Texas | 001-35410 | 27-4662601 | ||
(State or other jurisdiction of incorporation) | (Commission File Number) | (IRS Employer Identification No.) |
5400 LBJ Freeway, Suite 1500, Dallas, Texas | 75240 | |
(Address of principal executive offices) | (Zip Code) |
o | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 2.02 | Results of Operations and Financial Condition. |
Item 7.01 | Regulation FD Disclosure. |
Item 9.01 | Financial Statements and Exhibits. |
Exhibit No. | Description of Exhibit | ||
99.1 | |||
99.2 |
MATADOR RESOURCES COMPANY | ||||||
Date: February 27, 2019 | By: | /s/ Craig N. Adams | ||||
Name: | Craig N. Adams | |||||
Title: | Executive Vice President |
• | Fourth quarter 2018 average daily oil equivalent production increased 2% sequentially to a record quarterly high for the Company of 55,500 barrels of oil equivalent (“BOE”) per day (60% oil) as compared to the third quarter of 2018. Average daily oil production increased 4% sequentially to 33,500 barrels per day and average daily natural gas production decreased 1% sequentially to 132.3 million cubic feet per day, each as compared to the third quarter of 2018. |
• | Fourth quarter 2018 Delaware Basin average daily oil equivalent production increased 3% sequentially to a record quarterly high for the Company of 49,300 BOE per day (64% oil) as compared to the third quarter of 2018. Delaware Basin average daily oil production increased 5% sequentially to 31,300 barrels per day and Delaware Basin average daily natural gas production was essentially flat sequentially at 107.9 million cubic feet per day, each as compared to the third quarter of 2018. |
• | Fourth quarter 2018 net income (GAAP basis) was $136.7 million, or $1.17 per diluted common share, a sequential increase of $118.9 million from $17.8 million in the third quarter of 2018, and a year-over-year increase of 257% from $38.3 million in the fourth quarter of 2017. |
• | Fourth quarter 2018 adjusted net income (a non-GAAP financial measure) was $43.0 million, or $0.37 per diluted common share, a sequential decrease of $12.7 million from $55.7 million in the third quarter of 2018, and a year-over-year increase of 58% from $27.2 million in the fourth quarter of 2017. |
• | Fourth quarter 2018 adjusted earnings before interest expense, income taxes, depletion, depreciation and amortization and certain other items (“Adjusted EBITDA,” a non-GAAP financial measure) were $143.2 million, a sequential decrease of $12.2 million from $155.4 million in the third quarter of 2018, and a year-over-year increase of 32% from $108.6 million in the fourth quarter of 2017. |
Three Months Ended | |||||||||||||
December 31, | September 30, | December 31, | |||||||||||
2018 | 2018 | 2017 | |||||||||||
Net Production Volumes:(1) | |||||||||||||
Oil (MBbl)(2) | 3,080 | 2,973 | 2,269 | ||||||||||
Natural gas (Bcf)(3) | 12.2 | 12.3 | 10.5 | ||||||||||
Total oil equivalent (MBOE)(4) | 5,109 | 5,025 | 4,022 | ||||||||||
Average Daily Production Volumes:(1) | |||||||||||||
Oil (Bbl/d) | 33,479 | 32,317 | 24,665 | ||||||||||
Natural gas (MMcf/d)(5) | 132.3 | 133.8 | 114.3 | ||||||||||
Total oil equivalent (BOE/d)(6) | 55,536 | 54,625 | 43,718 | ||||||||||
Average Sales Prices: | |||||||||||||
Oil, without realized derivatives (per Bbl) | $ | 49.09 | $ | 57.15 | $ | 53.66 | |||||||
Oil, with realized derivatives (per Bbl) | $ | 50.75 | $ | 58.97 | $ | 52.30 | |||||||
Natural gas, without realized derivatives (per Mcf) | $ | 3.47 | $ | 3.77 | $ | 4.12 | |||||||
Natural gas, with realized derivatives (per Mcf) | $ | 3.35 | $ | 3.77 | $ | 4.12 | |||||||
Revenues (millions): | |||||||||||||
Oil and natural gas revenues | $ | 193.5 | $ | 216.3 | $ | 165.1 | |||||||
Third-party midstream services revenues | $ | 8.6 | $ | 6.8 | $ | 3.3 | |||||||
Realized gain (loss) on derivatives | $ | 3.7 | $ | 5.4 | $ | (3.1 | ) | ||||||
Operating Expenses (per BOE): | |||||||||||||
Production taxes, transportation and processing | $ | 3.53 | $ | 4.02 | $ | 4.46 | |||||||
Lease operating | $ | 4.56 | $ | 4.48 | $ | 4.68 | |||||||
Plant and other midstream services operating | $ | 1.45 | $ | 1.45 | $ | 1.16 | |||||||
Depletion, depreciation and amortization | $ | 14.19 | $ | 14.02 | $ | 13.53 | |||||||
General and administrative(7) | $ | 2.66 | $ | 3.67 | $ | 4.06 | |||||||
Total(8) | $ | 26.39 | $ | 27.64 | $ | 27.89 | |||||||
Other (millions): | |||||||||||||
Lease bonus - mineral acreage | $ | 2.5 | $ | — | $ | — | |||||||
Net sales of purchased natural gas(9) | $ | 0.4 | $ | — | $ | — | |||||||
Total | $ | 2.9 | $ | — | $ | — | |||||||
Net income (millions)(10) | $ | 136.7 | $ | 17.8 | $ | 38.3 | |||||||
Earnings per common share (diluted)(10) | $ | 1.17 | $ | 0.15 | $ | 0.35 | |||||||
Adjusted net income (millions)(10)(11) | $ | 43.0 | $ | 55.7 | $ | 27.2 | |||||||
Adjusted earnings per common share (diluted)(10)(12) | $ | 0.37 | $ | 0.48 | $ | 0.25 | |||||||
Adjusted EBITDA (millions)(10)(13) | $ | 143.2 | $ | 155.4 | $ | 108.6 |
• | For the year ended December 31, 2018, Matador’s total oil equivalent production was an all-time high totaling 19.03 million BOE, consisting of 11.14 million barrels of oil and 47.3 billion cubic feet of natural gas, an increase of 34% as compared to full year 2017. Full year 2018 oil and oil equivalent production were just above the high end of the Company’s updated full year 2018 guidance for oil and oil equivalent production of 11.0 to 11.1 million barrels and 18.8 to 19.0 million BOE, respectively. Full year 2018 natural gas production was near the high end of the Company’s updated full year 2018 natural gas guidance of 47.0 to 47.4 billion cubic feet. Matador’s full year 2018 guidance for oil, natural gas and total oil equivalent production was updated on October 31, 2018, thus, the second upward revision in 2018. |
• | Full year 2018 average daily oil equivalent production increased 34% year-over-year to 52,100 BOE per day (59% oil) as compared to the full year 2017. Average daily oil production increased 42% to 30,500 barrels per day and average daily natural gas production increased 24% to 129.6 million cubic feet per day, each as compared to the full year 2017. |
