Empyrean Regulatory News (EME)

Empyrean Energy PLC / Index: AIM / Epic: EME / Sector: Oil & Gas

8 September 2015

Empyrean Energy PLC ('Empyrean' or 'the Company')

Final Results

Empyrean Energy, the profitable US onshore oil, gas and condensate exploration, development and production company with assets in Texas and California, is pleased to announce its final results for the year ended 31 March 2015.

Highlights

· Record revenue and production driven by further improvements at flagship Marathon Oil operated Sugarloaf AMI project (EME 3% working interest) (the "Project" or the "Sugarloaf AMI"), despite the fall in oil prices during the year

o 15% increase in revenues for the 12 months to 31 March 2015 to US$16.010m (2014: US$13.884m)

o 2% decrease in net profit before tax for the 12 months to 31 March 2015 to US$5.122m (2014: US$5.221m)

o 9% increase in production net to Empyrean (after royalties) for the 12 months to 31 March 2015 to 366,469 barrels of oil equivalent (2014: 335,305 barrels of oil equivalent)

· Substantial increase in activity at Sugarloaf with 130 wells spudded (2014: 43 wells) and 84 wells brought into production during the period (2014: 39 wells)

o Stack and Frac pilot programme commenced with early production results encouraging

o Downward trend in drilling and completion costs continues

· Re-negotiated finance facility with Macquarie Bank

o US$11m drawn down 1 April 2015

· Updated reserves report to 31 December 2014 on Sugarloaf AMI released in June 2015 showed:

o 63% increase in 1P Reserves to 5.78 Mmboe

o 94% increase in 2P Reserves to 12.64 Mmboe

o 134% increase in 3P Reserves to 20.91 Mmboe

o 2C Contingent Resource of 2.85 Mmboe

o 49% increase in 2P + 2C to 15.49 Mmboe

· Significant potential from the Upper Eagle Ford formation

o Early production from the Upper Eagle Ford indicates that this zone is in a similar appraisal phase to that of the Austin Chalk 18 months ago

o Further development of the Upper Eagle Ford could add another 500 wells to the overall field development

Empyrean CEO Tom Kelly said, "I believe we have made significant progress across many fronts in spite of one of the most challenging periods for all oil producers globally. We have increased revenues, been able to re-finance our participation in the flagship Sugarloaf AMI and are positioned to capitalise on the significant growth in reserves that has evolved from further successful delineation and appraisal of the Austin Chalk formation, which is being co-developed with the Eagle Ford Shale. From a value perspective, the indicated NPV10 of our 2P reserves has shown a solid increase from December 2013 to December 2014 despite the fall in oil prices and, importantly, we also have significant growth upside to unlock from further appraisal of the Upper Eagle Ford formation. Finally, we remain focussed on delivering a favourable outcome for shareholders from our portfolio and, in particular, the continued involvement in the Sugarloaf AMI."

Chairman's Statement

I am pleased to report that our tenth year of operations has seen us achieve further revenue growth despite challenging market conditions. Empyrean succeeded in sustaining last year's very strong growth in production, and as a result has reported a 15% revenue growth, notwithstanding the unprecedented fall in global oil prices in the second half of 2014.

The principal activity in the past year has remained the development of the Sugarkane Field, in particular the Sugarloaf AMI in which we have a 3% working interest in approximately 24,300 gross acres centrally positioned in the liquids rich sweet-spot within the field. The Lower Eagle Ford Shale continues to be the main production source, with the overlying Austin Chalk providing an increasingly important addition along with the emergence of the Upper Eagle Ford as a co-development appraisal opportunity.

The operator of this field, Marathon Oil, has continued to demonstrate excellent drilling expertise, and on-going technical initiatives have reduced total well costs significantly. Marathon has maintained its rapid development of this prolific field, demonstrating its confidence in the quality of this prime asset by spudding 130 wells between April 2014 and March 2015. This resulted in our interests at financial year-end in a total of 205 wells, producing gas and condensate, including 21 producing from the Austin Chalk.

