Matador Resources Company — Q2 2016 Form 10-Q
Reporting period: Quarter and six months ended June 30, 2016; unaudited. Matador is an independent U.S. oil and gas exploration and production company focused primarily on the Delaware Basin, with operations also in the Eagle Ford, Haynesville and Cotton Valley plays.
Financial and operating performance
| Metric | Q2 2016 | Q2 2015 | Six months 2016 | Six months 2015 |
|---|---|---|---|---|
| Oil and gas revenue | $69.3 million | $87.8 million | $113.3 million | $150.3 million |
| Total revenue, including derivative gains/losses | $45.2 million | $78.1 million | $89.3 million | $150.5 million |
| Net loss attributable to Matador shareholders | $105.9 million | $157.1 million | $213.5 million | $207.3 million |
| Adjusted EBITDA | $39.0 million | $66.7 million | $56.2 million | $116.8 million |
| Net cash from operating activities | Not clearly stated for the quarter | Not clearly stated for the quarter | $49.6 million | $113.4 million |
| Oil-equivalent production | 2.55 million BOE | 2.42 million BOE | 4.72 million BOE | 4.54 million BOE |
- Q2 average daily production was 28,022 BOE, up 5% year over year; H1 averaged 25,934 BOE per day, up 4%. Q2 production comprised approximately 48% oil and 52% natural gas on an equivalent basis.
- Q2 realized prices before derivative gains were $42.84 per barrel of oil and $2.10 per Mcf of natural gas, versus $54.37 and $2.78, respectively, a year earlier. H1 realized prices were $36.43 per barrel and $2.07 per Mcf.
- Q2 operating loss was $101.5 million; H1 operating loss was $203.5 million. The filing does not provide a clear standalone gross-margin figure.
- Q2 and H1 included full-cost ceiling impairment charges of $78.2 million and $158.6 million, respectively. These are non-cash charges. Derivatives produced Q2 realized gains of $2.5 million but unrealized losses of $26.6 million; H1 realized gains were $9.5 million and unrealized losses were $33.5 million.
Balance sheet, liquidity and capital
- At June 30, cash was $40.9 million and current assets were $94.6 million, versus current liabilities of $136.1 million. The company reported no borrowings under its revolving credit agreement; its borrowing base was $300 million, with approximately $0.6 million of letters of credit outstanding.
- Senior notes had $400 million principal outstanding, bearing 6.875% interest and due 2023; their balance-sheet carrying value was $391.8 million. Total shareholders’ equity was $422.5 million.
- H1 investing cash use was $166.0 million; financing provided $140.6 million, mainly from the March 2016 equity offering. The offering raised approximately $141.5 million net. H1 capital expenditures were approximately $198 million; the 2016 budget was approximately $325 million.
- Contractual obligations included $43.0 million of drilling-rig termination commitments, $4.2 million of non-operated well commitments, and $4.6 million remaining on the Rustler Breaks gas-plant construction contract. The company also disclosed long-term gathering and processing commitments.
Material changes and management outlook
- Oil and gas revenue fell 21% in Q2 and 25% in H1 year over year, primarily due to lower commodity prices. Production growth, particularly Delaware Basin gas production, partly offset the price decline. Delaware Basin production more than doubled year over year in Q2 to 14,525 BOE per day.
- H1 operating cash flow and Adjusted EBITDA declined substantially year over year. Management attributed the EBITDA decline principally to lower commodity prices. The Q2 shareholder net loss was smaller than in 2015, largely reflecting lower impairment and DD&A charges; the H1 shareholder net loss increased slightly.
- The May 2016 borrowing-base redetermination reduced the revolving facility’s borrowing base from $375 million to $300 million. Management expected to fund capital needs through the remainder of 2016 and into 2017 using cash, equity proceeds, operating cash flow and credit availability, while retaining discretion to adjust spending.
- Management reported three rigs operating in the Delaware Basin as of August 3, 2016, and highlighted improving drilling times and well costs. The Rustler Breaks processing plant was scheduled to enter service later in August 2016. Management reported approximately 50% of anticipated remaining-2016 oil production and 55% of anticipated natural gas production hedged as of August 3.
- Proved reserves reached 95.5 million BOE at June 30, up from 85.1 million at year-end 2015; approximately 41% were proved developed. Standardized Measure was $468.3 million and PV-10 was $473.2 million. Management said lower prices led to some proved undeveloped reserves being reclassified as contingent resources. These reserve-value measures are not estimates of fair market value.
Risks, contingencies and unusual items
- Results and liquidity are sensitive to volatile oil and gas prices, production performance, reserve estimates, access to capital and borrowing-base determinations. Management warned that lower prices or reduced drilling could affect production, reserves, cash flow and credit availability.
- The full-cost ceiling impairment depends on trailing average commodity prices and other reserve and cost assumptions. Management estimated that a specified lower-price scenario would have increased the ceiling impairment by a further $48.5 million, holding other factors constant.
- Open commodity collars had a net fair-value liability of $17.2 million at June 30. Collar price floors and ceilings limit both downside exposure and potential benefit from higher prices.
- The company had a full valuation allowance against deferred tax assets and recognized no income tax benefit in 2016 periods presented.
- Management considered the ordinary-course lawsuits unlikely to have a material adverse impact. It also disclosed potential deficiency fees under gas-processing agreements and other contractual and off-balance-sheet commitments.
Important facts for investors to verify
- Whether commodity prices, realized differentials and hedge settlements support operating cash flow and the planned capital program.
- How the $300 million borrowing base changes at subsequent redeterminations, and the company’s compliance with credit-agreement terms.
- Whether Delaware Basin well productivity, drilling costs and production growth meet management’s expectations, including after the processing plant begins operating.
- How future commodity prices and reserve revisions affect proved reserves, the full-cost ceiling and potential additional impairment charges.
- The timing and cash impact of drilling-rig, gathering, processing, transportation and other contractual commitments.
- Adjusted EBITDA is a non-GAAP measure; assess it alongside GAAP losses and operating cash flow.