A core of producing working interests, operated and non-operated, bought below their appraised value. Development on proven acreage, selected royalty and mineral purchases, and a set of rules we do not bend.
Interest types
The five contracts behind a producing well
Each interest type is a different contract with the same well. What differs is who pays the costs and how much of the upside you keep. Working interests are where most of our capital goes. Royalties come next, and minerals are the exception.
Operated WI
Operated working interest: we are the operator — we run the wells, control the costs, and can drill new ones.
Cost exposure
Our share of drilling, operating and plugging costs — and we run the field
Upside
We control costs, timing, workovers and new drilling on locations we own
Core holding
Non-op WI
Non-operated working interest: we pay our share of drilling and operating costs and receive our share of revenue. Another company operates.
Cost exposure
Our share of drilling, operating and plugging costs
Upside
Bought at a discount to appraised value; the operator drives the pace
Core holding
Royalty
A share of production revenue carved out of the mineral estate. No costs, no operations.
Cost exposure
None
Upside
Every well on the lease while it produces
Bought selectively
ORRI
Overriding royalty: a share of revenue carved out of the operator's lease. Cost-free, but ends when the lease ends.
Cost exposure
None
Upside
Cost-free; ends when the lease ends, so priced accordingly
Bought selectively
Mineral
Ownership of the minerals under the land. Receives a royalty on everything produced, forever, with no cost exposure.
Cost exposure
None — the operator pays everything
Upside
Every future well drilled on the acreage
The exception
Guardrails
Working interests carry costs, so every purchase is priced with operating expense, capital and plugging in the forecast. Bids are held to ceilings the board sets, title must clear before a closing, and evaluation wells are kept to a capped share of capital.
Oil and gas
Both commodities, on purpose
Oil and natural gas prices move on different cycles. Owning both is intended to smooth cash flow across those cycles.
Oil
Priced by the world
Crude is sold against a global benchmark, so its price follows world
supply and demand. A barrel in Texas and a barrel in the North Sea move
together.
Gas
Priced by the pipeline
Natural gas is sold into regional pipelines, so its price follows local
supply, storage and the weather. It can be strong in a year when oil is
weak, and the reverse.
Underwriting
How we decide what to pay
Price decides the outcome. The screening tools find and rank; people verify title and sign.
Appraised value, not hope. Every producing purchase is priced against an independent engineer's appraisal of proved developed reserves on the company's own price deck, with a stress case.
Decline curves are fitted, not assumed. Every well's decline is fitted to reported monthly production; type curves are fallbacks only.
Operator quality moves the price. A well run by a disciplined operator with a strong balance sheet is worth more than the same rock under a weak one.
Title is a gate, not a note. Interests with unverified chain of title go to review, never straight to a bid. Division orders must be in pay before a purchase is complete.
Working interests carry the plugging bill. Every purchase is priced with our share of future plugging and abandonment in the forecast.
Operated working interest
Wells we run
Operating is where a hands-on company can add value that the market does not price. Where the company holds the acreage, Sourcerock Operations, a separate company under common control, operates the wells for the company's account at cost; the company bears the operator's liabilities.
LOE
We pay to operate
Pumpers, electricity, chemicals, water hauling, repairs. Lease operating
expense is the first thing deducted from an operated well's revenue, and
the first thing we can control.
CAPEX
We decide what to spend
Workovers and recompletions on a mature well are often the
best-returning dollars in oil and gas. As operator we choose which to do
and when.
ARO
We own the plugging liability
When a well reaches its economic limit it must be plugged. We forecast
that cost per well, fund it, and report it.
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Why it can add value
Operated fields come with drillable locations, gathering and
infrastructure we control. Buying proved production and adding value
through operations is the oldest trade in the industry.
Where the capital goes
Buy production. Develop proven acreage. Test carefully.
Three uses of capital, in order of size.
1
Production acquisitions
The largest share. We buy working interests in wells that already
produce, and the undeveloped leases that come with them, through our own
industry relationships and through established marketing platforms.
2
Development drilling
Lower-risk wells on acreage where offsetting production has already
proved the reservoir. We drill on leases we bought or leased ourselves,
or take a share in a well another operator drills.
3
Evaluation wells
A capped share of capital tests locations that are not yet proved.
These wells carry the most risk and can fail entirely, which is why the
allocation is capped.
Nothing on this website is an offer to sell, or a solicitation of an offer to buy, any security. Oil and gas interests are wasting assets, drilling can fail, and an operator bears liabilities a passive owner does not. Any offering of the company's securities is made only by its own offering document to eligible persons.
Investor information
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