As forecast by the Board of Directors, further appraisal, delineation and drilling of the Austin Chalk formation has resulted in a significant uplift in reserves during the year. DeGolyer & MacNaughton produced an update to the Reserves and Resources of Sugarloaf to December 2014, which has bolstered our confidence in the Project's excellent long term potential. The proven reserves increased 63% to 5.78 million barrels of oil equivalent and proven plus probable increasing by 94% to 12.64 million barrels of oil equivalent, with the majority of the increase attributable to the Austin Chalk's further delineation and shifting out of contingent Resources into Reserves.

Drilling activity levels during the period were high, with 130 wells spudded and 84 wells brought onto production. Revenue in the year to March 2015 was US$16.010m, 15% above the previous year as a result of this rapid development. Gross profit, at US$8.820m is 5% higher than last year, while net profit before tax at US$5.122m is 2% lower.

During the year, we carried out an in-depth Strategic Review, together with our advisers, Macquarie Capital and Cenkos Securities Plc. This Review, announced in July 2014 and completed in February 2015, concluded that, as the prevailing market conditions showed substantial uncertainty following the widely reported fall of over 50% in the benchmark price of West Texas Intermediate crude oil, there had been no proposals that the Board could recommend to shareholders. With this in mind, the Board decided that shareholder value would best be maintained and enhanced by its continuing to participate in the development of its primary asset, the Sugarloaf AMI, and by securing the finance necessary to do so.

As part of an amortisation and impairment review, Empyrean has chosen to impair those wells that, in its view, are unlikely to produce again or have a diminished production profile based on recent data. This includes the Block A-4 well and a partial impairment of the Block A-1 and A-5 wells at the Sugarloaf Block A project. There has also been a partial impairment of the Cartwright well at the Riverbend project. Empyrean remains committed to the ongoing process of renegotiating leases at the Eagle Oil Pool Development project in California. The Company is focussed, for the time being, on its main primary production asset at the Sugarloaf AMI and will endeavor to maximise any exploration potential from its remaining assets, in particular, the Eagle Oil Pool Development project in California.

Furthermore, with strong and steady production from Sugarloaf (net 1,196 boe/d for Q2 2015), increased revenues and significant upside from the Sugarloaf project in terms of additional formations and multiple optimisation initiatives, we remain optimistic. I would like to thank my fellow Board members, management team and shareholders for their support and look forward to the year ahead.

Patrick Cross

Non-Executive Chairman

6 September 2015

Operational Report

Development of the Sugarloaf AMI remained the focus of Empyrean's operational activities throughout the period. The project is located onshore Texas in Karnes County where Empyrean holds a 3% working interest in approximately 24,300 acres. The primary objective in the development drilling programme is the Cretaceous Eagle Ford Shale, an unconventional play rich in gas condensate. Marathon Oil Corporation ("Marathon" NYSE: MRO), is the third operator since Empyrean became involved in 2006.

In the adjacent Block A, ConocoPhillips is operator of the block in which Empyrean holds a 7.5% working interest in four producing wells. Empyrean holds a lesser interest in another six recently drilled wells, three of which recently commenced production in April 2015.

The Riverbend Project onshore Texas is the third area of interest. After several unsuccessful attempts to produce economic quantities of gas and condensate from two wells targeting the Austin Chalk, Empyrean agreed with the newly appointed operator, Krescent Energy Partners II LLP (KEP 11), to re-enter Cartwright No1 and test the shallower Wilcox Formation. The operation was successful and the well commenced the production of gas and minor condensate in May 2013. However, since October 2014 the production has been suspended.

The fourth Empyrean project located onshore California in the San Joaquin Basin is the Eagle Oil Pool Development Project. Empyrean has an increased working interest of 58.084 % and the operator remains Strata-X Energy (TSX.V:SXE). There have been no field operations carried out on the project during the past 12 months.

Sugarloaf AMI (3% WI)

The Eagle Ford Shale play remains the primary target in the Sugarloaf AMI. It is termed "unconventional" because shale has traditionally been classified as the caprock which impedes vertical hydrocarbon migration. It enables hydrocarbon entrapment in the so-called "conventional" reservoir (usually, sandstone or limestone). Mechanically induced fracturation, termed "fraccing" in the oil industry, creates effective permeability transforming the shale from being a cap rock in the "conventional" model to a hydrocarbon-bearing, fractured reservoir in the "unconventional" sense.

