MIDLAND, Texas, Aug. 03, 2016 (GLOBE NEWSWIRE) -- Legacy Reserves LP ("Legacy") (NASDAQ:LGCY) today announced second quarter results for 2016 including the following Q2 highlights:
- Reduced lease operating expenses, excluding ad valorem taxes, to $41.5 million representing an 11% decrease compared to Q1 2016 and a 14% decrease compared to Q4 2015
- Maintained production of 44,615 Boe/d, a 2% reduction compared to both Q1 2016 and Q4 2015 (without adjusting prior periods for recent asset sales)
- Closed an additional $19.0 million of asset sales
- Further reduced debt outstanding by $67.6 million including a $37.0 million reduction in borrowings under our credit facility and $30.6 million of repurchases and exchanges of senior notes
Operational Update
Through Q2 2016, we spent $11.7 million of our $37 million 2016 capital budget representing a year to date spend of 32% of the budgeted total. Approximately 22% was spent on recompletions and workovers in our East Texas region. The majority of the balance was deployed in the Permian on workovers and on horizontal development under our development agreement with an affiliate of TPG Special Situations Partners (“TSSP”) under which we operate all wells and fund 5% of the parties' development capital. Since September 2015 we have drilled and completed 12 horizontal wells under the program: 5 in Lea County, NM, 1 in Southern Reagan County, TX and 6 in Howard County, TX. After 6 months of inactivity, we recently resumed horizontal development and currently have two rigs running, one in Lea County, NM and one in Howard County, TX. Based on current strip pricing, we anticipate spending our $37 million capital budget but may deviate from such plans based on market conditions.
2016 Asset Sales Update
Through Q2 2016, we closed 18 divestitures generating net proceeds of $87.5 million. Below are the summary statistics of year to date sales:
Transaction Statistics:
| Total Sales Price | $ | 87,469,448 | |
| Transaction Count | 18 | ||
| County Count | 38 | ||
| Total Net Acreage | 54,660 | ||
| Midland Basin Net Acreage (1) | 9,679 | ||
| Approximated % of Year-End 2015 Midland Basin Acreage (1) | 51 | % | |
| Average Gross Midland Basin Tract Size (acres) | 181 | ||
| Q4 2015 Production (Boe/d) | 953 | ||
| Cash Flow (2) | $ | (536,869 | ) |
| Total Gross Well Count (3) | 733 | ||
| YE 2015 PUDs | 2 | ||
| $ / Net Midland Basin Acre (4) | $ | 7,874 | |
______________________
(1) Excludes our and TSSP's combined interests in approximately 4,092 net acres in the Midland Basin committed to the parties' development agreement.
(2) Estimate based on last twelve months prior to closing each transaction.
(3) Includes producing, injecting, shut-in and PUD wells.
(4) Calculated as sales price received attributable to Midland Basin acreage divided by Midland Basin acreage.
In July and early August, we completed three additional divestments of properties outside the Midland Basin for approximately $5.0 million, bringing our year-to-date total to $92.5 million.
Capital Structure Update
Through August 1, 2016, we have reduced our year-end 2015 total debt outstanding by $272.4 million. Our debt balances as of each of the respective dates are as follows:
| 12/31/2015 | 6/30/2016 | 8/1/2016 | |||||||
| (In thousands) | |||||||||
| Credit Facility due 2019 | $ | 608,000 | $ | 533,000 | $ | 520,000 | |||
| 8% Senior Notes (1) | 300,000 | 232,989 | 232,989 | ||||||
| 6.625% Senior Notes (1) | 550,000 | 432,656 | 432,656 | ||||||
| Total Debt Outstanding (1) | $ | 1,458,000 | $ | 1,198,645 | $ | 1,185,645 | |||
________________________________________________
(1) Excludes unamortized discount on Senior Notes.
Given our borrowing base of $630 million, outstanding borrowings of $520 million and $1.4 million of outstanding letters of credit, we currently have $108.6 million of availability.
Near-Term Outlook and Commentary
Paul T. Horne, Chairman, President and Chief Executive Officer of Legacy's general partner commented, “I am proud of the progress we made in Q2 and over the past several quarters. The difficult macro environment remains challenging but our team continues to make meaningful operational improvements. LOE was down 11% from last quarter and down 3% relative to Q2 2015, which is very impressive, given the significant increase in our property base from our acquisition of East Texas properties. We remain incredibly disciplined with our capital spending. Under our horizontal development program with TSSP, we have funded $4.1 million of capital to date and averaged approximately 850 Boe/d of net production in the quarter. With great asset-level results in that program, we recently resumed drilling under the first tranche with a rig running in both Lea County, NM and Howard County, TX.
