We are a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas, onshore in the United States. We acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and modern technology to increase production, ultimate recoveries, or both.
We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders, including approximately 21% beneficially owned by all of our employees and directors.
Our strategy is intended to generate scalable, low unit cost, development and re-development opportunities that minimize or eliminate exploration risks. These opportunities involve the application of modern technology, our own proprietary technology and our specific expertise in overlooked areas of the United States, where we may or may not choose to be the operator.
The assets we exploit currently fit into three types of project opportunities:
- Enhanced Oil Recovery (EOR),
- Bypassed Primary Resources, and
- Unconventional Development, especially utilizing our staff expertise in horizontal drilling.
Our active projects in these categories are:
Enhanced Oil Recovery
Delhi Field — Louisiana
Our mineral interests in the Delhi Holt Bryant Unit in the Delhi Field, located in Northeast Louisiana, are currently our most significant assets. The Unit has had a prolific production history totaling approximately 190 million barrels of oil through primary and secondary recovery operations since its discovery in the mid-1940s. At the time of our $2.8 million purchase in 2003, the Unit had minimal production.
The Unit is currently being redeveloped as an EOR project utilizing CO2 flood technology following our farm-out to a subsidiary of Denbury Resources, Inc. in mid-2006. Estimates of gross proved and probable reserves by our independent reservoir engineer as of June 30, 2012 total 66 million barrels of gross additional recovery from the flooding operation, of which approximately 16.79 million barrels of oil are net to our interests.
We own two types of interests in the Unit:
- 7.4% of overriding and mineral royalty interests that are in effect throughout the life of the project, free of all operating and capital cost burdens.
- A 23.9% reversionary working interest with an associated 19.1% net revenue interest. The working interest reverts to us when the Operator has generated $200 million of net revenue from the 100% working interest less direct operating expenses and the cost of purchased CO2. Upon reversion of the deemed payout, regardless of the Operator’s actual capital expenditures, we begin bearing 23.9% of all future operating and capital expense and our net revenue interest increases by an incremental 19.1% (to an aggregate 26.5%). Our current independent reserves report dated June 30, 2012 projects the deemed payout to occur in late calendar year 2013.
Our independent reservoir engineers, DeGolyer & MacNaughton (“D&M”), assigned the following net reserves to our interests at Delhi as of June 30, 2012:
- 11,011,570 BBLS of proved oil reserves, with a PV-10 of $409.1 million* (volumes are 68% developed)
- 5,780,906 BBLS of probable oil reserves, with a PV-10 of $102.8 million* (volumes are 46% developed)
* PV-10 of proved reserves is a non-GAAP measure, reconciled to the Standardized Measure at “Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues” under Item 2. Properties of this Form 10-K. Probable reserves are not recognized by GAAP, and therefore the PV-10 of probable reserves cannot be reconciled to a GAAP measure. Please Cautionary Statement herein.
The Operator has planned up to six phases for the installation of the CO2 flood. We refer to them as Phases I thru VI.
Phase I began CO2 injection in November 2009. First oil production response occurred in March 2010, about three to four months earlier than expected. Implementation of Phase II, which is more than double the size of Phase I, commenced with incremental CO2 injection at the end of December 2010. First oil production response from Phase II occurred during March 2011, also three or more months ahead of expectation.
Phase III was installed during calendar 2011. The operator elected to expand Phase III twice during calendar 2011.
Phase IV was substantially installed during the first six months of calendar 2012.
The operator has announced that 2013 capital expenditures of approximately $40 million will be focused on adding additional reservoirs in the western end of the field, where significant development and seismic surveys have identified areas of more oil saturation than was expected. We expect that the remaining phases of the project will be installed over the next few years. We further expect that four smaller reservoirs within the Unit and in similar formations with similar production history will be developed in the future as an additional phase in the EOR project later this decade.
During fiscal 2012, Delhi’s Louisiana Light Sweet (“LLS”) crude oil sales realized $111.29 per BBL average price, a 19% price premium over the $93.54 per BBL sales price we received from our Texas production. A positive market differential has continued through the first quarter of fiscal 2013.
Bypassed Primary Resource Projects
Following the closing of our Delhi Farmout in June 2006, we began the process of identifying new conventional development and/or redevelopment projects targeting primary petroleum resources previously bypassed by industry in historically productive formations, generally due to inadequate technology or commodity prices. In selecting our candidates:
- We leverage our staff’s extensive experience, gained over many years while employed at various large independent oil and gas companies in the pioneering of horizontal drilling practices;
- We seek projects that can effectively and efficiently redeploy projected net cash flows from our Delhi Field “annuity”;
- We seek projects that can generate multiple, scalable drilling opportunities with long term production growth; and
- We seek exposure to both crude oil and natural gas opportunities, with an emphasis on crude oil in recent years.