The Eagle Ford Shale is high in Total Organic Content (TOC). In the area of the Sugarkane Field it has been subjected to the time duration and temperature constraints necessary for in situ hydrocarbons generation. As well as being the hydrocarbon source, it is also the reservoir. It may also be the source of the hydrocarbons which have migrated vertically over time into the overlying Austin Chalk.

Fractured shale reservoirs are invariably exploited by utilizing the horizontal drilling technique. This enables exposure of larger volumes of the microfractured shale reservoir to the fraccing process. In the AMI area the horizontal distances range between 4,000 ft- 7,900 ft. The measured total depth varies between 15,325 ft and 19,800 ft (St Germaine Imperial 14H), depending on location and target.

The first well to produce in the Sugarloaf AMI was Kennedy 1H in 2010. It was actually spudded in September 2007 and then subjected to a workover operation by the then operator Hilcorp. At that time the lithostratigraphy of the area was not well-defined. In fact the producing formation was thought to be the Austin Chalk and was considered to consist of three identifiable "Upper" ,"Middle" and "Lower" divisions. With the increase in drilling in the area came a better understanding of the reservoir facies and their components. The lithostratigraphic understanding evolved as did the nomenclature. Today the operator identifies four distinct vertical units separated by three regional barriers. The Austin Chalk, with an average thickness of 100 ft, overlies the Upper Eagle Ford Shale (average thickness 45 ft). The two formations are separated by several layers of volcanic ash which can act as effective permeability barriers. The Upper Eagle Ford Shale overlies the Lower Eagle Ford Shale (average thickness 135 ft) which is divided into an upper and lower member. These two members are separated by a tight lime band which can also act as an effective, impermeable barrier to vertical hydrocarbon migration.

This then is the lithostratigraphic framework at present being employed. It forms the basis on which wells involved in the recently introduced "Stack and Frac" operations are located. This operation is currently being tested by Marathon and is designed to optimise co-development of multiple horizons drilled from the one pad. It can involve the drilling of up to five wells per stack. The first " Stack and Frac" pilot commenced in September 2014 with the drilling of the Franke Johnson wells (4H, 5H, 6H AC1H and AC2H) which targeted the Austin Chalk, and both members of the Lower Eagle Ford Shale. Production commenced on the 4 February 2015 from all five wells. The March 2015 well head production figures gave similar quantities of 15-18,000 barrels of condensate and 50-67,000 msc.ft of gas from both the Austin Chalk and Eagle Ford Shale accumulations. It is too early to draw conclusions (180 days production period, at least is required) but initial rates are most encouraging.

Another two "Stack and Frac" pilots commenced in late December 2014 and early February 2015. Those spudded in late December include the five St Christoval Ranch wells (G 10H, G AC 5H, G 309H, G 511H and G 508H). All wells have been production cased and are awaiting frac operations. The wells G511H and G 508 H are of particular interest as they have been designed to intercept the Upper Eagle Ford Shale which to date has not been a primary target but has the potential to be a major contributor to increased proven Reserves.

The third pilot involves the Kowalik wells (6H, 307H, G 511H, AC 3H and AC 4H). All five wells have been production cased and await fraccing operations which will perforate the Austin Chalk and lower and upper Lower Eagle Ford Shale members.

The accelerated drilling programme has not abated. During the 2014 calendar year Marathon spudded 108 wells (of which two were plugged and abandoned). 26 of these wells targeted the Austin Chalk. During the period April 2014 to March 2015, 130 wells were spudded and another 20 wells have been spudded to the 15 May 2015. The importance of the Austin Chalk has been reflected in the fact that 22 of the 51 wells so far spudded in 2015 (to 15 May) target this formation.

