PrimeEnergy Corporation — Form 10-Q Summary
Reporting period: Quarter and nine months ended September 30, 2015. The interim financial statements are unaudited. The filing identifies the registrant as PrimeEnergy Corporation; the request metadata names PrimeEnergy Resources Corp.
Business context
PrimeEnergy is an independent U.S. oil and natural gas producer, with properties primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana, and also provides well-servicing operations. It operates affiliated partnerships and trusts and uses commodity derivatives to manage price exposure.
Financial performance and position
Amounts below are in millions of dollars except per-share data, production, prices and ratios.
- Third-quarter results: Revenue was $21.50 million, down from $40.74 million in Q3 2014. Operating loss was $0.27 million versus operating income of $17.93 million; net loss attributable to PrimeEnergy was $0.66 million, or $0.28 per share, compared with net income of $10.80 million, or $4.58 per share.
- Nine-month results: Revenue was $63.80 million versus $100.46 million. Operating loss was $1.48 million versus operating income of $30.47 million. Net loss attributable to PrimeEnergy was $2.58 million, or $1.11 per share, compared with net income of $16.84 million, or $7.11 per share.
- Revenue components, nine months: Oil and gas sales fell to $37.16 million from $73.64 million. Realized derivative gains were $14.94 million versus a $2.57 million loss; unrealized derivative losses were $11.25 million versus unrealized gains of $2.36 million. Field-service income declined to $16.50 million from $19.83 million, and administrative overhead fees to $6.40 million from $7.06 million.
- Production and realized prices, nine months: Oil production decreased 2% to 564,000 barrels, while gas production increased 2% to 3.605 million Mcf. Excluding derivatives, average wellhead oil price fell 49% to $47.91 per barrel and gas price fell 50% to $2.81 per Mcf. Including derivatives but excluding early settlements, reported average prices were $70.73 per barrel and $3.38 per Mcf.
- Expenses and margins: Nine-month lease operating expense decreased 18% to $27.04 million; field-service expense fell 14% to $13.55 million; and general and administrative expense fell 22% to $9.27 million. The filing does not present a consolidated operating-margin measure. Lower commodity prices were the principal driver of the earnings decline.
- Cash flow: Operating cash flow was $13.84 million for the first nine months, down from $44.29 million. Capital expenditures, including exploration, were $11.21 million; investing cash outflow was $9.30 million. Financing cash outflow was $8.30 million, and cash decreased $3.76 million to $5.45 million. Restricted cash was an additional $3.63 million.
- Debt and liquidity: Total bank debt on the balance sheet was approximately $94.89 million, including $3.03 million current. The revolving facility had a $112.5 million borrowing base, $84.5 million drawn and $28 million available at period-end; stated facility size was $250 million. Equipment loans totaled approximately $10.3 million. The company reported covenant compliance and expected to remain compliant over the next 12 months.
- Balance sheet: Total assets were $241.61 million, down from $264.90 million at year-end 2014; total liabilities were $167.99 million and equity was $73.61 million. Current assets were $27.43 million and current liabilities $24.72 million.
Material changes and management commentary
- Management attributed the sharp year-over-year earnings decline primarily to lower oil and gas prices. Q3 oil and gas sales fell 55%; nine-month sales fell 49%. Production was generally flat overall, with new wells offsetting natural decline; temporary mechanical repairs reduced Q3 oil production.
- Management reported cost reductions in lease operations and G&A, including lower labor, support, vendor, salary and bonus costs. Field-service revenue and expense also fell amid slightly reduced utilization and lower customer rates.
- During 2015, the company continued drilling in West Texas and the Mid-Continent and shifted emphasis from vertical wells toward horizontal development. Through November 9, it had participated in six gross (2.6 net) new wells, all producing, including two Apache joint-venture horizontal wells.
- Management expected approximately $15 million of 2015 drilling expenditure, primarily in West Texas. The current West Texas phase contemplated up to four wells at an estimated net cost of approximately $10 million. A potential broader Apache program was described as approximately 60 horizontal wells over 36–48 months, with total program cost of approximately $470 million and an estimated company share of approximately $150 million; timing and well count may change with commodity-market conditions.
- Commodity derivatives reduced some exposure to price declines but limit participation in certain price increases and create counterparty risk. Mark-to-market accounting caused revenue volatility. Commodity derivative fair-value assets declined to $5.65 million from $16.90 million at December 31, 2014; interest-rate derivative liability was $0.08 million.
Outlook, risks and contingencies
No formal earnings or production guidance is provided. Management said capital spending is largely discretionary and depends on commodity conditions, prospects, service-market conditions and available opportunities. The borrowing base is redetermined semi-annually and may be reduced based on reserve valuations, potentially reducing liquidity or requiring repayment. The credit facility is secured by substantially all oil and gas properties and includes financial and operational covenants.
Identified risks include oil and gas price volatility, drilling cost overruns and technical difficulties, operational risks, uncertainty in seismic interpretation and reserve estimates, and the ability to replace and grow reserves. Asset-retirement estimates depend on assumptions about plugging costs, inflation, well lives and discount rates. Management did not expect environmental matters or ordinary-course legal actions to materially adversely affect the company; it reported no legal proceedings in Part II. The company also has contingent responsibility for affiliated partnership obligations if partnership assets are insufficient, though it believed partnership reserves were adequate.
The company repurchased 25,330 shares for $1.66 million during the nine months and spent $1.76 million under stock and partnership-interest repurchase programs. Management reported effective disclosure controls and no material change in internal controls during the quarter.
Key investor verification points
- Confirm the effect of continued low commodity prices, derivative coverage and derivative valuation on future realized prices, cash flow and reported earnings.
- Track the semi-annual borrowing-base redetermination, covenant headroom, outstanding debt and the $28 million of stated revolver availability.
- Assess the funding, timing and expected returns of the planned drilling program, particularly the company’s estimated share of the potential Apache development.
- Reconcile the filing’s derivative discussion: the financial statements report nine-month realized derivative gains of $14.94 million, while portions of the MD&A describe settlement amounts as losses despite presenting positive amounts.
- Review reserve estimates, production trends, asset-retirement assumptions and any changes in partnership obligations or liquidity needs.