Comstock Resources, Inc. — FY 2016 Form 10-K
Business context and reporting period. Comstock is a U.S. oil and natural gas exploration and production company, focused primarily in Texas and Louisiana. This annual report covers the year ended December 31, 2016; it is not a standalone fourth-quarter filing. Operations shifted toward Haynesville and Bossier shale natural gas development as oil prices remained weak. At year-end, natural gas represented 95% of proved reserves.
Key financial and operating metrics
| Metric | FY 2016 / year-end | Comparable period |
|---|---|---|
| Oil and gas sales | $175.7 million | $252.4 million in 2015; down 30% |
| Net loss | $135.1 million; $11.52 per share | $1.047 billion loss; $113.53 per share in 2015 |
| Operating loss | $183.8 million | $1.166 billion in 2015 |
| Operating cash flow | $(23.7) million | $30.1 million in 2015 |
| Capital expenditures | $59.6 million | $243.2 million in 2015 |
| Cash and cash equivalents | $65.9 million | $134.0 million at year-end 2015 |
| Debt | $1.045 billion carrying value; approximately $1.2 billion principal amount disclosed | $1.249 billion carrying value at year-end 2015 |
| Proved reserves | 916.1 Bcfe; standardized measure $429.3 million | Standardized measure $372.1 million in 2015 |
Production totaled 62.0 Bcfe, down from 66.2 Bcfe in 2015. Natural gas production increased 13% to 53.7 Bcf, while oil production fell 55% to 1.388 million barrels. Average realized prices declined to $2.28/Mcf for gas from $2.30 and $38.24/barrel for oil from $46.19; the combined realized price fell to $2.83/Mcfe from $3.81. Lease operating costs improved to $0.76/Mcfe from $0.97; DD&A was $141.5 million, or $2.26/Mcfe.
Current assets were $90.2 million and current liabilities $91.7 million. The company had no borrowings under its $50 million revolving credit facility and reported compliance with its financial covenants. Cash interest paid was $105.4 million; reported interest expense was $128.7 million. The filing does not provide a conventional operating profit margin; the reported operating loss was $183.8 million.
Material changes versus prior period
- Sales fell $76.7 million, chiefly because oil sales declined 63%; higher gas volumes partially offset weaker prices and reduced oil production.
- The net loss improved substantially from 2015, when $801.3 million of proved-property impairments and a $112.1 million loss on asset sales drove unusually large charges. In 2016, proved-property impairments were $27.1 million, but exploration expense included $84.1 million of unevaluated leasehold impairments.
- Debt carrying value declined by about $204.8 million. A September 2016 exchange covering approximately 98% of outstanding senior notes extended or restructured obligations, introduced convertible PIK notes, and generated a reported $189.1 million net gain on debt extinguishment. The exchange reduced near-term cash interest requirements but did not eliminate substantial leverage.
- The company sold South Texas natural gas properties in December for $25.8 million net proceeds, recognizing a $13.4 million sale loss after a $20.8 million impairment earlier in the year.
- Natural gas proved undeveloped reserves rose 292.5 Bcf to 550.9 Bcf, primarily from Haynesville/Bossier additions and performance revisions. Approximately 60% of total proved reserves were undeveloped; estimated future development costs for these reserves were $427.3 million.
Guidance, risks and unusual items
- Management planned up to $167.5 million of 2017 development and exploration spending, including 22 horizontal Haynesville/Bossier gas wells and completion of wells drilled in 2016. Spending and well count were discretionary and dependent on commodity prices. Management said cash on hand, operating cash flow and available borrowing capacity were expected to fund planned 2017 activity, while warning that low prices could require reduced drilling or additional financing.
- Management expected oil production to keep declining until South Texas drilling resumes; gas production could also decline without new wells. It expected to drill 22 additional Haynesville/Bossier wells in 2017. A joint development venture and a planned third operated rig were also described.
- At year-end, swaps covered 23.4 Bcf of expected 2017 gas production at a fixed NYMEX price of $3.37/Mcf; by February 24, 2017, coverage had increased to 25.9 Bcf at $3.38/Mcf. The year-end swaps had a $6.0 million fair-value liability.
- Liquidity and solvency risks include weak commodity prices, negative 2016 operating cash flow, high debt service, secured liens on substantially all assets, restrictive covenants, and limited access to new capital. The convertible notes could materially dilute shareholders: the filing estimates conversion of outstanding notes at year-end could represent 72% of then-outstanding shares. Conversion could also restrict use of tax loss carryforwards.
- Other key risks include reserve-estimation uncertainty, further impairment charges, lease expirations, dependence on third-party gathering and transportation, environmental and hydraulic-fracturing regulation, operational hazards, and commodity-price and counterparty risks. The company reported no legal proceedings it believed would materially adversely affect its financial condition or results.
- The quarterly data show a $4.9 million net profit in Q2 2016 amid losses in the other three quarters; debt-extinguishment gains contributed materially to the year’s results. Dividends remained suspended. Management assessed the company as a going concern with adequate liquidity for at least 12 months from issuance, while acknowledging uncertainty if low prices persisted.
Important facts for investors to verify
- Review debt documents and maturity, cash-interest and PIK terms, including the $75 million toggle feature, covenants, collateral priorities and remaining revolver availability.
- Assess the actual dilution potential from convertible notes and warrants, and whether ownership changes could impair federal or state tax-loss carryforwards.
- Compare the planned 2017 capital program and $427.3 million of estimated PUD development costs with realized cash flow, production results and commodity prices.
- Validate reserve assumptions and the standardized measure using the stated year-end pricing convention; these estimates are not current market value and are sensitive to prices, costs and drilling performance.
- Track 2017 hedge volumes, realized prices, transportation commitments and any additional impairment or financing needs.
- Note that the independent auditor issued an unqualified opinion on the financial statements and internal controls; management also reported effective disclosure controls and internal control over financial reporting.