An average of 10 wells per month has been the norm so far in 2015, and although the record of 21 wells spudded in December 2014 is unlikely to be repeated in any future month, there are no signs that the drilling programme is decreasing in intensity. Future activity is reflected in the fact that there are at present in hand 20 AFE's (Authorities for Expenditure) of planned wells, 6 of which will target the Austin Chalk. Sugarloaf AMI partners have profited from the fact that Marathon has had access to 12 rigs during the period mentioned and at no time has there been time lost due to rig unavailability. And although the overall active rig count in Karnes County has fallen from 31 in February to 18 in May 2015, rig availability has not been adversely affected for operations in the Sugarloaf AMI. 

Only 2 wells, May B AC2H and Brysch Jonas B2H which were spudded September 2014, had to be plugged and abandoned for technical reasons. In this low commodity price environment, the tempo of drilling has only marginally declined. 84 wells were brought on production during the period April 2014 to March 2015. 70 came on production during 2014 and another 29 have been added this year (to 15 May). At 26 August 2015 there are 241 wells producing gas and condensate in the Sugarloaf AMI of which 32 are producing from the Austin Chalk. The "Stack and Frac" pilot operations are likely to result in the focusing of increased attention on the Upper Eagle Ford Shale.

The drilling and completion operations are highly sophisticated and technically difficult. Of the 259 wells so far drilled by Marathon only two have been plugged and abandoned. The rest are successful producers. The operator has from the beginning embarked on a programme of technical initiatives aimed at achieving optimum productivity with maximum economic efficiency.

Productivity continues to improve with on-going refinements in stimulation design. Spacing has also evolved. Most of the wells drilled in the past year have been located at 40-60 acre spacing. This has resulted in an approximate 45% increase in 30 day initial production rates over wells drilled previously at greater than 60 acre spacing. With the "stack and frac" procedure the spacing is even less at 40 acres (approximately 350ft wide block) with the encouraging results already mentioned. When two wells target the Lower Eagle Ford Shale the spacing actually reduces to as low as 20 acres.

There exists a large variation in the early days of production for many of the wells, independent of well location. The May 1 3H well, drilled in April 2014 and commenced production on the 25 August, has so far recorded the highest production rate of all the wells. In the first month of production in September 2014 it produced 34,106 BO and 85,200 msc.ft of gas from the Eagle Ford Shale. Urrutia 8H, produced similar volumes of 32,448 BO and 80,565 msc.ft of gas in the same month.

Children Weston 4H has so far been the most prolific producer from the Austin Chalk. In the first full month of production in May 2014 it produced 26,088 BO and 95,523 msc.ft of gas. During 2014, when most of the Austin Chalk well commenced production, the initial monthly volumes varied between 9,000- 19,000 BO (average 15,000 BO) and 40,000- 85,000 msc.ft of gas (average 60,000 ms.cft).

The well head production results do not seem to show any fixed relationship between the volumes of gas produced and volumes of condensate. Nor can it be said that the Eagle Ford Shale will always be the more prolific producer. The first "Stack and Frac" results are a good example. The three Lower Eagle Ford wells in the first full month of production produced 15,273, 7,924, and 16,845 BO respectively. The two Austin Chalk wells produced 18,237 and 16,484 BO during the same period.

Marathon has reduced drilling costs by developing improved drilling techniques and adopting the practice of common pad drilling (sometimes up to eight wells per pad). Marathon recently announced a reduction in exploration and production costs per oil equivalent barrel of US$7.94, down 17 % from the fourth quarter 2014. Completed well costs have fallen by approximately 15%.

In the Sugarloaf AMI, drilling time has taken between 9-15 days from spud to TD (total depth). Fraccing time varies depending on the number of stages executed (between 15 -28 per well) with the completion cost always greater than the drilling. Total well costs have varied between US$6-8.5 million. Marathon has stated that in general there has been an average cost reduction of approximately US$1.3 million independent of the commodity price environment. Marathon attributes the reduction to a "diverse range of drivers" among which include efficient deployment of contract labour, focus on compressor utilisation, optimisation of chemical programmes and aggregating water production into gathering systems. Marathon have more recently announced further efficiency gains from a continual improvement in drilling and completion.