• | Full year 2018 Delaware Basin average daily oil equivalent production increased 54% to 45,200 BOE per day (62% oil) as compared to the full year 2017. Delaware Basin average daily oil production increased 56% to 28,000 barrels per day and Delaware Basin average daily natural gas production increased 51% to 103.3 million cubic feet per day, each as compared to the full year 2017. |
• | Full year 2018 net income (GAAP basis) was $274.2 million, or $2.41 per diluted common share, a year-over-year increase of 118% from $125.9 million, or $1.23 per diluted common share, for the full year 2017. |
• | Full year 2018 adjusted net income (a non-GAAP financial measure) was $184.0 million, or $1.62 per diluted common share, a year-over-year increase of 151% from $73.4 million, or $0.72 per diluted common share, for the full year 2017. |
• | Full year 2018 Adjusted EBITDA, a non-GAAP financial measure, was $553.2 million, a year-over-year increase of 65% from $336.1 million for the full year 2017. Full year 2018 Adjusted EBITDA of $553.2 million was near the high end of the Company’s full year 2018 guidance for Adjusted EBITDA of $535.0 to $555.0 million, as updated and revised upwards for the second time on October 31, 2018. |
Year Ended | |||||||||||||
December 31, | December 31, | December 31, | |||||||||||
2018 | 2017 | 2016 | |||||||||||
Net Production Volumes:(1) | |||||||||||||
Oil (MBbl)(2) | 11,141 | 7,851 | 5,096 | ||||||||||
Natural gas (Bcf)(3) | 47.3 | 38.2 | 30.5 | ||||||||||
Total oil equivalent (MBOE)(4) | 19,026 | 14,212 | 10,180 | ||||||||||
Average Daily Production Volumes:(1) | |||||||||||||
Oil (Bbl/d) | 30,524 | 21,510 | 13,924 | ||||||||||
Natural gas (MMcf/d)(5) | 129.6 | 104.6 | 83.3 | ||||||||||
Total oil equivalent (BOE/d)(6) | 52,128 | 38,936 | 27,813 | ||||||||||
Average Sales Prices: | |||||||||||||
Oil, without realized derivatives (per Bbl) | $ | 57.04 | $ | 49.28 | $ | 41.19 | |||||||
Oil, with realized derivatives (per Bbl) | $ | 57.38 | $ | 48.81 | $ | 42.34 | |||||||
Natural gas, without realized derivatives (per Mcf) | $ | 3.49 | $ | 3.72 | $ | 2.66 | |||||||
Natural gas, with realized derivatives (per Mcf) | $ | 3.46 | $ | 3.70 | $ | 2.78 | |||||||
Revenues (millions): | |||||||||||||
Oil and natural gas revenues | $ | 800.7 | $ | 528.7 | $ | 291.2 | |||||||
Third-party midstream services revenues | $ | 21.9 | $ | 10.2 | $ | 5.2 | |||||||
Realized gain (loss) on derivatives | $ | 2.3 | $ | (4.3 | ) | $ | 9.3 | ||||||
Operating Expenses (per BOE): | |||||||||||||
Production taxes, transportation and processing | $ | 4.00 | $ | 4.10 | $ | 4.23 | |||||||
Lease operating | $ | 4.89 | $ | 4.74 | $ | 5.52 | |||||||
Plant and other midstream services operating | $ | 1.29 | $ | 0.92 | $ | 0.53 | |||||||
Depletion, depreciation and amortization | $ | 13.94 | $ | 12.49 | $ | 11.99 | |||||||
General and administrative(7) | $ | 3.64 | $ | 4.65 | $ | 5.41 | |||||||
Total(8) | $ | 27.76 | $ | 26.90 | $ | 27.68 | |||||||
Other (millions): | |||||||||||||
Lease bonus - mineral acreage | $ | 2.5 | $ | — | $ | — | |||||||
Net sales of purchased natural gas(9) | $ | 0.4 | $ | — | $ | — | |||||||
Total | $ | 2.9 | $ | — | $ | — | |||||||
Net income (loss) (millions)(10) | $ | 274.2 | $ | 125.9 | $ | (97.4 | ) | ||||||
Earnings (loss) per common share (diluted)(10) | $ | 2.41 | $ | 1.23 | $ | (1.07 | ) | ||||||
Adjusted net income (loss) (millions)(10)(11) | $ | 184.0 | $ | 73.4 | $ | (2.8 | ) | ||||||
Adjusted earnings (loss) per common share (diluted)(10)(12) | $ | 1.62 | $ | 0.72 | $ | (0.03 | ) | ||||||
Adjusted EBITDA (millions)(10)(13) | $ | 553.2 | $ | 336.1 | $ | 157.9 |
At December 31, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
Estimated proved reserves:(1)(2) | ||||||||||||
Oil (MBbl)(3) | 123,401 | 86,743 | 56,977 | |||||||||
Natural Gas (Bcf)(4) | 551.5 | 396.2 | 292.6 | |||||||||
Total (MBOE)(5) | 215,313 | 152,771 | 105,752 | |||||||||
Estimated proved developed reserves: | ||||||||||||
Oil (MBbl)(3) | 53,223 | 36,966 | 22,604 | |||||||||
Natural Gas (Bcf)(4) | 246.2 | 190.1 | 126.8 | |||||||||
Total (MBOE)(5) | 94,261 | 68,651 | 43,731 | |||||||||
Percent developed | 43.8 | % | 44.9 | % | 41.4 | % | ||||||
Estimated proved undeveloped reserves: | ||||||||||||
Oil (MBbl)(3) | 70,178 | 49,777 | 34,373 | |||||||||
Natural Gas (Bcf)(4) | 305.2 | 206.1 | 165.9 | |||||||||
Total (MBOE)(5) | 121,052 | 84,120 | 62,021 | |||||||||
Standardized Measure (in millions) | $ | 2,250.6 | $ | 1,258.6 | $ | 575.0 | ||||||
PV-10 (in millions)(6) | $ | 2,579.3 | $ | 1,333.4 | $ | 581.5 | ||||||
(1) Numbers in table may not total due to rounding. | ||||||||||||
(2) Matador’s estimated proved reserves, Standardized Measure and PV-10 were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the period from January through December 2018 were $62.04 per Bbl for oil and $3.10 per MMBtu for natural gas, for the period from January through December 2017 were $47.79 per Bbl for oil and $2.98 per MMBtu for natural gas and for the period from January through December 2016 were $39.25 per Bbl for oil and $2.48 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. Matador reports its proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead price on those properties where the natural gas liquids are extracted and sold. | ||||||||||||
(3) One thousand barrels of oil. | ||||||||||||
(4) One billion cubic feet of natural gas. | ||||||||||||
(5) One thousand barrels of oil equivalent, estimated using a conversion ratio of one barrel of oil per six thousand cubic feet of natural gas. | ||||||||||||
(6) PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 (non-GAAP) to Standardized Measure (GAAP), please see “Supplemental Non-GAAP Financial Measures.” |
• | Matador’s total proved oil and natural gas reserves increased 41% year-over-year from 152.8 million BOE (57% oil, 45% proved developed, 84% Delaware Basin), consisting of 86.7 million barrels of oil and 396.2 billion cubic feet of natural gas, at December 31, 2017 to 215.3 million BOE (57% oil, 44% proved developed, |
