||
| General and administrative |
24,090 | 10,552 | ||||||
| Depletion, depreciation, amortization and accretion |
36,547 | 28,796 | ||||||
| Impairment of long-lived assets |
— | 8,062 | ||||||
| Gain on disposal of assets |
(20,395 | ) | (5,524 | ) | ||||
|
|
|
|
|
|||||
| Total expenses |
95,535 | 97,262 | ||||||
|
|
|
|
|
|||||
| Operating income |
41,944 | 2,285 | ||||||
| Other income (expense): |
||||||||
| Interest income |
12 | 1 | ||||||
| Interest expense |
(27,368 | ) | (20,133 | ) | ||||
| Gain on extinguishment of debt |
51,693 | — | ||||||
| Equity in income of equity method investees |
17 | 11 | ||||||
| Net gains (losses) on commodity derivatives |
(1,704 | ) | 34,669 | |||||
| Other |
275 | (40 | ) | |||||
|
|
|
|
|
|||||
| Income before income taxes |
64,869 | 16,793 | ||||||
| Income tax expense |
(487 | ) | (421 | ) | ||||
|
|
|
|
|
|||||
| Net income |
$ | 64,382 | $ | 16,372 | ||||
| Distributions to Preferred unitholders |
(4,750 | ) | (4,750 | ) | ||||
|
|
|
|
|
|||||
| Net income attributable to unitholders |
$ | 59,632 | $ | 11,622 | ||||
|
|
|
|
|
|||||
| Income per unit—basic and diluted |
$ | 0.78 | $ | 0.16 | ||||
|
|
|
|
|
|||||
| Weighted average number of units used in computing net income per unit - |
||||||||
| Basic |
76,350 | 72,103 | ||||||
|
|
|
|
|
|||||
| Diluted |
76,657 | 72,103 | ||||||
|
|
|
|
|
|||||
8
LEGACY RESERVES LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
| March 31, 2018 |
December 31, 2017 |
|||||||
| (In thousands) | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | — | $ | 1,246 | ||||
| Accounts receivable, net: |
||||||||
| Oil and natural gas |
66,254 | 62,755 | ||||||
| Joint interest owners |
21,074 | 27,420 | ||||||
| Other |
2 | 2 | ||||||
| Fair value of derivatives |
15,034 | 13,424 | ||||||
| Prepaid expenses and other current assets |
7,575 | 7,757 | ||||||
|
|
|
|
|
|||||
| Total current assets |
109,939 | 112,604 | ||||||
|
|
|
|
|
|||||
| Oil and natural gas properties using the successful efforts method, at cost: |
||||||||
| Proved properties |
3,423,592 | 3,529,971 | ||||||
| Unproved properties |
29,492 | 28,023 | ||||||
| Accumulated depletion, depreciation, amortization and impairment |
(2,093,640 | ) | (2,204,638 | ) | ||||
|
|
|
|
|
|||||
| 1,359,444 | 1,353,356 | |||||||
|
|
|
|
|
|||||
| Other property and equipment, net of accumulated depreciation and amortization of $11,746 and $11,467, respectively |
2,739 | 2,961 | ||||||
| Operating rights, net of amortization of $5,855 and $5,765, respectively |
1,162 | 1,251 | ||||||
| Fair value of derivatives |
14,150 | 14,099 | ||||||
| Other assets |
8,175 | 8,811 | ||||||
| Investments in equity method investees |
||||||||
|
|
|
|
|
|||||
| Total assets |
$ | 1,495,609 | $ | 1,493,082 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND PARTNERS’ DEFICIT | ||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 3,363 | $ | 13,093 | ||||
| Accrued oil and natural gas liabilities |
72,602 | 81,318 | ||||||
| Fair value of derivatives |
18,164 | 18,013 | ||||||
| Asset retirement obligation |
3,214 | 3,214 | ||||||
| Other |
42,602 | 29,172 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
139,945 | 144,810 | ||||||
|
|
|
|
|
|||||
| Long-term debt |
1,296,953 | 1,346,769 | ||||||
| Asset retirement obligation |
258,554 | 271,472 | ||||||
| Fair value of derivatives |
628 | 1,075 | ||||||
| Other long-term liabilities |
643 | 643 | ||||||
|
|
|
|
|
|||||
| Total liabilities |
1,696,723 | 1,764,769 | ||||||
|
|
|
|
|
|||||
| Commitments and contingencies |
||||||||
| Partners’ deficit |
||||||||
| Series A Preferred equity—2,300,000 units issued and outstanding at March 31, 2018 and December 31, 2017 |
55,192 | 55,192 | ||||||
| Series B Preferred equity—7,200,000 units issued and outstanding at March 31, 2018 and December 31, 2017 |
174,261 | 174,261 | ||||||
| Incentive distribution equity—100,000 units issued and outstanding at March 31, 2018 and December 31, 2017 |
30,814 | 30,814 | ||||||
| Limited partners’ deficit—76,658,829 and 72,594,620 units issued and outstanding at March 31, 2018 and December 31, 2017, respectively |
(461,236 | ) | (531,794 | ) | ||||
| General partner’s deficit (approximately 0.02%) |
(145 | ) | (160 | ) | ||||
|
|
|
|
|
|||||
| Total partners’ deficit |
(201,114 | ) | (271,687 | ) | ||||
|
|
|
|
|
|||||
| Total liabilities and partners’ deficit |
$ | 1,495,609 | $ | 1,493,082 | ||||
|
|
|
|
|
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9
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 March 31, |
||||||||
| 2018 | 2017 | |||||||
| (In thousands) | ||||||||
| Net income |
$ | 64,382 | $ | 16,372 | ||||
| Plus: |
||||||||
| Interest expense |
27,368 | 20,133 | ||||||
| Gain on extinguishment of debt |
(51,693 | ) | — | |||||
| Income tax expense |
487 | 421 | ||||||
| Depletion, depreciation, amortization and accretion |
36,547 | 28,796 | ||||||
| Impairment of long-lived assets |
— | 8,062 | ||||||
| Gain on disposal of assets |
(20,395 | ) | (5,524 | ) | ||||
| Equity in income of equity method investees |
(17 | ) | (11 | ) | ||||
| Unit-based compensation expense |
12,806 | 1,897 | ||||||
| Minimum payments received in excess of overriding royalty interest earned(1) |
522 | 445 | ||||||
| Net (gains) losses on commodity derivatives |
1,704 | (34,669 | ) | |||||
| Net cash settlements (paid) received on commodity derivatives |
(2,795 | ) | 4,236 | |||||
| Transaction costs |
1,782 | 32 | ||||||
|
|
|
|
|
|||||
| Adjusted EBITDA |
$ | 70,698 | $ | 40,190 | ||||
|
|
|
|
|
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10
| (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 |
11