Consistent with our view last quarter, we continue to focus on maintaining liquidity and reducing debt outstanding and therefore we have no near-term plans to resume our distributions on either our preferred units or common units. As always, we will continue to closely watch the market and respond with business objectives that match accordingly.”
Dan Westcott, Executive Vice President and Chief Financial Officer of Legacy's general partner commented, “We again improved our balance sheet this quarter. Year-to-date, our internally generated free cash flow and $92 million of asset sales has enhanced our liquidity, reduced future plugging obligations, and improved our leverage statistics. We've reduced total debt by $272.4 million and currently have over $100 million of availability under our $630 million borrowing base. Given the volatility of the macro environment, we continue to review alternatives for the business including, among others, additional asset sales and new sources of capital. As noted in the included tables, we've recently added commodity hedges to mitigate some of the impact of the market volatility. In the past few months, we increased our 2H 2016 oil hedges from 29% to 63% of current production and increased 2017 from 10% to 46%. We also increased our 2H 2016 gas hedges from 52% to 82% of current production and increased 2017 from 49% to 54%. We continue to monitor further hedge opportunities, and would have hedged additional volumes, but unfortunately, our banks have been unwilling to act as counterparty for additional hedges, which we believe is based on our credit profile and their desire to reduce exposure to the oil and gas sector. Commodity prices have improved since our last quarterly report and our internally projected cash flow has correspondingly increased, but we remain largely exposed to commodity price volatility. Our plans remain flexible to the environment in which we operate, and as Paul mentioned, we will adjust accordingly to position Legacy for success.”
| LEGACY RESERVES LP | |||||||||||||||
| SELECTED FINANCIAL AND OPERATING DATA | |||||||||||||||
| Three Months Ended | Six Months Ended | ||||||||||||||
| June 30, | June 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (In thousands, except per unit data) | |||||||||||||||
| Revenues: | |||||||||||||||
| Oil sales | $ | 41,272 | $ | 59,113 | $ | 71,592 | $ | 109,409 | |||||||
| Natural gas liquids sales | 3,922 | 5,729 | 6,375 | 9,921 | |||||||||||
| Natural gas sales | 28,173 | 22,959 | 61,259 | 50,010 | |||||||||||
| Total revenue | $ | 73,367 | $ | 87,801 | $ | 139,226 | $ | 169,340 | |||||||
| Expenses: | |||||||||||||||
| Oil and natural gas production, excluding ad valorem taxes | $ | 41,520 | $ | 42,828 | $ | 88,181 | $ | 88,772 | |||||||
| Ad valorem taxes | $ | 3,041 | $ | 2,392 | $ | 6,403 | $ | 5,668 | |||||||
| Total oil and natural gas production | $ | 44,561 | $ | 45,220 | $ | 94,584 | $ | 94,440 | |||||||
| Production and other taxes | $ | 3,390 | $ | 3,986 | $ | 5,963 | $ | 8,204 | |||||||
| General and administrative, excluding trans. related costs and LTIP | $ | 7,777 | $ | 6,549 | $ | 15,469 | $ | 14,305 | |||||||
| Transaction related costs | $ | 714 | $ | 1,648 | $ | 791 | $ | 1,673 | |||||||
| LTIP expense | $ | 2,502 | $ | 2,193 | $ | 4,167 | $ | 3,281 | |||||||
| Total general and administrative | $ | 10,993 | $ | 10,390 | $ | 20,427 | $ | 19,259 | |||||||
| Depletion, depreciation, amortization and accretion | $ | 37,668 | $ | 36,197 | $ | 74,627 | $ | 77,265 | |||||||
| Commodity derivative cash settlements: | |||||||||||||||
| Oil derivative cash settlements received | $ | 9,760 | $ | 27,364 | $ | 22,345 | $ | 59,564 | |||||||
| Natural gas derivative cash settlements received | $ | 12,333 | $ | 9,825 | $ | 22,525 | $ | 17,962 | |||||||
| Production: | |||||||||||||||
| Oil (MBbls) | 1,039 | 1,171 | 2,108 | 2,371 | |||||||||||
| Natural gas liquids (MGal) | 9,663 | 11,566 | 17,904 | 21,252 | |||||||||||
| Natural gas (MMcf) | 16,743 | 9,649 | 34,009 | 19,307 | |||||||||||
| Total (MBoe) | 4,060 | 3,055 | 8,202 | 6,095 | |||||||||||
