MIDLAND, Texas, March 18, 2019 /PRNewswire/ -- Legacy Reserves Inc. ("Legacy") (NASDAQ: LGCY) today announced the 2018 fourth quarter and year-end results. These results are subject to the completion of audited financial statements to be filed within our forthcoming Form 10-K.
Highlights since the third quarter 2018 include:
- Generated quarterly oil production of 18,630 Bbls/d and record annual oil production of 18,162 bbls/d which represents a 32% year-over-year increase;
- Brought 7 Permian horizontal wells online late in the quarter, including:
- One 4-well pad of 10,000' Wolfcamp B wells in Martin County, each of which achieved average peak rates of nearly 1,100 bbls/d prior to installation of artificial lift equipment; and
- Three 7,500'-8,000' wells in Lea County in the 1st, 2nd and 3rd Bone Spring formations, which achieved average peak rates of nearly 1,000 bbls/d;
- Drilled our first two horizontal Wolfcamp wells in Lea County with first production expected Q1 2019;
- Commenced drilling a 6-well pad in Northern Midland County consisting of 7,500' laterals across four horizons;
- Completed three Permian land swaps, enhancing drilling prospects and adding drilling locations in Lea County, NM and Martin and Midland Counties, TX:
- Increased net lateral footage by 62,000'; and
- Increased average lateral lengths 17% to approximately 7,500' for the 106 gross drilling locations comprising the 4 affected prospect areas;
- Completed 6 divestitures of 554 non-core, low-value wells generating approximately $19 million of proceeds;
- Extinguished $16.7 million of debt through equity exchanges, including exchanges after year end, at an average implied conversion price of $2.76 per share; and
- Generated net income of $78.0 million and Adjusted EBITDA of $55.7 million for the fourth quarter.
Dan Westcott, Legacy's Chief Executive Officer, commented, "The team continues to execute on our goals to efficiently develop our significant Permian horizontal resource, high-grade our assets by divesting non-core properties, and enhance our near-term drilling prospects by trading our small tracts. We're proud of our recent well results in Martin County and look forward to executing in new areas across Midland and Howard Counties later this year. I am proud of the Legacy team and their ability to post strong results despite our challenged financial situation."
Robert Norris, Legacy's Chief Financial Officer, commented, "Through 2018, Legacy completed a corporate reorganization, improved our total leverage metrics, participated in value-accretive acreage trades, and sold non-core assets in an effort to improve our leverage profile and access to capital markets. We continue that effort with our announced $135 million 2019 capital budget, which is a meaningful reduction in activity, designed to drill within cash flow. We look forward to working with our stakeholders and advisors to address our capital structure and determine the best path forward for Legacy."
Proved Reserves
The following information represents estimates of our proved reserves as of December 31, 2018 which have been prepared in compliance with the SEC rules using an average WTI price, as posted by Plains Marketing L.P., of $65.56 per Bbl for oil and an average natural gas price, as posted by Platts Gas Daily, of $3.10 per MMBtu.
Operating Regions | Oil | Natural | NGLs | Total | % | % PDP | % Total | ||||||||||||||
Permian Basin | 44,671 | 116,879 | 660 | 64,811 | 70 | % | 90 | % | 39 | % | |||||||||||
East Texas | 103 | 292,249 | 211 | 49,022 | 1 | % | 100 | % | 30 | % | |||||||||||
Rocky Mountain | 6,479 | 206,541 | 7,257 | 48,160 | 29 | % | 100 | % | 29 | % | |||||||||||
Mid-Continent | 824 | 6,051 | 1,083 | 2,916 | 65 | % | 92 | % | 2 | % | |||||||||||
Total | 52,077 | 621,720 | 9,211 | 164,909 | 37 | % | 96 | % | 100 | % | |||||||||||
2019 Capital Program By Category
Gross | Net | Percent of Net | ||||||||
(In millions) | ||||||||||
Horizontal Permian development | $ | 227 | $ | 122 | 90 | % | ||||
Workovers and recompletions | 7 | 5 | 4 | % | ||||||
Facilities, midstream, seismic & land | 8 | 8 | 6 | % | ||||||
Total capital expenditures | $ | 242 | $ | 135 | 100 | % | ||||
We serve as operator of more than 90% of our anticipated capital program, and accordingly, maintain significant control of the capital program budget and may deviate materially from the figures above based on market conditions, credit conditions, or otherwise.