• | At December 31, 2018, the Standardized Measure and PV-10, a non-GAAP financial measure, of Matador’s total proved oil and natural gas reserves were $2.25 billion and $2.58 billion, respectively, an increase of 79% and 93% from $1.26 billion and $1.33 billion, respectively, at December 31, 2017. At December 31, 2018, the oil and natural gas prices used to estimate total proved reserves were $62.04 per barrel and $3.10 per MMBtu, respectively, as compared to $47.79 per barrel and $2.98 per MMBtu, respectively, at December 31, 2017. |
• | At December 31, 2018, Matador’s total proved oil and natural gas reserves included 24.8 million BOE in proved undeveloped reserves, with a Standardized Measure of $249 million and a PV-10 of $286 million, attributable to portions of the 8,400 gross and net acres of leasehold that the Company acquired in the Bureau of Land Management New Mexico Oil and Gas Lease Sale in September 2018 (the “BLM Acquisition”). The PV-10 of $286 million at December 31, 2018 already represents almost 75% of the aggregate lease bonus of $387 million Matador paid to acquire these properties, not to mention the significant future midstream value of these properties to San Mateo. Matador estimates that the proved undeveloped reserves assigned to these properties at December 31, 2018 reflect only a fraction of the oil and natural gas reserves that may be ultimately attributable to these properties as a result of future development operations on this leasehold. |
• | Accounting for Matador’s 2018 oil equivalent production of 19.0 million BOE, Matador’s total proved reserves increased 81.5 million BOE in 2018, or approximately 4.3 times its 2018 annual production. The Company’s proved reserves to production ratio was 11.3 at December 31, 2018, an increase of 5% from 10.8 at December 31, 2017. The overall increase in Matador’s proved reserves of 81.5 million BOE during 2018 included aggregate upward revisions to prior estimates of 11.3 million BOE, resulting primarily from better-than-expected well performance associated with a number of wells throughout the Delaware Basin. |
• | At December 31, 2018, Matador had identified 5,442 gross (2,472 net) potential locations for future drilling on its Delaware Basin acreage, an increase of 26% in net identified locations, as compared to 4,630 gross (1,958 net) locations at December 31, 2017. The Company estimates that it may be able to operate as many as 3,451 gross (2,278 net) of these locations. As with prior estimates, Matador’s updated Delaware Basin inventory estimates assume one-mile laterals drilled at 160-acre spacing in most formations. This increase in identified well locations was primarily attributable to the Company’s acquisition of approximately 30,000 net acres of additional leasehold and mineral interests in the Delaware Basin during 2018. |
Completion | 24-hr IP | BOE/d / | Oil | ||
Asset Area/Well Name | Interval | (BOE/d) | 1,000 ft.(1) | (%) | Comments |
Antelope Ridge, Lea County, NM | |||||
Nina Cortell Federal Com #201H | Wolfcamp A-Lower | 1,753 | 368 | 78% | Strong Wolfcamp A-Lower well completed in the northwest portion of the Antelope Ridge asset area. |
Florence State 23-23S-34E AR #121H | Second Bone Spring | 1,421 | 311 | 71% | Excellent Second Bone Spring well in the Antelope Ridge asset area. |
Rustler Breaks, Eddy County, NM | |||||
David Edelstein State Com #223H | Wolfcamp B-Blair | 3,375 | 338 | 29% | Initial 2-mile Wolfcamp B-Blair test in the southwest portion of the Rustler Breaks asset area. |
Michael Collins 11-23S-27E RB #201H | Wolfcamp A-XY | 2,125 | 459 | 78% | Very strong Wolfcamp A-XY test in the northwest portion of the Rustler Breaks asset area. |
Wolf, Loving County, TX | |||||
Wolf 80-TTT-B33 WF #208H | Wolfcamp A-XY | 2,514 | 406 | 39% | Matador’s best 24-hour IP targeting the Wolfcamp A-XY in the southern portion of the Wolf asset area. |
Wolf 80-TTT-B33 WF #206H | Wolfcamp A-XY | 2,509 | 446 | 41% | Another excellent Wolfcamp A-XY well completed in the southern portion of the Wolf asset area. |
• | Production taxes, transportation and processing expenses decreased 12% sequentially from $4.02 per BOE in the third quarter of 2018 to $3.53 per BOE in the fourth quarter of 2018. This decrease was attributable primarily to lower production taxes associated with the 11% sequential decrease in oil and natural gas revenues. |
• | Lease operating expenses per BOE increased 2% from $4.48 per BOE in the third quarter of 2018 to $4.56 per BOE in the fourth quarter of 2018. The increase was attributable to higher repair and workover expenses during the quarter, partially offset by lower salt water disposal costs as more of our oil and natural gas producing wells in the Wolf and Rustler Breaks asset areas are now connected to salt water disposal wells operated by San Mateo via pipeline, thus eliminating higher priced salt water trucking costs. Lease operating expenses were better than the Company’s expectations for the quarter of between $5.00 and $5.25 per BOE as the Company was able to effectively manage costs and take advantage of increased economies of scale associated with our higher daily oil equivalent production. |
• | General and administrative expenses per BOE decreased 28% from $3.67 per BOE in the third quarter of 2018 to $2.66 per BOE in the fourth quarter of 2018, much better than the Company’s expectations. This decrease resulted primarily from economies of scale and the 34% increase in total oil equivalent production during 2018, but also reflects lesser bonus compensation paid to Matador’s principal executives in 2018, as compared to 2017, which is reflected in the Company’s fourth quarter general and administrative expenses. General and administrative expenses of $2.66 per BOE were the lowest in any quarter since Matador’s initial public offering in February 2012. Excluding $0.67 per BOE in non-cash stock-based compensation expenses, Matador’s cash-based general and administrative expenses were $1.99 per BOE in the fourth quarter of 2018. |