| Average daily production (Boe/d) | 44,615 | 33,571 | 45,066 | 33,674 | |||||||||||
| Average sales price per unit (excluding derivative cash settlements): | |||||||||||||||
| Oil price (per Bbl) | $ | 39.72 | $ | 50.48 | $ | 33.96 | $ | 46.14 | |||||||
| Natural gas liquids price (per Gal) | $ | 0.41 | $ | 0.50 | $ | 0.36 | $ | 0.47 | |||||||
| Natural gas price (per Mcf) | $ | 1.68 | $ | 2.38 | $ | 1.80 | $ | 2.59 | |||||||
| Combined (per Boe) | $ | 18.07 | $ | 28.74 | $ | 16.97 | $ | 27.78 | |||||||
| Average sales price per unit (including derivative cash settlements): | |||||||||||||||
| Oil price (per Bbl) | $ | 49.12 | $ | 73.85 | $ | 44.56 | $ | 71.27 | |||||||
| Natural gas liquids price (per Gal) | $ | 0.41 | $ | 0.50 | $ | 0.36 | $ | 0.47 | |||||||
| Natural gas price (per Mcf) | $ | 2.42 | $ | 3.40 | $ | 2.46 | $ | 3.52 | |||||||
| Combined (per Boe) | $ | 23.51 | $ | 40.91 | $ | 22.45 | $ | 40.50 | |||||||
| Average WTI oil spot price (per Bbl) | $ | 45.46 | $ | 57.85 | $ | 39.55 | $ | 53.25 | |||||||
| Average Henry Hub natural gas index price (per Mcf) | $ | 2.15 | $ | 2.77 | $ | 2.07 | $ | 2.82 | |||||||
| Average unit costs per Boe: | |||||||||||||||
| Oil and natural gas production, excluding ad valorem taxes | $ | 10.23 | $ | 14.02 | $ | 10.75 | $ | 14.56 | |||||||
| Ad valorem taxes | $ | 0.75 | $ | 0.78 | $ | 0.78 | $ | 0.93 | |||||||
| Production and other taxes | $ | 0.83 | $ | 1.30 | $ | 0.73 | $ | 1.35 | |||||||
| General and administrative excluding trans. related costs and LTIP | $ | 1.92 | $ | 2.14 | $ | 1.89 | $ | 2.35 | |||||||
| Total general and administrative | $ | 2.71 | $ | 3.40 | $ | 2.49 | $ | 3.16 | |||||||
| Depletion, depreciation, amortization and accretion | $ | 9.28 | $ | 11.85 | $ | 9.10 | $ | 12.68 | |||||||
Financial and Operating Results - Three-Month Period Ended June 30, 2016 Compared to Three-Month Period Ended June 30, 2015
- Production increased 33% to 44,615 Boe/d from 33,571 Boe/d primarily due to our acquisitions in the second half of 2015 including our acquisitions of East Texas properties.
- Average realized price, excluding net cash settlements from commodity derivatives, decreased 37% to $18.07 per Boe in 2016 from $28.74 per Boe in 2015 driven by the significant decline in commodity prices as well as the increase of natural gas production as a percentage of total production. Average realized oil price decreased 21% to $39.72 in 2016 from $50.48 in 2015 driven by a decrease in the average West Texas Intermediate ("WTI") crude oil price of $12.39 per Bbl partially offset by an improvement in realized regional differentials. Average realized natural gas price decreased 29% to $1.68 per Mcf in 2016 from $2.38 per Mcf in 2015. This decrease is primarily a result of the decrease in the average Henry Hub natural gas index price of $0.62 per Mcf. Finally, our average realized NGL price decreased 18% to $0.41 per gallon in 2016 from $0.50 per gallon in 2015.
- Production expenses, excluding ad valorem taxes, decreased 3% to $41.5 million in 2016 from $42.8 million in 2015, primarily due to cost reduction efforts on historical properties, partially offset by production expenses related to our acquisition of East Texas properties ($7.5 million). On an average cost per Boe basis, production expenses excluding ad valorem taxes decreased 27% to $10.23 per Boe in 2016 from $14.02 per Boe in 2015, driven primarily by the inclusion of lower cost production from our acquired East Texas properties as well as cost reduction efforts in our historical properties.
- General and administrative expenses, excluding unit-based Long-Term Incentive Plan compensation expense increased to $8.5 million in 2016 from $8.2 million in 2015, reflecting cost reduction efforts partially offsetting increases in salaries and wages commensurate with a larger asset base following our acquisition of East Texas properties.
- Cash settlements received on our commodity derivatives during 2016 were $22.1 million compared to $37.2 million in 2015. While commodity prices were lower in 2016, the decline in cash settlements received is a result of the reduced nominal volumes hedges in Q2 2016 compared to Q2 2015.