In summary, the monthly rate of well spuds has not abated. During the period April 2014 to March 2015, 130 wells were spudded and 84 brought on production. As of 26 August 2015 there are 241 wells producing gas and condensate out of a total 308 wells spudded.

The Lower Eagle Ford Shale continues to be the main producing horizon with the overlying Austin Chalk increasing in importance. The Upper Eagle Ford Shale shows great potential and will be targeted more often in the future, giving scope for further reserve increases.

A new technique instigated by Marathon termed "Stack and Frac", whereby stacked targets are co-produced from the same pad with a 20-40 acre spacing, was commenced late 2014 and shows early encouraging results. The technique is likely to be employed more frequently in the future. The productivities have improved markedly through technical innovation, and drilling and completion costs have decreased significantly.

The capacities of five central facilities are planned to be increased to 320,000 mscfd and 80,000 barrels of condensate respectively to accommodate the additional production from the Upper Eagle Ford Shale and overlying Austin Chalk. It is anticipated that full development of the Austin Chalk could involve the drilling of an extra 300 wells in addition to the Eagle Ford Shale wells.

Sugarloaf Block A (7.5% WI)

Production of gas and condensate from the first of the four producing wells, in which Empyrean holds a 7.5% WI, commenced on the 13 November 2008. The remaining three wells commenced production in February 2009. The four wells are referred to as TCEI Block A-1 (Kunde No3), A-3 (Baker Trust No1), A-4 (Baker Trust No2) and A-5 (Marlene Olson No1).

The Kunde No4 (A-2) vertical well never produced and was used as a monitoring well for frac identification and delineation in adjacent producing wells.

Empyrean had decided at the time against participating in further drilling in Block A, the focus being on development drilling in the adjacent Block B (Sugarloaf AMI).

In September 2013 Empyrean announced its decision to accept participation in the drilling of an additional two Eagle Ford Shale wells.

Baker Trust No 4, in which Empyrean holds an approximate 2.45% WI, commenced producing gas condensate on the 29 December 2013. It has a measured TD of 17,948ft.

Marlene Olson No 3, the second well in which Empyrean has an approximate 0.85% WI, commenced production on the 22 March 2014 and has a measured TD of 20,601ft (lateral approximately 7,000 ft.). Both wells were drilled from the same pad. 

Empyrean's interest in the two wells is less than the previous 7.5% WI because parts of each well traverse acreage in which no WI is held; the resulting interest being based on a pro rata share.

Since then Empyrean has participated in another five wells located on acreage enclosing existing producers. WI is substantially reduced because of pro rata acreage sharing.

Kunde A B1 (ex Lucille Klein A1) spudded on the 7 May 2014 and commenced production 17 July 2014 (TD 19,325ft) reaching a maximum production of 19,122 BO and 68,627 msc.ft of gas in October 2014. In April 2015 the volumes had decreased to 6,744 BO and 21,717 msc.ft of gas. Empyrean holds a 3.154661% WI.

Marlene Olson #4 spudded on the 30 September 2014, reached a measured TD of 20,438 ft on the 6 December 2014 but has not begun producing to date.

Marlene Olson #5 spudded on the 4 October 2014, reached a TD of 20,640 ft on the 20 November and commenced production on the 8 April 2015. It produced 8,846 BO and 30,182 msc.ft of gas in the month of April.

Marlene Olson #6 reached a measured TD of 20,582 ft on the 4 November and commenced production on the 8 April 2015. There was a similar production of 8,855 BO and 28,220 msc.ft of gas.

Marlene Olson #7 reached a measured TD of 20,285 ft on the 23 October and commenced production on the 8 April 2015. Production was 8,224 BO and 24,803 msc.ft of gas during the first 22 days.

Empyrean holds a 0.852273% WI in all four horizontal Marlene Olson #4, 5, 6 and 7 wells. The producing horizon is the Eagle Ford Shale and the operator remains ConocoPhillips. The Board took a decision to partially impair some of the Sugarloaf Block A wells during the year ended 31 March 2015 based on well performance data and current oil price assumptions. Refer to Statement of Accounting Policies - Judgements, Estimates and Assumptions for further detail.