• | Depletion, depreciation and amortization expenses per BOE increased 1% sequentially from $14.02 per BOE in the third quarter of 2018 to $14.19 per BOE in the fourth quarter of 2018. This slight increase was attributable to increased depreciation expense associated with increased midstream property and equipment during the fourth quarter. Depreciation expenses associated with midstream operations were $4.1 million, or $0.80 per BOE, in the fourth quarter of 2018, as compared with $2.6 million, or $0.52 per BOE, in the third quarter of 2018. |
Operated | Non-Operated | Total | Gross Operated | ||||||
Asset/Operating Area | Gross | Net | Gross | Net | Gross | Net | Well Completion Intervals | ||
Rustler Breaks | 8 | 6.7 | 12 | 1.7 | 20 | 8.4 | 1-Morrow, 1-2BS, 4-WC A-XY, 1-WC B, 1-WC D | ||
Arrowhead | - | - | - | - | - | - | No Arrowhead completions in Q4 2018 | ||
Ranger | 2 | 1.9 | - | - | 2 | 1.9 | 1-1BS, 1-3BS | ||
Wolf/Jackson Trust | 4 | 3.4 | - | - | 4 | 3.4 | 3-WC A-XY, 1-WC B | ||
Twin Lakes | 1 | 1.0 | 1 | 0.1 | 2 | 1.1 | 1-WC D | ||
Antelope Ridge | 7 | 6.2 | 8 | 0.6 | 15 | 6.8 | 1-BC, 2-1BS, 1-2BS, 1-WC A-XY, 2-WC A-Lower | ||
Delaware Basin | 22 | 19.2 | 21 | 2.4 | 43 | 21.6 | Nine separate intervals tested in Q4 2018 | ||
South Texas | 1 | 1.0 | 1 | 0.3 | 2 | 1.3 | One Eagle Ford shale completion in Q4 2018 | ||
Haynesville Shale | - | - | 2 | 0.0 | 2 | 0.0 | |||
Total | 23 | 20.2 | 24 | 2.7 | 47 | 22.9 |
Operated | Non-Operated | Total | Gross Operated | ||||||
Asset/Operating Area | Gross | Net | Gross | Net | Gross | Net | Well Completion Intervals | ||
Rustler Breaks | 46 | 38.0 | 39 | 5.3 | 85 | 43.3 | 2-Morrow, 4-2BS, 25-WC A-XY, 6-WC A-Lower, 8-WC B, 1-WC D | ||
Arrowhead | 6 | 3.8 | - | - | 6 | 3.8 | 4-2BS, 1-3BS, 1-WC A-XY | ||
Ranger | 4 | 3.7 | 3 | 0.4 | 7 | 4.1 | 1-1BS, 1-2BS, 2-3BS | ||
Wolf/Jackson Trust | 11 | 8.0 | - | - | 11 | 8.0 | 8-WC A-XY, 1-WC A-Lower, 2-WC B | ||
Twin Lakes | 1 | 1.0 | 2 | 0.4 | 3 | 1.4 | 1-WC D | ||
Antelope Ridge | 14 | 12.3 | 15 | 0.9 | 29 | 13.2 | 1 BC, 4-1BS, 1-2BS, 1-3BS, 2-WC A-XY, 5-WC A-Lower | ||
Delaware Basin | 82 | 66.8 | 59 | 7.0 | 141 | 73.8 | Nine separate intervals tested in 2018 | ||
South Texas | 1 | 1.0 | 3 | 0.5 | 4 | 1.5 | |||
Haynesville Shale | - | - | 8 | 0.2 | 8 | 0.2 | |||
Total | 83 | 67.8 | 70 | 7.7 | 153 | 75.5 |
• | In October 2018, a subsidiary of San Mateo entered into a long-term agreement with a producer in Eddy County, New Mexico for the gathering and processing of such producer’s natural gas. At the time of the announcement, San Mateo had entered into contracts to provide firm gathering and processing for over 80% of the designed inlet capacity of 260 million cubic feet of natural gas per day at its Black River cryogenic natural gas processing plant (the “Black River Processing Plant”) in Eddy County, New Mexico (please see Matador’s October 16, 2018 press release for additional information). |
• | In mid-December 2018, a subsidiary of San Mateo placed into service its crude oil gathering and transportation system in Eddy County, New Mexico (the “Rustler Breaks Oil Pipeline System”). The Rustler Breaks Oil Pipeline System includes approximately 17 miles of 10-inch diameter crude oil gathering and transportation pipelines from origin points in Eddy County, New Mexico to an interconnect with Plains Pipeline, L.P. (please see San Mateo’s December 19, 2018 press release for additional information). With the Rustler Breaks Oil Pipeline System in service, Matador expects to improve its oil price realizations in the Rustler Breaks asset area by as much as $1.00 to $1.50 per barrel through the elimination of higher priced trucking costs. Matador currently has on pipe almost all of its oil production from the Wolf and Rustler Breaks asset areas, which comprised approximately 70% of the Company’s Delaware Basin oil production in the fourth quarter of 2018 (please see Matador’s December 19, 2018 press release for additional information). |
• | During the fourth quarter of 2018, San Mateo began drilling its sixth commercial salt water disposal well in the Rustler Breaks asset area in Eddy County, New Mexico. This salt water disposal well was completed and water injection began in mid-February 2019. San Mateo currently has nine commercial salt water disposal wells (six in the Rustler Breaks asset area and three in the Wolf asset area) with approximately 250,000 barrels per day of total designed salt water disposal capacity. |
• | In December 2018, San Mateo entered into a new $250 million credit facility led by the Bank of Nova Scotia (the “San Mateo Credit Facility”), and including all participants in Matador’s existing revolving credit facility led by the Royal Bank of Canada. The San Mateo Credit Facility includes an accordion feature, which could expand the commitments of the lenders to up to $400 million. The San Mateo Credit Facility is non-recourse to Matador. Upon the closing of the San Mateo Credit Facility, San Mateo borrowed $195 million, which was distributed 51% to Matador and 49% to Five Point to reimburse prior capital commitments to San Mateo. The distribution to Matador is being used to reduce outstanding borrowings under the Company’s revolving credit facility and to fund future exploration and production activities. At December 31, 2018, San Mateo had approximately $220 million in borrowings outstanding. |
• | Gathered an average of 149 million cubic feet of natural gas day in the Wolf and Rustler Breaks asset areas, a sequential increase of 14%, as compared to 131 million cubic feet per day in the third quarter of 2018, and a year-over-year increase of 41%, as compared to 106 million cubic feet per day in the fourth quarter of 2017. |
• | Processed an average of 112 million cubic feet of natural gas per day at the Black River Processing Plant, a sequential increase of 19%, as compared to 94 million cubic feet per day in the third quarter of 2018, and a year-over-year increase of 75%, as compared to 64 million cubic feet per day in the fourth quarter of 2017. |