Credit Agreement Update and Strategic Alternatives
Legacy continues to diligently work with the lenders under its revolving credit facility (the "Facility") for the execution of a maturity extension under the Facility.
As previously announced, Legacy is evaluating and exploring potential strategic alternatives. These alternatives include, among others, a sale or other business combination transaction, sales of assets, financing transactions, or some combination of these.
Director Transition
In association with his promotion to Chief Executive Officer, Dan Westcott, has been appointed to the Board of Directors effective immediately. In an effort to enhance the Company's governance practices, Cary Brown, a former Chief Executive Officer of Legacy's predecessor entity, has elected to resign as a director of the Board coincident with Mr. Westcott's appointment. Mr. Brown stated, "Legacy has been a blessing in my life since its inception. I pray for their success through this difficult backdrop and trust the management team and Board will keep fighting for the Company's best interests."
LEGACY RESERVES INC. | |||||||||||||||
SELECTED FINANCIAL AND OPERATING DATA | |||||||||||||||
(Unaudited) | |||||||||||||||
Three Months Ended | Twelve Months Ended | ||||||||||||||
December 31, | December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(In thousands, except per unit data) | |||||||||||||||
Revenues | |||||||||||||||
Oil sales | $ | 83,455 | $ | 85,150 | $ | 375,444 | $ | 239,448 | |||||||
Natural gas liquids sales | 6,848 | 8,105 | 27,750 | 24,796 | |||||||||||
Natural gas sales | 42,591 | 43,837 | 151,667 | 172,057 | |||||||||||
Total revenues | $ | 132,894 | $ | 137,092 | $ | 554,861 | $ | 436,301 | |||||||
Expenses: | |||||||||||||||
Oil and natural gas production | $ | 49,447 | $ | 42,594 | $ | 191,345 | $ | 173,599 | |||||||
Ad valorem taxes | 2,136 | 2,527 | 8,940 | 9,620 | |||||||||||
Total | $ | 51,583 | $ | 45,121 | $ | 200,285 | $ | 183,219 | |||||||
Production and other taxes | $ | 6,827 | $ | 6,046 | $ | 29,532 | $ | 19,825 | |||||||
General and administrative excluding transaction costs and LTIP | $ | 11,684 | $ | 9,919 | $ | 39,041 | $ | 34,006 | |||||||
Transaction costs | 795 | 8,631 | 5,635 | 8,769 | |||||||||||
LTIP expense | (3,805) | 1,666 | 28,362 | 6,597 | |||||||||||
Total general and administrative | $ | 8,674 | $ | 20,216 | $ | 73,038 | $ | 49,372 | |||||||
Depletion, depreciation, amortization and accretion | $ | 45,724 | $ | 36,738 | $ | 159,998 | $ | 126,938 | |||||||
Commodity derivative cash settlements: | |||||||||||||||
Oil derivative cash settlements received | $ | (3,940) | $ | 2,040 | $ | (16,845) | $ | 11,840 | |||||||
Natural gas derivative cash settlements received | (3,782) | 4,337 | 5,130 | 12,316 | |||||||||||
Total commodity derivative cash settlements | $ | (7,722) | $ | 6,377 | $ | (11,715) | $ | 24,156 | |||||||
Production: | |||||||||||||||
Oil (MBbls) | 1,714 | 1,628 | 6,629 | 5,032 | |||||||||||
Natural gas liquids (MGal) | 9,546 | 10,617 | 41,549 | 38,159 | |||||||||||
Natural gas (MMcf) | 14,596 | 15,866 | 58,457 | 62,833 | |||||||||||
Total (MBoe) | 4,374 | 4,525 | 17,361 | 16,413 | |||||||||||
Average daily production (Boe/d) | 47,543 | 49,185 | 47,564 | 44,967 | |||||||||||
