Matador Resources Company — Q2 2014 Form 10-Q
Reporting period: Three and six months ended June 30, 2014. Matador is an independent U.S. oil and natural gas producer focused primarily on the Eagle Ford and Permian Basin, with additional Haynesville/Cotton Valley and exploratory acreage.
Financial and operating results
| Metric | Q2 2014 | Q2 2013 | Six months 2014 | Six months 2013 |
|---|---|---|---|---|
| Oil and natural gas revenue | $99.1 million | $58.2 million | $178.0 million | $117.5 million |
| Net income | $18.2 million | $25.1 million | $34.6 million | $9.6 million |
| Diluted EPS | $0.26 | $0.45 | $0.51 | $0.17 |
| Operating income | $30.1 million | $26.9 million | $57.3 million | $12.7 million |
| Net cash from operations | Not separately provided for quarter | Not separately provided for quarter | $113.5 million | $83.9 million |
| Adjusted EBITDA (non-GAAP) | $69.5 million | $40.8 million | $125.8 million | $81.4 million |
- Q2 production reached a company record of 1.403 million BOE, or 15,424 BOE/day; oil was 802,000 barrels, 57% of production. Six-month production was 2.475 million BOE, including 1.463 million barrels of oil.
- Q2 oil and gas revenue rose 70%, mainly from a 79% increase in oil production. Six-month revenue rose 51%. Q2 realized prices before derivatives were $97.92/Bbl for oil and $5.69/Mcf for natural gas.
- Q2 net income fell 27% despite higher operating income, reflecting $8.1 million of derivative losses versus a $7.8 million derivative gain in Q2 2013, and a $10.6 million tax provision versus $32,000. Six-month net income increased from the prior year, which included a $21.2 million full-cost impairment; no impairment was recorded in 2014.
- Q2 production taxes and marketing were $6.50/BOE, lease operating costs $8.34/BOE, DD&A $22.66/BOE and G&A $5.77/BOE. Six-month lease operating cost declined to $8.51/BOE from $10.82/BOE.
- Six-month investing cash use was $236.2 million, primarily oil and gas capital spending of $234.3 million. Financing provided $131.1 million, including equity proceeds and net credit-facility activity. Cash increased $8.3 million to $14.6 million.
Balance sheet, debt and liquidity
- At June 30, 2014, cash was $14.6 million, total assets $1.133 billion, current liabilities $150.9 million and shareholders’ equity $787.2 million. Current assets of $67.3 million were below current liabilities; reported working capital was approximately negative $83.6 million.
- Credit Agreement borrowings were $150 million at quarter-end, with $0.6 million of letters of credit; the borrowing base was $385 million and the maximum facility amount $500 million. The company reported compliance with its debt-to-EBITDA covenant (maximum 4.25x). Borrowings increased by $45 million after quarter-end to $195 million by August 6.
- A May public offering of 7.5 million shares generated approximately $181.3 million net proceeds; $180 million was used to repay credit-facility borrowings. The offering increased the share count and diluted existing holders.
- Proved reserves were 57.2 million BOE at June 30, up from 51.7 million at year-end 2013. Approximately 35% were proved developed. Reserve PV-10 was $826 million and Standardized Measure was $723 million; these are estimates, not market values.
Outlook, risks and notable items
- Management raised its 2014 capital budget from $440 million to $570 million: $470 million for drilling and completion, $20 million for infrastructure and $80 million for leasehold and seismic. $273.3 million had been incurred by June 30. Management expected operating cash flow and available borrowing capacity to fund the remaining 2014 program, excluding significant acquisitions.
- As of August 6, four rigs were operating—two in the Eagle Ford and two in the Permian. Management expected the additional Permian rig to have a material effect beginning in 2015 and planned to add at least one more rig at the start of 2015.
- Management expected Chesapeake to drill up to 30 gross Haynesville wells on Matador acreage in 2014. At August 6, Matador had agreed to participate in 21 gross wells, with an estimated commitment of $37.4 million; participation in all 30 could cost approximately $50 million.
- Management cited commodity-price volatility, drilling and reserve-estimation uncertainty, production declines, service availability and cost, transportation/processing capacity, and access to capital as principal risks. Oil prices had weakened after quarter-end. Derivative contracts reduce some price exposure but also limit upside under collar ceilings; derivatives were not designated for hedge accounting and generated material earnings volatility.
- At June 30, contractual obligations totaled approximately $265.1 million, including $54.7 million of potential drilling-rig termination obligations, $30.3 million for non-operated wells, $8.0 million for gas processing/transportation, and $4.1 million for geological and geophysical data. Ordinary-course lawsuits were not expected by management to have a material adverse effect.
- The company stated disclosure controls were effective and reported no material change in internal control over financial reporting. Adoption of the new revenue-recognition standard was under evaluation.
Investor verification priorities
- Track production, well performance and realized prices, particularly whether Permian and Haynesville activity delivers the expected contribution.
- Reconcile the $570 million capital plan with operating cash flow, post-quarter-end borrowings, borrowing-base redeterminations and covenant headroom.
- Assess derivative volumes, price floors and ceilings, settlement impacts, and the sensitivity of earnings and cash flow to commodity prices.
- Review reserve growth and the large proved-undeveloped share, including development timing, cost assumptions and the sensitivity of PV-10 to prices and estimates.
- Monitor equity dilution and the timing and cash requirements of drilling, rig, processing and acreage commitments.