• | Disposed of an average of 153,000 barrels of salt water per day in the Wolf and Rustler Breaks asset areas, essentially flat sequentially, as compared to 155,000 barrels per day in the third quarter of 2018, and a year-over-year increase of 84%, as compared to 83,000 barrels per day in the fourth quarter of 2017. |
• | Gathered an average of 10,000 barrels of oil per day in the Wolf and Rustler Breaks asset areas, a sequential increase of 54%, as compared to 6,500 barrels per day in the third quarter of 2018 and as compared to minimal oil volumes gathered in the fourth quarter of 2017. |
Delaware Basin Asset Area | Gross Acres | Net Acres | ||||
Rustler Breaks | 45,300 | 26,200 | ||||
Stateline | 2,800 | 2,800 | ||||
Wolf/Jackson Trust | 14,400 | 10,700 | ||||
Antelope Ridge | 20,500 | 17,300 | ||||
Arrowhead | 60,100 | 25,700 | ||||
Ranger | 34,200 | 17,500 | ||||
Twin Lakes | 44,300 | 31,300 | ||||
Other | 600 | 500 | ||||
Total | 222,200 | 132,000 |
Net | Net | |
Delaware Basin Asset Area | Mineral Acres | Royalty Acres(1) |
Rustler Breaks | 4,800 | 7,500 |
Wolf/Jackson Trust | 1,000 | 1,800 |
Antelope Ridge | 700 | 1,200 |
Arrowhead | 100 | 100 |
Ranger | 100 | 200 |
Twin Lakes | 200 | 400 |
Total | 6,900 | 11,200 |
(1) Net royalty acres normalized for a 12.5% (1/8th) royalty interest. For example, 1.0 net mineral acre with a 25% Royalty interest = 2.0 net royalty acres; 1.0 net mineral acre with a 20% royalty interest = 1.6 net royalty acres; and 1.0 net mineral acre with a 12.5% royalty interest = 1.0 net royalty acre. |
Full Year 2019 | ||
Oil Collars - West Texas Intermediate | ||
Costless Collars - Volumes Hedged (MBbl) | 4,920 | |
Weighted-average Price Ceiling ($/Bbl) | $71.74 | |
Weighted-average Price Floor ($/Bbl) | $51.46 | |
Three-Way Collars - Volumes Hedged (MBbl) | 1,320 | |
Weighted-average Price Ceiling (Long Call) ($/Bbl) | $78.85 | |
Weighted-average Price Ceiling (Short Call) ($/Bbl) | $75.00 | |
Weighted-average Price Floor ($/Bbl) | $60.00 | |
Natural Gas Collars - Henry Hub | ||
Costless Collars - Volumes Hedged (MMBtu) | 2,400,000 | |
Weighted-average Price Ceiling ($/MMBtu) | $3.80 | |
Weighted-average Price Floor ($/MMBtu) | $2.50 | |
Three-Way Collars - Volumes Hedged (MMBtu) | 4,800,000 | |
Weighted-average Price Ceiling (Long Call) ($/MMBtu) | $3.24 | |
Weighted-average Price Ceiling (Short Call) ($/MMBtu) | $3.00 | |
Weighted-average Price Floor ($/MMBtu) | $2.50 |
(In thousands, except par value and share data) | December 31, | ||||||||
2018 | 2017 | ||||||||
ASSETS | |||||||||
Current assets | |||||||||
Cash | $ | 64,545 | $ | 96,505 | |||||
Restricted cash | 19,439 | 5,977 | |||||||
Accounts receivable | |||||||||
Oil and natural gas revenues | 68,161 | 65,962 | |||||||
Joint interest billings | 61,831 | 67,225 | |||||||
Other | 16,159 | 8,031 | |||||||
Derivative instruments | 49,929 | 1,190 | |||||||
Lease and well equipment inventory | 17,564 | 5,993 | |||||||
Prepaid expenses and other assets | 8,057 | 6,287 | |||||||
Total current assets | 305,685 | 257,170 | |||||||
Property and equipment, at cost | |||||||||
Oil and natural gas properties, full-cost method | |||||||||
Evaluated | 3,780,236 | 3,004,770 | |||||||
Unproved and unevaluated | 1,199,511 | 637,396 | |||||||
Midstream and other property and equipment | 450,066 | 281,096 | |||||||
Less accumulated depletion, depreciation and amortization | (2,306,949 | ) | (2,041,806 | ) | |||||
Net property and equipment | 3,122,864 | 1,881,456 | |||||||
Other assets | |||||||||
Deferred income taxes | 20,457 | — | |||||||
Other assets | 6,512 | 7,064 | |||||||
Total other assets | 26,969 | 7,064 | |||||||
Total assets | $ | 3,455,518 | $ | 2,145,690 | |||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||||
Current liabilities | |||||||||
Accounts payable | $ | 66,970 | $ | 11,757 | |||||
Accrued liabilities | 170,855 | 174,348 | |||||||
Royalties payable | 64,776 | 61,358 | |||||||
Amounts due to affiliates | 13,052 | 10,302 | |||||||
Derivative instruments | — | 16,429 | |||||||
Advances from joint interest owners | 10,968 | 2,789 | |||||||
Amounts due to joint ventures | 2,373 | 4,873 | |||||||
Other current liabilities | 1,028 | 750 | |||||||
Total current liabilities | 330,022 | 282,606 | |||||||
Long-term liabilities | |||||||||
Borrowings under Credit Agreement | 40,000 | — | |||||||
Borrowings under San Mateo Credit Facility | 220,000 | — | |||||||
Senior unsecured notes payable | 1,037,837 | 574,073 | |||||||
Asset retirement obligations | 29,736 | 25,080 | |||||||
Derivative instruments | 83 | — | |||||||
Deferred income taxes | 13,221 | — | |||||||
Other long-term liabilities | 4,962 | 6,385 | |||||||
Total long-term liabilities | 1,345,839 | 605,538 | |||||||
Shareholders’ equity | |||||||||
Common stock — $0.01 par value, 160,000,000 shares authorized; 116,374,503 and 108,513,597 shares issued; and 116,353,590 and 108,510,160 shares outstanding, respectively | 1,164 | 1,085 | |||||||
Additional paid-in capital | 1,924,408 | 1,666,024 | |||||||
Accumulated deficit | (236,277 | ) | (510,484 | ) | |||||
Treasury stock, at cost, 20,913 and 3,437 shares, respectively | (415 | ) | (69 | ) | |||||
Total Matador Resources Company shareholders’ equity | 1,688,880 | 1,156,556 | |||||||
Non-controlling interest in subsidiaries | 90,777 | 100,990 | |||||||
Total shareholders’ equity | 1,779,657 | 1,257,546 | |||||||
Total liabilities and shareholders’ equity | $ | 3,455,518 | $ | 2,145,690 |
(In thousands, except per share data) | For the Years Ended December 31, | |||||||||||
2018 | 2017 | 2016 | ||||||||||
Revenues | ||||||||||||
Oil and natural gas revenues | $ | 800,700 | $ | 528,684 | $ | 291,156 | ||||||
Third-party midstream services revenues | 21,920 | 10,198 | 5,218 | |||||||||
Sales of purchased natural gas | 7,071 | — | — | |||||||||
Lease bonus - mineral acreage | 2,489 | — | — | |||||||||
Realized gain (loss) on derivatives | 2,334 | (4,321 | ) | 9,286 | ||||||||
Unrealized gain (loss) on derivatives | 65,085 | 9,715 | (41,238 | ) | ||||||||
Total revenues | 899,599 | 544,276 | 264,422 | |||||||||
Expenses | ||||||||||||
Production taxes, transportation and processing | 76,138 | 58,275 | 43,046 | |||||||||
Lease operating | 92,966 | 67,313 | 56,202 | |||||||||
Plant and other midstream services operating | 24,609 | 13,039 | 5,389 | |||||||||
Purchased natural gas | 6,635 | — | — | |||||||||
Depletion, depreciation and amortization | 265,142 | 177,502 | 122,048 | |||||||||
Accretion of asset retirement obligations | 1,530 | 1,290 | 1,182 | |||||||||
Full-cost ceiling impairment | — | — | 158,633 | |||||||||
General and administrative | 69,308 | 66,016 | 55,089 | |||||||||
Total expenses | 536,328 | 383,435 | 441,589 | |||||||||
Operating income (loss) | 363,271 | 160,841 | (177,167 | ) | ||||||||
Other income (expense) | ||||||||||||
Net (loss) gain on asset sales and inventory impairment | (196 | ) | 23 | 107,277 | ||||||||
Interest expense | (41,327 | ) | (34,565 | ) | (28,199 | ) | ||||||
Prepayment premium on extinguishment of debt | (31,226 | ) | — | — | ||||||||
Other income (expense) | 1,551 | 3,551 | (4 | ) | ||||||||
Total other (expense) income | (71,198 | ) | (30,991 | ) | 79,074 | |||||||
Income (loss) before income taxes | 292,073 | 129,850 | (98,093 | ) | ||||||||
Income tax (benefit) provision | ||||||||||||
Current | (455 | ) | (8,157 | ) | (1,036 | ) | ||||||
Deferred | (7,236 | ) | — | — | ||||||||
Total income tax benefit | (7,691 | ) | (8,157 | ) | (1,036 | ) | ||||||
Net income (loss) | 299,764 | 138,007 | (97,057 | ) | ||||||||
Net income attributable to non-controlling interest in subsidiaries | (25,557 | ) | (12,140 | ) | (364 | ) | ||||||
Net income (loss) attributable to Matador Resources Company shareholders | $ | 274,207 | $ | 125,867 | $ | (97,421 | ) | |||||
Earnings (loss) per common share | ||||||||||||
Basic | $ | 2.41 | $ | 1.23 | $ | (1.07 | ) | |||||
Diluted | $ | 2.41 | $ | 1.23 | $ | (1.07 | ) | |||||
Weighted average common shares outstanding | ||||||||||||
Basic | 113,580 | 102,029 | 91,273 | |||||||||
Diluted | 113,691 | 102,543 | 91,273 | |||||||||
(In thousands) | For the Years Ended December 31, | |||||||||||||
2018 | 2017 | 2016 | ||||||||||||
Operating activities | ||||||||||||||
Net income (loss) | $ | 299,764 | $ | 138,007 | $ | (97,057 | ) | |||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities | ||||||||||||||
Unrealized (gain) loss on derivatives | (65,085 | ) | (9,715 | ) | 41,238 | |||||||||
Depletion, depreciation and amortization | 265,142 | 177,502 | 122,048 | |||||||||||
Accretion of asset retirement obligations | 1,530 | 1,290 | 1,182 | |||||||||||
Full-cost ceiling impairment | — | — | 158,633 | |||||||||||
Stock-based compensation expense | 17,200 | 16,654 | 12,362 | |||||||||||
Prepayment premium on extinguishment of debt | 31,226 | — | — | |||||||||||
Deferred income tax benefit | (7,236 | ) | — | — | ||||||||||
Amortization of debt issuance cost | 1,357 | 468 | 1,148 | |||||||||||
Net loss (gain) on asset sales and inventory impairment | 196 | (23 | ) | (107,277 | ) | |||||||||
Changes in operating assets and liabilities | ||||||||||||||
Accounts receivable | (4,934 | ) | (82,549 | ) | (14,259 | ) | ||||||||
Lease and well equipment inventory | (12,176 | ) | (3,623 | ) | (700 | ) | ||||||||
Prepaid expenses and other assets | (1,770 | ) | (2,960 | ) | (124 | ) | ||||||||
Other assets | 3,418 | (6,425 | ) | 490 | ||||||||||
Accounts payable, accrued liabilities and other current liabilities | 68,647 | 33,559 | 6,611 | |||||||||||
Royalties payable | 3,418 | 37,370 | 7,495 | |||||||||||
Advances from joint interest owners | 8,179 | 1,089 | 1,000 | |||||||||||
Income taxes payable | — | — | (2,848 | ) | ||||||||||
Other long-term liabilities | (353 | ) | (1,519 | ) | 4,144 | |||||||||
Net cash provided by operating activities | 608,523 | 299,125 | 134,086 | |||||||||||
Investing activities | ||||||||||||||
Oil and natural gas properties capital expenditures | (1,357,802 | ) | (699,445 | ) | (379,067 | ) | ||||||||
Expenditures for midstream and other property and equipment | (165,784 | ) | (120,816 | ) | (74,845 | ) | ||||||||
Proceeds from sale of assets | 8,333 | 977 | 5,173 | |||||||||||
Net cash used in investing activities | (1,515,253 | ) | (819,284 | ) | (448,739 | ) | ||||||||
Financing activities | ||||||||||||||
Repayments of borrowings | (370,000 | ) | — | (120,000 | ) | |||||||||
Borrowings under Credit Agreement | 410,000 | — | 120,000 | |||||||||||
Borrowings under San Mateo Credit Facility | 220,000 | — | — | |||||||||||
Cost to enter into or amend credit facilities | (3,077 | ) | — | — | ||||||||||
Proceeds from issuance of senior unsecured notes | 1,051,500 | — | 184,625 | |||||||||||
Cost to issue senior unsecured notes | (14,098 | ) | — | (2,734 | ) | |||||||||
Purchase of senior unsecured notes | (605,780 | ) | — | — | ||||||||||
Proceeds from issuance of common stock | 226,612 | 208,720 | 288,510 | |||||||||||
Cost to issue equity | (204 | ) | (280 | ) | (847 | ) | ||||||||
Proceeds from stock options exercised | 815 | 2,920 | 100 | |||||||||||
Contributions related to formation of Joint Venture | 14,700 | 171,500 | — | |||||||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries | 85,750 | 44,100 | — | |||||||||||
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries | (121,520 | ) | (10,045 | ) | — | |||||||||
Taxes paid related to net share settlement of stock-based compensation | (6,466 | ) | (5,763 | ) | (1,948 | ) | ||||||||
Purchase of non-controlling interest of less-than-wholly-owned subsidiary | — | (2,653 | ) | — | ||||||||||
Net cash provided by financing activities | 888,232 | 408,499 | 467,706 | |||||||||||
(Decrease) increase in cash and restricted cash | (18,498 | ) | (111,660 | ) | 153,053 | |||||||||
Cash and restricted cash at beginning of year | 102,482 | 214,142 | 61,089 | |||||||||||
Cash and restricted cash at end of year | $ | 83,984 | $ | 102,482 | $ | 214,142 | ||||||||
Three Months Ended | Year Ended December 31, | |||||||||||||||||||||||