Average sales price per unit (excluding commodity derivative cash settlements): | |||||||||||||||
Oil price (per Bbl) | $ | 48.69 | $ | 52.30 | $ | 56.64 | $ | 47.59 | |||||||
Natural gas liquids price (per Gal) | $ | 0.72 | $ | 0.76 | $ | 0.67 | $ | 0.65 | |||||||
Natural gas price (per Mcf)(a) | $ | 2.92 | $ | 2.76 | $ | 2.59 | $ | 2.74 | |||||||
Combined (per Boe) | $ | 30.38 | $ | 30.30 | $ | 31.96 | $ | 26.58 | |||||||
Average sales price per unit (including commodity derivative cash settlements): | |||||||||||||||
Oil price (per Bbl) | $ | 46.39 | $ | 53.56 | $ | 54.10 | $ | 49.94 | |||||||
Natural gas liquids price (per Gal) | $ | 0.72 | $ | 0.76 | $ | 0.67 | $ | 0.65 | |||||||
Natural gas price (per Mcf)(a) | $ | 2.66 | $ | 3.04 | $ | 2.68 | $ | 2.93 | |||||||
Combined (per Boe) | $ | 28.62 | $ | 31.71 | $ | 31.29 | $ | 28.05 | |||||||
Average WTI oil spot price (per Bbl) | $ | 59.97 | $ | 55.27 | $ | 65.23 | $ | 50.80 | |||||||
Average Henry Hub natural gas index price (per MMbtu) | $ | 3.77 | $ | 2.91 | $ | 3.15 | $ | 2.99 | |||||||
Average unit costs per Boe: | |||||||||||||||
Production costs, excluding production and other taxes | $ | 11.30 | $ | 9.41 | $ | 11.02 | $ | 10.58 | |||||||
Ad valorem taxes | $ | 0.49 | $ | 0.56 | $ | 0.51 | $ | 0.59 | |||||||
Production and other taxes | $ | 1.56 | $ | 1.34 | $ | 1.70 | $ | 1.21 | |||||||
General and administrative excluding transaction costs and LTIP | $ | 2.67 | $ | 2.19 | $ | 2.25 | $ | 2.07 | |||||||
Total general and administrative | $ | 1.98 | $ | 4.47 | $ | 4.21 | $ | 3.01 | |||||||
Depletion, depreciation, amortization and accretion | $ | 10.45 | $ | 8.12 | $ | 9.22 | $ | 7.73 | |||||||
Annual Financial and Operating Results - 2018 Compared to 2017
- Production increased 6% to an annual record of 47,564 Boe/d in 2018 from 44,967 Boe/d in 2017 primarily due to additional oil production from our Permian Basin horizontal drilling operations and higher realized ethane recoveries associated with our Piceance assets for portions of 2018. 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 20% to $31.96 per Boe in 2018 from $26.58 per Boe in 2017. Average realized oil price increased 19% to $56.64 in 2018 from $47.59 in 2017. This increase was primarily driven by an increase in the average West Texas Intermediate ("WTI") crude oil price of $14.43 per Bbl and partially offset by widening realized regional differentials. Average realized natural gas price decreased 5% to $2.59 per Mcf in 2018 from $2.74 per Mcf in 2017. This decrease was primarily driven by widening realized regional differentials partially offset by an increase in the average NYMEX pricing. Finally, our average realized NGL price increased 3% to $0.67 per gallon in 2018 from $0.65 per gallon in 2017.
- Production expenses, excluding ad valorem taxes, increased 10% to $191.3 million in 2018 from $173.6 million in 2017 primarily due to increased workover and repair activity across all operating regions, increased well count due to our Permian horizontal drilling program, partially offset by general cost reduction efforts. On an average cost per Boe basis, production expenses increased to $11.02 per Boe in 2018 from $10.58 per Boe in 2017, driven primarily by increased well count, working interests, and general cost inflations.