Mississippi Lime – Kay County, North Central Oklahoma
In 2012, we entered into a joint venture with Orion Exploration, a private company based in Tulsa, OK. The joint venture is operated by Orion for the horizontal development of the Mississippian Lime reservoir in Kay County, Oklahoma, within this rapidly growing play in north central Oklahoma and western Kansas. Our leasehold position is located in the eastern, oily side of the play. With the objective reservoir less than 4,000 feet in depth, the cost of drilling, fracturing and completing a horizontal well with 4,000 feet of lateral length is approximately $3 million. The joint venture has been gradually adding to the initial 11,700 net acre position. We hold a 45% share of the interest held by the joint venture. To date, the operator has drilled one gross salt water disposal well and reached total depth on our first two horizontally drilled wells in the Mississippian Lime formation, including lateral lengths of approximately 4,100 feet in the Sneath #24-1 and 4,800 feet in Hendrickson #1-1. Both wells were hydraulically fractured and, as of early December 2012, were in the process of dewatering to reduce reservoir pressure which is expected to initiate oil and natural gas production.
As of June 30, 2012, our independent reservoir engineer, Pinnacle Energy Services, assigned us net probable reserves of 6,423,000 BOE with PV-10 of $69 million* associated with our net interest in 114 gross drilling locations on 213 acre spacing.
Artificial Lift Technology (GARP®)
Our artificial lift technology trademarked as GARP® (Gas Assisted Rod Pump) was developed by one of our employees. Its design is intended to extend the life of horizontal wells with gas, oil or associated water production with the expectation of recovering an additional 10-30% of cumulative recovery at a cost less than $10 per BOE. Letters patent for our GARP® technology were issued on August 30, 2011.
Prior to patent issuance, our GARP® technology was tested on certain marginal producers we own and operate in the Giddings Field. The tests were successful in demonstrating that the process works; however, these candidates were unable to prove commercial application due to their low primary recoveries as producers. We believe that the best candidates for GARP® are in the top two quartiles of producers based on recovery.
Subsequent to receiving our patent, we entered into demonstration JV projects with two different industry operators during fiscal 2012 to prove commercial application. Based on our positive results to date that added reserves and extended the well lives, we are currently in discussions to expand GARP® installations with both operators.
With continued success and industry acceptance, we believe GARP® could be applicable to a large set of late stage horizontal producing wells worldwide.
Giddings Field — Central Texas
We began leasing activities in the Giddings Field in December 2006 and, as of June 30, 2012, held 5,005 net developed acres and approximately 3,145 net acres as undeveloped and associated with proved drilling locations. In late calendar 2007, we initiated a redevelopment drilling program in the Giddings Field targeting the Austin Chalk, Georgetown and Buda formations. As of June 30, 2012, we owned thirteen producing wells, eleven of which we drilled and two of which we restored to production through work-overs. Three of the producing wells were drilled during fiscal 2011 as part of a joint venture to which we contributed the proved drilling locations. One of the three joint venture wells was deemed noncommercial due to water production in the target zone and was recompleted as a marginal producing well in another reservoir.
During Fiscal 2012, we also farmed out our Woodbine rights in approximately 900 net acres in exchange for cash and an ORRI of approximately 5%. Furthermore, on approximately 258 net acres of that total, we retained a 15% back-in working interest that reverts to us after a simple payout. We have not yet assigned any reserves to these interests, pending drilling results by the operator.
Total net proved reserves assigned to our properties in the Giddings Field by our independent reservoir engineer, W.D. Von Gonten & Associates, are 2,324 MBOE as of June 30, 2012. The total is a decrease of 399 MBOE from June 30, 2011 due to Giddings production during the year of 69 MBOE, negative revisions totaling 369 MBOE and additions of 40 MBOE. Our total investment of approximately $29 million to date has generated $13.4 million of cash flows from approximately 420 MBOE of total net production and proved PV-10 at June 30, 2012 of $35.6 million. See “Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues” under Item 2. Properties of this Form 10-K for a reconciliation of PV-10 to the Standardized Measure.
Due to the relatively high gas content of these reserves and drilling locations combined with low natural gas price and our expectation that natural gas prices will not significantly increase in the near term, we have elected to monetize our assets in the Giddings Field, excluding our GARP® installed wells and our Woodbine royalty interests. To date, we have reached tentative agreements to dispose of most of the targeted assets, which will provide both capital and staff for expanding our core projects.
Lopez Field - South Texas
We acquired leases in the Lopez Field in South Texas with the intent of testing the concept of redeveloping old oil fields utilizing high flow rate production. If successful, we intended to expand the concept to similar fields in the area.
We currently own leases on approximately 891.6 net acres in the Lopez Field. As of June 30, 2012, our independent reservoir engineer, W.D. Von Gonten & Associates, recognized one proved producing well and six gross and net proved undeveloped well locations with 106 MBO of proved reserves. The engineer further assigned 475 MBO of probable reserves to 32 gross and net locations. During fiscal 2012, we drilled two salt water injection wells and two oil producer wells. The first producer drilled exceeded our expectations with gross production averaging 16 BO per day for the quarter ended June 30, 2012. Based on the electric logs of the second oil producer and associated salt water injection well, we elected to swap well designations and applied for the necessary regulatory permits to convert the injection well to a producing well and the producing well to an injection well.