(In thousands) | December 31, 2018 | September 30, 2018 | December 31, 2017 | 2018 | 2017 | 2016 | ||||||||||||||||||
Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): | ||||||||||||||||||||||||
Net income (loss) attributable to Matador Resources Company Shareholders | $ | 136,713 | $ | 17,794 | $ | 38,335 | $ | 274,207 | $ | 125,867 | $ | (97,421 | ) | |||||||||||
Net income attributable to non-controlling interest in subsidiaries | 7,375 | 7,321 | 4,106 | 25,557 | 12,140 | 364 | ||||||||||||||||||
Net income (loss) | 144,088 | 25,115 | 42,441 | 299,764 | 138,007 | (97,057 | ) | |||||||||||||||||
Interest expense | 14,492 | 10,340 | 8,336 | 41,327 | 34,565 | 28,199 | ||||||||||||||||||
Total income tax benefit | (7,691 | ) | — | (8,157 | ) | (7,691 | ) | (8,157 | ) | (1,036 | ) | |||||||||||||
Depletion, depreciation and amortization | 72,478 | 70,457 | 54,436 | 265,142 | 177,502 | 122,048 | ||||||||||||||||||
Accretion of asset retirement obligations | 404 | 387 | 353 | 1,530 | 1,290 | 1,182 | ||||||||||||||||||
Full-cost ceiling impairment | — | — | — | — | — | 158,633 | ||||||||||||||||||
Unrealized (gain) loss on derivatives | (74,577 | ) | 21,337 | 11,734 | (65,085 | ) | (9,715 | ) | 41,238 | |||||||||||||||
Stock-based compensation expense | 3,413 | 4,842 | 4,166 | 17,200 | 16,654 | 12,362 | ||||||||||||||||||
Net loss (gain) on asset sales and inventory impairment | — | 196 | — | 196 | (23 | ) | (107,277 | ) | ||||||||||||||||
Prepayment premium on extinguishment of debt | — | 31,226 | — | 31,226 | — | — | ||||||||||||||||||
Consolidated Adjusted EBITDA | 152,607 | 163,900 | 113,309 | 583,609 | 350,123 | 158,292 | ||||||||||||||||||
Adjusted EBITDA attributable to non-controlling interest subsidiaries | (9,368 | ) | (8,508 | ) | (4,690 | ) | (30,386 | ) | (14,060 | ) | (400 | ) | ||||||||||||
Adjusted EBITDA attributable to Matador Resources Company shareholders | $ | 143,239 | $ | 155,392 | $ | 108,619 | $ | 553,223 | $ | 336,063 | $ | 157,892 | ||||||||||||
Three Months Ended | Year Ended December 31, | |||||||||||||||||||||||
(In thousands) | December 31, 2018 | September 30, 2018 | December 31, 2017 | 2018 | 2017 | 2016 | ||||||||||||||||||
Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by Operating Activities: | ||||||||||||||||||||||||
Net cash provided by operating activities | $ | 189,205 | $ | 165,111 | $ | 76,609 | $ | 608,523 | $ | 299,125 | $ | 134,086 | ||||||||||||
Net change in operating assets and liabilities | (50,129 | ) | (11,111 | ) | 36,886 | (64,429 | ) | 25,058 | (1,809 | ) | ||||||||||||||
Interest expense, net of non-cash portion | 13,986 | 9,900 | 7,971 | 39,970 | 34,097 | 27,051 | ||||||||||||||||||
Current income tax benefit | (455 | ) | — | (8,157 | ) | (455 | ) | (8,157 | ) | (1,036 | ) | |||||||||||||
Adjusted EBITDA attributable to non-controlling interest subsidiaries | (9,368 | ) | (8,508 | ) | (4,690 | ) | (30,386 | ) | (14,060 | ) | (400 | ) | ||||||||||||
Adjusted EBITDA attributable to Matador Resources Company shareholders | $ | 143,239 | $ | 155,392 | $ | 108,619 | $ | 553,223 | $ | 336,063 | $ | 157,892 | ||||||||||||
Three Months Ended | Year Ended December 31, | |||||||||||||||||||||||
December 31, 2018 | September 30, 2018 | December 31, 2017 | 2018 | 2017 | 2016 | |||||||||||||||||||
(In thousands, except per share data) | ||||||||||||||||||||||||
Unaudited Adjusted Net Income (Loss) and Adjusted Earnings (Loss) Per Common Share Reconciliation to Net Income (Loss): | ||||||||||||||||||||||||
Net income (loss) attributable to Matador Resources Company shareholders | $ | 136,713 | $ | 17,794 | $ | 38,335 | $ | 274,207 | $ | 125,867 | $ | (97,421 | ) | |||||||||||
Total income tax benefit | (7,691 | ) | — | (8,157 | ) | (7,691 | ) | (8,157 | ) | (1,036 | ) | |||||||||||||
Income (loss) attributable to Matador Resources shareholders before taxes (1) | 129,022 | 17,794 | 30,178 | 266,516 | 117,710 | (98,457 | ) | |||||||||||||||||
Less non-recurring and unrealized charges to income (loss) before taxes: | ||||||||||||||||||||||||
Full-cost ceiling impairment | — | — | — | — | — | 158,633 | ||||||||||||||||||
Unrealized (gain) loss on derivatives | (74,577 | ) | 21,337 | 11,734 | (65,085 | ) | (9,715 | ) | 41,238 | |||||||||||||||
Net loss (gain) on asset sales and inventory impairment | — | 196 | — | 196 | (23 | ) | (107,277 | ) | ||||||||||||||||
Non-recurring expenses related to stock-based compensation | — | — | — | — | 1,515 | — | ||||||||||||||||||
Non-recurring transaction costs associated with the formation of San Mateo | — | — | — | — | 3,458 | — | ||||||||||||||||||
Prepayment premium on extinguishment of debt | — | 31,226 | — | 31,226 | — | — | ||||||||||||||||||
Adjusted income (loss) attributable to Matador Resources shareholders before taxes | 54,445 | 70,553 | 41,912 | 232,853 | 112,945 | (5,863 | ) | |||||||||||||||||
Income tax expense (benefit)(1) | 11,433 | 14,816 | 14,669 | 48,899 | 39,531 | (3,088 | ) | |||||||||||||||||
Adjusted net income (loss) attributable to Matador Resources Company shareholders (non-GAAP) | $ | 43,012 | $ | 55,737 | $ | 27,243 | $ | 183,954 | $ | 73,414 | $ | (2,775 | ) | |||||||||||
Weighted average shares outstanding, including participating securities - basic | 116,341 | 116,358 | 107,693 | 113,580 | 102,029 | 91,273 | ||||||||||||||||||
Dilutive effect of options and restricted stock units | 68 | 554 | 492 | 111 | 514 | — | ||||||||||||||||||
Weighted average common shares outstanding - diluted | 116,409 | 116,912 | 108,185 | 113,691 | 102,543 | 91,273 | ||||||||||||||||||
Adjusted earnings (loss) per share attributable to Matador Resources shareholders (non-GAAP) | ||||||||||||||||||||||||
Basic | $ | 0.37 | $ | 0.48 | $ | 0.25 | $ | 1.62 | $ | 0.72 | $ | (0.03 | ) | |||||||||||
Diluted | $ | 0.37 | $ | 0.48 | $ | 0.25 | $ | 1.62 | $ | 0.72 | $ | (0.03 | ) | |||||||||||
(1) | Estimated using federal statutory tax rate in effect for the period. Year ended December 31, 2016 also includes a $1.1 million income tax refund. |
(in millions) | At December 31, 2018 | At December 31, 2017 | At December 31, 2016 | |||||||||