- Non-cash impairment expense totaled $68.0 million in 2018 primarily driven by the further decline in oil and natural gas futures prices in early 2018 as well as increased expenses and well performance during 2018.
- General and administrative expenses, excluding transaction-related expenses and unit-based Long-Term Incentive Plan ("LTIP") compensation expense increased to $39.0 million in 2018 compared to $34.0 million in 2017 primarily due to reduced overhead income which is recognized as a reduction in general and administrative expenses. The reduction is related to dispositions of oil and natural gas properties and as such, lower recovery results in an increase in our expenses. The remaining increase was due to general cost increases.
- Cash settlements paid on our commodity derivatives during 2018 were $11.7 million as compared to cash receipts of $24.2 million in 2017. The decrease in cash settlements is a result of fluctuating commodity prices and reduced nominal volumes hedged.
- Total development capital expenditures increased to $229.5 million in 2018 from $176.8 million in 2017. The 2018 activity was comprised mainly of the drilling and completion of horizontal Permian wells.
Financial and Operating Results - Fourth Quarter 2018 Compared to Fourth Quarter 2017
- Production decreased 3% to 47,543 Boe/d from 49,185 Boe/d primarily due to additional natural production declines in our Piceance assets as well as immaterial asset sales. This was partially offset by increased oil production from our Permian Basin horizontal drilling program.
- Average realized price, excluding net cash settlements from commodity derivatives, remained relatively flat at $30.38 per Boe in 2018 compared to $30.30 per Boe in 2017. Average realized oil price decreased 7% to $48.69 per Bbl in 2018 from $52.30 per Bbl in 2017. This decrease of $3.61 was primarily attributable to widening regional differentials as the average WTI crude oil price increased by $4.70. Average realized natural gas prices increased 6% to $2.92 per Mcf in 2018 from $2.76 per Mcf in 2017. This increase of $0.16 was primarily attributable to an increase in the average Henry Hub gas price. Finally, our average realized NGL price decreased 5% to $0.72 per gallon in 2018 from $0.76 per gallon in 2017.
- Production expenses, excluding ad valorem taxes, increased 16% to $49.4 million in 2018 from $42.6 million in 2017. Production expenses increased primarily due to increased workover and repair activity across all operating regions and increased well count due to our Permian horizontal drilling program, partially offset by general cost reduction efforts. On a per Boe basis, production expenses increased to $11.30 from $9.41 or 20% driven primarily by increased well work activities, decreased low cost oil production, increased competition in the market place and general cost inflations.
- Non-cash impairment expense totaled $13.6 million in 2018 primarily driven by the write-off of unproved properties acquired since 2010 as well as declining oil and natural gas futures prices, increased costs and well performance.
- General and administrative expenses, excluding acquisition costs and LTIP compensation expense, increased to $11.7 million in 2018 from $9.9 million in 2017 primarily due to reduced overhead income which is recognized as a reduction in general and administrative expenses. The reduction is related to dispositions of oil and natural gas properties and as such, lower recovery results in an increase in our expenses. The remaining increase was due to general cost increases.
- Cash settlements paid on our commodity derivatives were $7.7 million during 2018 compared to receipts of $6.4 million in 2017. The decrease in cash settlements is a result of fluctuating commodity prices and reduced nominal volumes hedged.
- Total development capital expenditures were $58 million in the fourth quarter of 2018.
Commodity Derivative Contracts
The following tables summarize, for the periods indicated, our oil and natural gas derivatives in place as of March 13, 2019 covering the period from January 1, 2019 through December 31, 2019. We use derivatives, including swaps, enhanced swaps and three-way collars, as our mechanism for offsetting the cash flow effects of changes in commodity prices whereby we pay the counterparty floating prices and receive fixed prices from the counterparty, which serves to reduce the effects on cash flow of the floating prices we are paid by purchasers of our oil and natural gas. These transactions are mostly settled based upon the monthly average closing price of front-month NYMEX WTI oil and the price on the last trading day of front-month NYMEX Henry Hub natural gas.
Oil Swaps: