Business Context and Reporting Period
Company: San Juan Basin Royalty Trust (the "Trust")
Reporting Period: Quarterly period ended June 30, 2004 (Form 10-Q)
Trustee: TexasBank
Outstanding Units: 46,608,796 (as of August 9, 2004)
Business Overview: The Trust holds a 75% net overriding royalty interest in oil and gas properties located in the San Juan Basin of northwestern New Mexico. The working interest owner is Burlington Resources Oil & Gas Company LP ("BROG"). The Trust is a passive entity that collects income from the royalty, pays expenses, and distributes the remainder to Unit Holders. Financial statements are prepared on a basis that differs from GAAP, customary for royalty trusts.
Key Financial Metrics
| Metric | Three Months Ended June 30, 2004 |
Three Months Ended June 30, 2003 |
Six Months Ended June 30, 2004 |
Six Months Ended June 30, 2003 |
|---|---|---|---|---|
| Royalty Income | $25,509,188 | $26,051,389 | $46,705,539 | $45,962,457 |
| Interest Income | $11,822 | $15,801 | $20,514 | $23,254 |
| General & Admin Expenses | $529,205 | $448,456 | $1,042,368 | $868,829 |
| Distributable Income | $24,991,805 | $25,618,734 | $45,683,685 | $45,116,882 |
| Distributable Income per Unit | $0.536204 | $0.549655 | $0.980152 | $0.967992 |
| Cash and Short-Term Investments | $9,024,529 (as of June 30, 2004) | |||
| Net Overriding Royalty Interest (Asset) | $28,338,910 (as of June 30, 2004) | |||
| Distributions Payable | $8,909,671 (as of June 30, 2004) |
Material Changes vs. Prior Period
- Quarterly Performance: Distributable income per unit decreased to $0.536204 in Q2 2004 from $0.549655 in Q2 2003. This decline was primarily driven by increased capital expenditures and production costs, despite higher oil prices.
- Semi-Annual Performance: Distributable income per unit increased to $0.980152 for the six months ended June 30, 2004, compared to $0.967992 in the prior year period. This increase was primarily due to higher gas prices during the first half of 2004.
- Production Costs: Capital expenditures attributable to the underlying properties were approximately $4.6 million for Q2 2004, compared to $2.9 million in Q2 2003. For the six months ended June 30, 2004, capital expenditures were approximately $14.0 million versus $9.4 million in the prior year.
- Commodity Prices: Average gas prices were $0.10 lower per Mcf in Q2 2004 compared to Q2 2003 ($4.38 vs $4.48). However, average oil prices increased by $3.81 per barrel ($31.72 vs $27.91). For the six-month period, average gas prices were higher ($4.27 vs $3.97) and oil prices were higher ($30.31 vs $26.53).
- Administrative Expenses: Increased in both the quarter and six-month periods, attributed to timing differences and an initiative to resolve joint interest audit issues with BROG.
Guidance, Outlook, and Risks
- Capital Expenditure Outlook: BROG estimates a 2004 capital expenditure budget of $18.5 million for the underlying properties, though actual expenditures could range from $15 million to $25 million depending on project mix and natural gas prices. Approximately $3.3 million had been spent as of June 30, 2004.
- Drilling Activity: BROG anticipates 441 projects in 2004, including 103 new wells operated by BROG (30 conventional, 73 coal seam) and 29 wells operated by third parties. The budget reflects a continued focus on the Fruitland Coal formation.
- Contractual Obligations: BROG has contracts to sell all gas volumes to Duke Energy and Marketing, L.L.C. (now ConocoPhillips) and PNM Gas Services. The contract with ConocoPhillips is set to terminate on March 31, 2005, and BROG is soliciting bids for a replacement.
- Tax Matters: The Trust is a grantor trust for federal income tax purposes. Unit Holders are entitled to claim depletion. The Section 29 tax credit for coal seam gas expired for sales after 2002, but cash-basis taxpayers may still claim credits for proceeds received in 2004 for fuel sold in 2002 or earlier.
- Legal and Contingencies: The Trust is not a party to any legal proceedings, but adverse outcomes in proceedings involving BROG could materially decrease royalty income. A settlement regarding gas imbalances resulted in a $243,968 revenue increase in July 2004. A subsequent event in July 2004 included an aggregate of $1,835,500 in royalty payments related to joint interest audit settlements and capital expenditure adjustments.
- Regulatory Risk: The Trust faces challenges complying with Sarbanes-Oxley Act governance requirements (e.g., audit committees) due to its passive trust structure, which lacks a board of directors or executive officers.
Investor Verification Checklist
- Capital Expenditure Impact: Verify the actual 2004 capital expenditure spend against the $15M-$25M range, as higher costs directly reduce distributable income.
- Gas Sales Contract Renewal: Monitor the status of the gas sales contract expiring March 31, 2005, and the terms of any new agreements with ConocoPhillips or other buyers.
- Production Volumes vs. Royalty Allocation: Note that royalty income is based on net profits (revenue minus costs), not gross production volumes; verify if cost increases are outpacing price increases.
- Subsequent Events: Review the July 2004 adjustments ($1.8M settlement and $1M capital expenditure adjustment) to understand their impact on Q3 2004 distributions.
- Tax Credit Eligibility: Confirm individual eligibility for Section 29 tax credits based on cash-basis accounting and prior-year production sales.