Standardized Measure | $ | 2,250.6 | $ | 1,258.6 | $ | 575.0 | ||||||
Discounted future income taxes | 328.7 | 74.8 | 6.5 | |||||||||
PV-10 | $ | 2,579.3 | $ | 1,333.4 | $ | 581.5 | ||||||
Guidance Metric | Actual 2018 Results | 2019 Guidance | % YoY Change(1) | |
Total Oil Production | 11.1 million Bbl | 12.9 to 13.3 million Bbl | +18 | % |
Total Natural Gas Production | 47.3 Bcf | 55.0 to 57.0 Bcf | +18 | % |
Total Oil Equivalent Production | 19.0 million BOE | 22.0 to 22.8 million BOE | +18 | % |
Adjusted EBITDA(2) | $553 million | $520 to $550 million | -3 | % |
D/C/E CapEx(3) | $686 million | $640 to $680 million | -4 | % |
Midstream CapEx(4) | $85 million | $55 to $75 million | -24 | % |
Commodity Prices | Actual 2018 Results | 2019 Projections | % YoY Change | |
Realized Unhedged Oil Price(2) | $57.04 per barrel | $49.80 per barrel | -13 | % |
Realized Unhedged Natural Gas Price(2) | $3.49 per Mcf | $2.88 per Mcf | -17 | % |
• | Six drilling rigs operating in the Delaware Basin, including 73 gross (54.9 net) wells anticipated to be completed and turned to sales during 2019 and the drilling and completion of at least three salt water disposal wells, one in the Stebbins area and two in the Rustler Breaks asset area during 2019, including one salt water |
• | One drilling rig operating in South Texas until its release in early February 2019, including eight gross (8.0 net) wells anticipated to be completed and turned to sales during 2019; |
• | Matador’s participation in a significant number of non-operated well opportunities, including 69 gross (4.6 net) non-operated wells anticipated to be completed and turned to sales in the Delaware Basin and 16 gross (1.7 net) non-operated wells anticipated to be completed and turned to sales in the Haynesville shale during 2019; |
• | Oil and natural gas prices based on commodity futures strip prices as of mid-February 2019, resulting in an estimated realized weighted average oil price of approximately $49.80 per barrel and an estimated realized weighted average natural gas price of $2.88 per Mcf, inclusive of the Company’s estimates for oil and natural gas price differentials, transportation costs and uplifts attributable to NGL revenues; |
• | Capital expenditures for drilling, completing and equipping wells (“D/C/E capital expenditures”) of $640 to $680 million, a decrease of 4% at the midpoint of 2019 guidance, as compared to full year 2018, and inclusive of an estimated $70 million in equipping and facilities costs and an estimated $29 million of capitalized general and administrative and interest expenses; and |
• | Midstream capital expenditures of $55 to $75 million, a decrease of 24% at the midpoint of 2019 guidance, as compared to full year 2018. This estimate primarily reflects Matador’s proportionate share of San Mateo’s 2019 estimated capital expenditures of $180 to $220 million and also accounts for portions of the $50 million capital carry that Five Point is expected to provide to Matador as part of the recently announced San Mateo expansion in Eddy County, New Mexico. As a result, Matador has agreed to pay $25 million and Five Point has agreed to pay $125 million of the first $150 million in capital expenditures related to this expansion. |
Operated | Non-Operated | Total | Gross Operated | ||||||
Asset/Operating Area | Gross | Net | Gross | Net | Gross | Net | Well Completion Intervals | ||
Rustler Breaks | 17 | 11.3 | 28 | 2.9 | 45 | 14.2 | 1-BC, 1-1BS, 6-WC A-XY, 2-WC A-Lower, 6-WC B-Blair, 1-WC D | ||
Arrowhead | 8 | 5.2 | 5 | 0.2 | 13 | 5.4 | 4-2BS, 1-3BS, 2-WC A-XY, 1-WC B | ||
Ranger | 7 | 4.4 | 4 | 0.4 | 11 | 4.8 | 1-1BS, 1-2BS, 4-3BS, 1-WC A-XY | ||
Wolf/Jackson Trust | 12 | 9.0 | - | - | 12 | 9.0 | 2-2BS, 6-WC A-XY, 2-WC A-Lower, 2-WC B | ||
Twin Lakes | 2 | 1.6 | - | - | 2 | 1.6 | 1-Morrow, 1-WC-Carb | ||
Antelope Ridge | 27 | 23.4 | 32 | 1.1 | 59 | 24.5 | 6-1BS, 1-2BS, 6-3BS, 3-WC A-XY, 10-WC A-Lower, 1-WC B | ||
Delaware Basin | 73 | 54.9 | 69 | 4.6 | 142 | 59.5 | |||
Eagle Ford Shale | 8 | 8.0 | - | - | 8 | 8.0 | |||
Haynesville Shale | - | - | 16 | 1.7 | 16 | 1.7 | |||
Total | 81 | 62.9 | 85 | 6.3 | 166 | 69.2 |
• | Average daily oil equivalent production should increase 3 to 4% sequentially, as compared to 55,500 BOE per day in the fourth quarter of 2018; |
• | Average daily oil production should increase 1 to 2% sequentially, as compared to 33,500 barrels per day in the fourth quarter of 2018; and |
• | Average daily natural gas production should increase 6 to 8% sequentially, as compared to 132.3 million cubic feet per day in the fourth quarter of 2018. |
Year Ended December 31, | ||||
(In thousands) | 2018 | |||
Unaudited Adjusted EBITDA Reconciliation to Net Income: | ||||
Net income attributable to Matador Resources Company shareholders | $274,207 | |||
Net income attributable to non-controlling interest in subsidiaries | 25,557 | |||
Net income | $299,764 | |||
Interest expense | 41,327 | |||
Total income tax benefit | (7,691) | |||
Depletion, depreciation and amortization | 265,142 | |||
Accretion of asset retirement obligations | 1,530 | |||
Unrealized gain on derivatives | (65,085) | |||
Stock-based compensation expense | 17,200 | |||
Net loss on asset sales and inventory impairment | 196 | |||
Prepayment premium on extinguishment of debt | 31,226 | |||
Consolidated Adjusted EBITDA | 583,609 | |||
Adjusted EBITDA attributable to non-controlling interest in subsidiaries | (30,386) | |||
Adjusted EBITDA attributable to Matador Resources Company shareholders | $553,223 | |||
Year Ended December 31, | ||||
(In thousands) | 2018 | |||
Unaudited Adjusted EBITDA Reconciliation to | ||||
Net Cash Provided by Operating Activities: | ||||
Net cash provided by operating activities | $608,523 | |||
Net change in operating assets and liabilities | (64,429) | |||
Interest expense, net of non-cash portion | 39,970 | |||
Current income tax benefit | (455) | |||
Adjusted EBITDA attributable to non-controlling interest in subsidiaries | (30,386) | |||
Adjusted EBITDA attributable to Matador Resources Company shareholders | $553,223 |