- Total development capital expenditures decreased to $6.9 million in 2016 from $8.4 million in 2015. The 2016 activity was comprised mainly of the drilling and completion of joint development agreement wells and capital costs related to CO2 properties.
Financial and Operating Results - Six-Month Period Ended June 30, 2016 Compared to Six-Month Period Ended June 30, 2015
- Production increased 34% to 45,066 Boe/d from 33,674 Boe/d primarily due to acquisitions in the second half of 2015 including the acquisition of East Texas properties.
- Average realized price, excluding net cash settlements from commodity derivatives, decreased 39% to $16.97 per Boe in 2016 from $27.78 per Boe in 2015 driven by the significant decline in commodity prices as well as the increase in NGL and natural gas production as a percentage of total production. Average realized oil price decreased 26% to $33.96 in 2016 from $46.14 in 2015 driven by a decrease in the average WTI crude oil price of $13.70 per Bbl partially offset by an improvement in realized regional differentials. Average realized natural gas price decreased 31% to $1.80 per Mcf in 2016 from $2.59 per Mcf in 2015. This decrease is a result of the decrease in the average Henry Hub natural gas index price of approximately $0.75 per Mcf. Finally, our average realized NGL price decreased 23% to $0.36 per gallon in 2016 from $0.47 per gallon in 2015. This decrease is due to lower commodity prices.
- Despite additional expenses from our acquisition of East Texas properties of approximately $16.2 million, our production expenses, excluding ad valorem taxes, decreased 1% to $88.2 million in 2016 from $88.8 million in 2015. On an average cost per Boe basis, production expenses decreased 26% to $10.75 per Boe in 2016 from $14.56 per Boe in 2015. These significant savings were driven primarily by expense reduction efforts across our historical property set ($16.8 million) as well as the inclusion of lower cost natural gas properties acquired in East Texas.
- Non-cash impairment expense totaled $15.4 million driven by the continued decline in commodities futures prices during the first quarter of 2016.
- General and administrative expenses, excluding unit-based LTIP compensation expense totaled $16.3 million in 2016 compared to $16.0 million in 2015, reflecting cost reduction efforts partially offsetting increases in salaries and wages commensurate with a larger asset base following our acquisition of East Texas properties.
- Cash settlements received on our commodity derivatives during 2016 were $44.9 million compared to receipts of $77.5 million in 2015. While commodity prices were lower in 2016, the decline in cash settlements received is a result of the reduced nominal volumes hedges in Q2 2016 compared to Q2 2015.
- Total development capital expenditures decreased to $11.7 million in 2016 from $21.8 million in 2015. The 2016 activity was comprised mainly of the drilling and completion of joint development agreement wells and capital costs related to CO2 properties.
Commodity Derivative Contracts
We enter into oil and natural gas derivative contracts to help mitigate the risk of changing commodity prices. As of August 1, 2016, we had entered into derivative agreements to receive average NYMEX WTI crude oil prices and NYMEX Henry Hub, Waha, NWPL, SoCal and San Juan natural gas prices as summarized below.
WTI Crude Oil Swaps:
| Time Period | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | ||||||||||||
| July-December 2016 | 1,002,800 | $ | 55.24 | $ | 50.15 | - | $ | 91.00 | |||||||
| 2017 | 182,500 | $ | 84.75 | $ | 84.75 | ||||||||||
WTI Crude Oil Costless Collars. At an average WTI market price of $40.00, $50.00 and $60.00, the summary position below would result in a net price of $45.00, $50.00 and $58.89, respectively.
| Average Short | Average Long | |||||||||
| Time Period | Volumes (Bbls) | Put Price per Bbl | Put Price per Bbl | |||||||
| 2017 | 1,460,000 | $ | 45.00 | $ | 58.89 | |||||
WTI Crude Oil 3-Way Collars. At an average WTI market price of $40.00, the summary positions below would result in a net price of $65.00 for the remainder of 2016 and 2017:
| Average Short Put | Average Long Put | Average Short Call | |||||||||||||
| Time Period | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | |||||||||||
| July-December 2016 | 230,000 | $ | 60.00 | $ | 85.00 | $ | 102.46 | ||||||||
| 2017 | 72,400 | $ | 60.00 | $ | 85.00 | $ | 104.20 | ||||||||
WTI Crude Oil Enhanced Swaps. At an average WTI market price of $40.00, the summary positions below would result in a net price of $66.70, $65.85 and $65.50 for the remainder of 2016, 2017 and 2018, respectively:
| Average Long Put | Average Short Put | Average Swap | |||||||||||||
| Time Period | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | |||||||||||
| July-December 2016 | 92,000 | $ | 57.00 | $ | 82.00 | $ | 91.70 | ||||||||
| 2017 | 182,500 | $ | 57.00 | $ | 82.00 | $ | 90.85 | ||||||||
| 2018 | 127,750 | $ | 57.00 | $ | 82.00 | $ | 90.50 | ||||||||
Midland-to-Cushing WTI Crude Oil Differential Swaps:
| Time Period | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | ||||||||||||
| July-December 2016 | 1,472,000 | $ | (1.60 | ) | $ | (1.50 | ) | - | $ | (1.75 | ) | ||||
| 2017 | 2,190,000 | $ | (0.30 | ) | $ | (0.05 | ) | - | $ | (0.75 | ) | ||||
Natural Gas Swaps (Henry Hub and Waha):
| Average | |||||||||||||||
| Time Period | Volumes (MMBtu) | Price per MMBtu | Price Range per MMBtu | ||||||||||||
| July-December 2016 | 24,973,600 | $ | 3.01 | $ | 2.42 | - | $ | 5.30 | |||||||
| 2017 | 27,600,000 | $ | 3.36 | $ | 3.29 | - | $ | 3.39 | |||||||
| 2018 | 27,600,000 | $ | 3.36 | $ | 3.29 | - | $ | 3.39 | |||||||
| 2019 | 25,800,000 | $ | 3.36 | $ | 3.29 | - | $ | 3.39 | |||||||
Natural Gas Costless Collars (Henry Hub). At an average Henry Hub market price of $2.50, $3.00 and $3.50, the summary position below would result in a net price of $2.90, $3.00 and $3.44, respectively.
| Average Short | Average Long | |||||||||
| Time Period | Volumes (Bbls) | Put Price per Bbl | Put Price per Bbl | |||||||
| 2017 | 14,600,000 | $ | 2.90 | $ | 3.44 | |||||
Natural Gas 3-Way Collars (Henry Hub). At an annual average Henry Hub market price of $2.50, the summary positions below would result in a net price of $3.00 for the remainder of 2016 and 2017:
| Volumes | Average Short Put | Average Long Put | Average Short Call | |||||||||||
| Time Period | (MMBtu) | Price per MMBtu | Price per MMBtu | Price per MMBtu | ||||||||||
| July-December 2016 | 2,790,000 | $ | 3.75 | $ | 4.25 | $ | 5.08 | |||||||
| 2017 | 5,040,000 | $ | 3.75 | $ | 4.25 | $ | 5.53 | |||||||
Natural Gas Basis Swaps (NWPL, SoCal and San Juan)
| July-December 2016 | 2017 | |||||||||||
| Average | Average | |||||||||||
| Volumes (MMBtu) | Price per MMBtu | Volumes (MMBtu) | Price per MMBtu | |||||||||
| NWPL | 7,529,832 | $ | (0.19 | ) | 7,300,000 | $ | (0.16 | ) | ||||
| SoCal | — | $ | — | 2,500,250 | $ | 0.11 | ||||||
| San Juan | 1,256,720 | $ | (0.16 | ) | 2,500,250 | $ | (0.10 | ) | ||||
Location and quality differentials attributable to our properties are not reflected in the above prices. The agreements provide for monthly settlement based on the difference between the agreement fixed price and the actual reference oil and natural gas index prices.
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 3, 2016.
Conference Call
As announced on July 12, 2016, Legacy will host an investor conference call to discuss Legacy's results on Thursday, August 4, 2016 at 9:00 a.m. (Central Time). Those wishing to participate in the conference call should dial 877-266-0479. A replay of the call will be available through Thursday, August 11, 2016, by dialing 855-859-2056 or 404-537-3406 and entering replay code 49069846. Those wishing to listen to the live or archived web cast via the Internet should go to the Investor Relations tab of our website at www.LegacyLP.com. Following our prepared remarks, we will be pleased to answer questions from securities analysts and institutional portfolio managers and analysts; the complete call is open to all other interested parties on a listen-only basis.
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, during the six month period ended June 30, 2016, Legacy closed 18 divestitures generating net proceeds of $87.5 million, and Legacy may sell additional assets and use the proceeds to repay existing debt or fund capital expenditure, in which case Legacy’s unitholders may be allocated taxable income and gain resulting from the sale, all or a portion of which may be subject to recapture rules and taxed as ordinary income rather than capital gain, without receiving a cash distribution. Further, Legacy may pursue other opportunities to reduce its existing debt, such as debt exchanges, debt repurchases, or modifications that would result in COD income being allocated to its unitholders as ordinary taxable income. The ultimate effect of any income allocations will depend on the unitholder's individual tax position with respect to its units, including the availability of any current or suspended passive losses that may offset some portion of the COD income allocable to a unitholder. 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.
About Legacy Reserves LP
Legacy Reserves LP is a master limited partnership headquartered in Midland, Texas, focused on the acquisition and development of oil and natural gas properties primarily located in the Permian Basin, East Texas, Rocky Mountain and Mid-Continent regions of the United States. Additional information is available at www.LegacyLP.com.
Cautionary Statement Relevant to Forward-Looking Information
This press release contains forward-looking statements relating to our operations that are based on management's current expectations, estimates and projections about its operations. Words such as "anticipates," "expects," "intends," "plans," "targets," "projects," "believes," "seeks," "schedules," "estimated," and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: realized oil and natural gas prices; production volumes, lease operating expenses, general and administrative costs and finding and development costs; future operating results and the factors set forth under the heading "Risk Factors" in our annual and quarterly reports filed with the SEC. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, Legacy undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.
| LEGACY RESERVES LP | ||||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||
| (UNAUDITED) | ||||||||||||||||
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| (In thousands, except per unit data) | ||||||||||||||||
| Revenues: | ||||||||||||||||
| Oil sales | $ | 41,272 | $ | 59,113 | $ | 71,592 | $ | 109,409 | ||||||||
| Natural gas liquids (NGL) sales | 3,922 | 5,729 | 6,375 | 9,921 | ||||||||||||
| Natural gas sales | 28,173 | 22,959 | 61,259 | 50,010 | ||||||||||||
| Total revenues | 73,367 | 87,801 | 139,226 | 169,340 | ||||||||||||
| Expenses: | ||||||||||||||||
| Oil and natural gas production | 44,561 | 45,220 | 94,584 | 94,440 | ||||||||||||
| Production and other taxes | 3,390 | 3,986 | 5,963 | 8,204 | ||||||||||||
| General and administrative | 10,993 | 10,390 | 20,427 | 19,259 | ||||||||||||
| Depletion, depreciation, amortization and accretion | 37,668 | 36,197 | 74,627 | 77,265 | ||||||||||||
| Impairment of long-lived assets | — | — | 15,447 | 209,402 | ||||||||||||
| (Gain) loss on disposal of assets | (9,141 | ) | (934 | ) | (40,842 | ) | 1,007 | |||||||||
| Total expenses | 87,471 | 94,859 | 170,206 | 409,577 | ||||||||||||
| Operating loss | (14,104 | ) | (7,058 | ) | (30,980 | ) | (240,237 | ) | ||||||||
| Other income (expense): | ||||||||||||||||
| Interest income | 16 | 176 | 54 | 382 | ||||||||||||
| Interest expense | (20,302 | ) | (17,760 | ) | (45,478 | ) | (35,552 | ) | ||||||||
| Gain on extinguishment of debt | 19,998 | — | 150,802 | — | ||||||||||||
| Equity in income (loss) of equity method investees | (9 | ) | 24 | (14 | ) | 103 | ||||||||||
| Net gains (losses) on commodity derivatives | (37,675 | ) | (13,497 | ) | (20,637 | ) | 6,983 | |||||||||
| Other | (98 | ) | 97 | (192 | ) | 702 | ||||||||||
| Incomes (loss) before income taxes | (52,174 | ) | (38,018 | ) | 53,555 | (267,619 | ) | |||||||||
| Income tax (expense) benefit | (87 | ) | (456 | ) | (487 | ) | 291 | |||||||||
| Net income (loss) | $ | (52,261 | ) | $ | (38,474 | ) | $ | 53,068 | $ | (267,328 | ) | |||||
| Distributions to Preferred unitholders | (4,750 | ) | (4,750 | ) | (8,708 | ) | (9,500 | ) | ||||||||
| Net income (loss) attributable to unitholders | $ | (57,011 | ) | $ | (43,224 | ) | $ | 44,360 | $ | (276,828 | ) | |||||
| Income (loss) per unit - basic and diluted | $ | (0.81 | ) | $ | (0.63 | ) | $ | 0.64 | $ | (4.02 | ) | |||||
| Weighted average number of units used in computing net income (loss) per unit - | ||||||||||||||||
| Basic and diluted | 70,071 | 68,897 | 69,518 | 68,909 | ||||||||||||
| LEGACY RESERVES LP | ||||||||
| CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||||
| (UNAUDITED) | ||||||||
| ASSETS | ||||||||
| June 30, 2016 | December 31, 2015 | |||||||
| (In thousands) | ||||||||
| Current assets: | ||||||||
| Cash and cash equivalents | $ | 1,140 | $ | 2,006 | ||||
| Accounts receivable, net: | ||||||||
| Oil and natural gas | 35,578 | 33,944 | ||||||
| Joint interest owners | 13,752 | 25,378 | ||||||
| Other | 2 | 86 | ||||||
| Fair value of derivatives | 23,188 | 63,711 | ||||||
| Prepaid expenses and other current assets | 7,724 | 4,334 | ||||||
| Total current assets | 81,384 | 129,459 | ||||||
| Oil and natural gas properties using the successful efforts method, at cost: | ||||||||
| Proved properties | 3,307,925 | 3,485,634 | ||||||
| Unproved properties | 13,653 | 13,424 | ||||||
| Accumulated depletion, depreciation, amortization and impairment | (2,048,928 | ) | (2,090,102 | ) | ||||
| 1,272,650 | 1,408,956 | |||||||
| Other property and equipment, net of accumulated depreciation and amortization of $9,754 and $8,915, respectively | 4,048 | 4,575 | ||||||
| Operating rights, net of amortization of $5,161 and $4,953, respectively | 1,856 | 2,064 | ||||||
| Fair value of derivatives | 30,254 | 56,373 | ||||||
| Other assets | 10,109 | 11,047 | ||||||
| Investments in equity method investees | 633 | 646 | ||||||
| Total assets | $ | 1,400,934 | $ | 1,613,120 | ||||
| LIABILITIES AND PARTNERS' DEFICIT | ||||||||
| Current liabilities: | ||||||||
| Accounts payable | $ | 3,722 | $ | 13,581 | ||||
| Accrued oil and natural gas liabilities | 55,086 | 50,573 | ||||||
| Fair value of derivatives | 3,047 | 2,019 | ||||||
| Asset retirement obligation | 3,496 | 3,496 | ||||||
| Other | 7,594 | 11,424 | ||||||
| Total current liabilities | 72,945 | 81,093 | ||||||
| Long-term debt | 1,173,009 | 1,427,614 | ||||||
| Asset retirement obligation | 266,427 | 282,909 | ||||||
| Fair value of derivatives | 3,469 | — | ||||||
| Other long-term liabilities | 1,195 | 1,181 | ||||||
| Total liabilities | 1,517,045 | 1,792,797 | ||||||
| Commitments and contingencies | ||||||||
| Partners' equity | ||||||||
| Series A Preferred equity - 2,300,000 units issued and outstanding at June 30, 2016 and December 31, 2015 | 55,192 | 55,192 | ||||||
| Series B Preferred equity - 7,200,000 units issued and outstanding at June 30, 2016 and December 31, 2015 | 174,261 | 174,261 | ||||||
| Incentive distribution equity - 100,000 units issued and outstanding at June 30, 2016 and December 31, 2015 | 30,814 | 30,814 | ||||||
| Limited partners' deficit - 72,055,697 and 68,949,961 units issued and outstanding at June 30, 2016 and December 31, 2015, respectively | (376,260 | ) | (439,811 | ) | ||||
| General partner's deficit (approximately 0.03%) | (118 | ) | (133 | ) | ||||
| Total partners' deficit | (116,111 | ) | (179,677 | ) | ||||
| Total liabilities and partners' deficit | $ | 1,400,934 | $ | 1,613,120 | ||||
Non-GAAP Financial Measures
This press release, the financial tables and other supplemental information include "Adjusted EBITDA" and "Distributable Cash Flow", both of which are non-generally accepted accounting principles ("non-GAAP") measures which may be used periodically by management when discussing our financial results with investors and analysts. The following presents a reconciliation of each of these non-GAAP financial measures to their nearest comparable generally accepted accounting principles ("GAAP") measure.
Adjusted EBITDA and Distributable Cash Flow are presented as management believes they provide additional information concerning the performance of our business and are used by investors and financial analysts to analyze and compare our current operating and financial performance relative to past performance and such performances relative to that of other publicly traded partnerships in the industry. Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other publicly traded limited partnerships or limited liability companies because all companies may not calculate such measures in the same manner.
Distributable Cash Flow is one of the factors used by the board of directors of our general partner (the “Board”) to help determine the amount of Available Cash as defined in our partnership agreement, that is to be distributed to our unitholders for such period. Under our partnership agreement, Available Cash is defined generally to mean, cash on hand at the end of each quarter, plus working capital borrowings made after the end of the quarter, less cash reserves determined by our general partner. The Board determines whether to increase, maintain or decrease the current level of distributions in accordance with the provisions of our partnership agreement based on a variety of factors, including without limitation, Distributable Cash Flow, cash reserves established in prior periods, reserves established for future periods, borrowing capacity for working capital, temporary, one-time or uncharacteristic historical results, and forecasts of future period results including the impact of pending acquisitions. Management and the Board consider the long-term view of expected results in determining the amount of its distributions. Certain factors impacting Adjusted EBITDA and Distributable Cash Flow may be viewed as temporary, one-time in nature, or being offset by reserves from past performance or near-term future performance. Financial results are also driven by various factors that do not typically occur evenly throughout the year that are difficult to predict, including rig availability, weather, well performance, the timing of drilling and completions and near-term commodity price changes. Consistent with practices common to publicly traded partnerships, the Board historically has not varied the distribution it declares based on such timing effects.
"Adjusted EBITDA" and "Distributable Cash Flow" should not be considered as alternatives to GAAP measures, such as net income, operating income, cash flow from operating activities, or any other GAAP measure of financial performance.
The following table presents a reconciliation of our consolidated net income (loss) to Adjusted EBITDA and Distributable Cash Flow:
| Three Months Ended | Six Months Ended | ||||||||||||||
| June 30, | June 30, | ||||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||||
| (In thousands) | |||||||||||||||
| Net income (loss) | $ | (52,261 | ) | $ | (38,474 | ) | $ | 53,068 | $ | (267,328 | ) | ||||
| Plus: | |||||||||||||||
| Interest expense | 20,302 | 17,760 | 45,478 | 35,552 | |||||||||||
| Gain on extinguishment of debt | (19,998 | ) | — | (150,802 | ) | — | |||||||||
| Income tax expense (benefit) | 87 | 456 | 487 | (291 | ) | ||||||||||
| Depletion, depreciation, amortization and accretion | 37,668 | 36,197 | 74,627 | 77,265 | |||||||||||
| Impairment of long-lived assets | — | — | 15,447 | 209,402 | |||||||||||
| (Gain) loss on disposal of assets | (9,141 | ) | (934 | ) | (40,842 | ) | 1,007 | ||||||||
| Equity in (income) loss of equity method investees | 9 | (24 | ) | 14 | (103 | ) | |||||||||
| Unit-based compensation expense | 2,502 | 2,193 | 4,167 | 3,281 | |||||||||||
| Minimum payments received in excess of overriding royalty interest earned(1) | — | 377 | 802 | 744 | |||||||||||
| Equity in EBITDA of equity method investee(2) | — | 50 | — | 169 | |||||||||||
| Net (gains) losses on commodity derivatives | 37,675 | 13,497 | 20,637 | (6,983 | ) | ||||||||||
| Net cash settlements received on commodity derivatives | 22,093 | 37,189 | 44,870 | 77,526 | |||||||||||
| Transaction related expenses | 714 | 1,648 | 791 | 1,673 | |||||||||||
| Adjusted EBITDA | $ | 39,650 | $ | 69,935 | $ | 68,744 | $ | 131,914 | |||||||
| Less: | |||||||||||||||
| Cash interest expense | 17,499 | 16,950 | 36,727 | 33,992 | |||||||||||
| Development capital expenditures(4) | 6,875 | 8,415 | 11,676 | 21,781 | |||||||||||
| Distributions on Series A and Series B preferred units | — | 4,750 | — | 9,500 | |||||||||||
| Distributable Cash Flow(3) | $ | 15,276 | $ | 39,820 | $ | 20,341 | $ | 66,641 | |||||||
(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) Equity in EBITDA of equity method investee is defined as the equity method investee's net income or loss plus interest expense and depreciation. We divested our interest in this investee in May of 2015.
(3) Estimated maintenance capital expenditures are intended to represent the amount of capital required to fully offset declines in production, but do not target specific levels of proved reserves to be achieved. Estimated maintenance capital expenditures do not include the cost of new oil and natural gas reserve acquisitions, but rather the costs associated with converting proved developed non-producing, proved undeveloped and unproved reserves to proved developed producing reserves. These costs, which are incorporated in our annual capital budget as approved by the Board, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing production on both operated and non-operated properties. Estimated maintenance capital expenditures are based on management's judgment of various factors including the long-term (generally 5-10 years) decline rate of our current production and the projected productivity of our total development capital expenditures. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our production. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain production at current levels, which could adversely affect our ability to pay a distribution at the current level or at all.
(4) Represents total capital expenditures for the development of oil and natural gas properties as presented on an accrual basis. For 2016, we intend to fund our total oil and natural gas development program from net cash provided by operating activities.