Riverbend Project (10% WI)

Cartwright No1 was re-entered to test the younger Wilcox Formation in the interval between 9,584 ft. -9,590 ft. Production from the primary Austin Chalk target had been unsuccessful due to a down hole obstruction, however the Austin Chalk remains a valid exploration target.

The formation was successfully perforated and tested. The Wilcox Formation had previously exhibited encouraging hydrocarbon "shows" during the initial drilling of the well.

Initial production from the Wilcox Formation of 30-40 barrels of condensate and 755 msc.ft of gas per day was encouraging. However the present economic environment has necessitated a temporary cessation of production in October 2014. The well remains suspended and will recommence production when commodity prices improve. The Board took a decision to partially impair the Cartwright well during the year ended 31 March 2015 based on well performance data and current oil price assumptions. Refer to Statement of Accounting Policies - Significant Judgements, Estimates and Assumptions for further detail.

Eagle Oil Pool Development Project (58.084% WI)

Empyrean increased its interest from 48.5% to 58.084% at no extra cost to the Company. Many of the leases mature during the 2015 calendar year and the operator is presently undergoing a lease renewal and re-negotiation exercise that is hoped to be completed within the next few months. A vertical well test of the Gatchell sands, and possibly the Kreyenhagen Shale, still remains the most likely option when drilling recommences. A horizontal appraisal well would then be the most logical step.

Definitions

2P Most likely or "2P" volumes represent most likely deterministic estimates of proved plus probable reserves as defined by the SEC, plus contingent or "2C" volumes with the same technical certainty as proved and probable reserves that are expected to be recovered but that cannot yet be classified as reserves, or the P50 on the cumulative distribution of results from probabilistic estimates

MMBOE Million barrels of oil equivalent

NPV Net present value

Production Production available for sale

WTI West Texas intermediate crude, type of oil used as a benchmark in oil pricing

Frank Brophy BSc (Hons)

Executive Technical Director

6 September 2015

Statement of Comprehensive Income

For the Year Ended 31 March 2015

All financial results presented are from continuing operations. The accompanying accounting policies and notes form an integral part of these financial statements.

Statement of Financial Position

As at 31 March 2015

1The allocation of current and non-current borrowing in the prior year has been amended to reflect the correct position as at 31 March 2014.

Statement of Cash Flows

For the Year Ended 31 March 2015

Statement of Changes in Equity

For the Year Ended 31 March 2015

The accompanying accounting policies and notes form an integral part of these financial statements.

Statement of Accounting Policies

For the Year Ended 31 March 2015

Basis of preparation

The Company's financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the European Union and Companies Act 2006. The principal accounting policies are summarised below. They have all been applied consistently throughout the year. The financial report is presented in the functional currency, US dollars and all values are shown in thousands of US dollars (US$'000).

Going concern

The Directors consider that the Company has adequate resources to continue in operational existence for the foreseeable future and that it is therefore appropriate to adopt the going concern basis in preparing its financial statements. The net current liabilities of US$1,988,000 (2014: US$5,465,000 net current liabilities) will be funded with a combination of operating revenue and debt from the Macquarie Bank Facility and or equity if required. If the current liabilities are funded from debt then this will have the effect of swapping short term debt for long term debt. Any further draw downs on the Macquarie Bank Facility are subject to the bank's normal credit department approvals for drawdowns under the facility. The Company's Sugarloaf acreage is held by production and the Company has the ability to opt out of wells, if necessary, in order to help manage its cashflow should the pace of development necessitate or oil prices remain low or should adequate funding not be available to allow the Company to participate. Any such decisions would be made in the context of the prevailing environment.

Basis of accounting and adoption of new and revised standards

a) New and amended standards adopted by the Group:

The following new standards and amendments to standards are mandatory for the first time for the Company for the financial year beginning 1 April 2014. Except as noted, the implementation of these standards did not have a material effect on the Company:

Joint arrangements under IFRS 11 have the same basic characteristics as joint ventures under IAS 31. Joint arrangements are classified as either joint operations or joint ventures. Where the Group has rights to the assets and obligations for the liabilities of the joint arrangement, it is regarded as a joint operation and the interests of the Group in the assets, liabilities, income and expenses arising from the joint arrangement are recognised.

b) Standards, amendments and interpretations that are not yet effective and have not been early adopted:

1 Not yet endorsed by the EU

The Company does not expect the pronouncements to have a material impact on the Company's earnings or shareholders' funds.

Revenue recognition

Revenue is derived from sales of oil and gas to third party customers. Sales of oil and gas production are recognised at the time of delivery of the product to the purchaser which is when the risks and rewards of ownership pass and are included in the statement of comprehensive income as Revenue. Revenue is recognised net of local ad valorem taxes. Interest revenue is accrued on a time basis, by reference to the principal outstanding at the effective interest rate applicable.

Cash and cash equivalents

Cash and short-term deposits in the Statement of Financial Position comprise cash at bank and in hand and short-term deposits with an original maturity of three months or less. For the purposes of the Cash Flow Statement, cash and cash equivalents consist of cash and cash equivalents as defined above, net of outstanding bank overdrafts.

Tax

The major components of tax on profit or loss include current and deferred tax. Current tax is based on the profit or loss adjusted for items that are non-assessable or disallowed and is calculated using tax rates that have been enacted or substantively enacted by the reporting date. Tax is charged or credited to the income statement, except when the tax relates to items credited or charged directly to equity, in which case the tax is also dealt with in equity.

Deferred tax

Deferred tax assets and liabilities are recognised where the carrying amount of an asset or liability in the statement of financial position differs to its tax base. Recognition of deferred tax assets is restricted to those instances where it is probable that taxable profit will be available, against which the difference can be utilised. The amount of the asset or liability is determined using tax rates that have been enacted or substantively enacted by the reporting date and are expected to apply when the deferred tax liabilities/(assets) are settled/(recovered). The Company has considered whether to recognise a deferred tax asset and has determined that this is not appropriate in line with IAS 12 as the conditions for recognition are not satisfied.

Royalties

Royalties or taxes based on production quantities or calculated as a percentage of revenue taken out of net revenue proceeds received.

Foreign currencies

Transactions denominated in foreign currencies are translated into US dollars at contracted rates or, where no contract exists, at average monthly rates. Monetary assets and liabilities denominated in foreign currencies which are held at the year-end are translated into US dollars at year-end exchange rates. Exchange differences on monetary items are taken to the Statement of Comprehensive Income. Items included in the financial statements are measured using the currency of the primary economic environment in which the Company operates (the functional currency).

Joint arrangements

Joint arrangements are arrangements in which the Company shares joint control with one or more parties. Joint control is the contractually agreed sharing of control of an arrangement, and exists only when decisions about the activities that significantly affect the arrangement's returns require the unanimous consent of the parties sharing control.

Joint arrangements are classified as either joint operations or joint ventures based on the rights and obligations of the parties to the arrangement. In joint operations, the parties have rights to the assets and obligations for the liabilities relating to the arrangement, whereas in joint ventures, the parties have rights to the net assets of the arrangement.

Joint arrangements that are not structured through a separate vehicle are always joint operations. Joint arrangements that are structured through a separate vehicle may be either joint operations or joint ventures depending on the substance of the arrangement. In these cases, consideration is given to the legal form of the separate vehicle, the terms of the contractual arrangement and, when relevant, other facts and circumstances. When the activities of an arrangement are primarily designed for the provision of output to the parties, and the parties are substantially the only source of cash flows contributing to the continuity of the operations of the arrangement, this indicates the parties to the arrangements have rights to the assets and obligations for the liabilities.

The Company accounts for all its joint arrangements as joint operations by recognising the assets, liabilities, and expenses for which it has rights or obligations, including its share of such items held or incurred jointly.

Oil and gas assets: exploration and evaluation

The Company applies the full cost method of accounting for Exploration and Evaluation ('E&E') costs, having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources'. Under the full cost method of accounting, costs of exploring for and evaluating oil and gas properties are accumulated and capitalised by reference to appropriate cash generating units ('CGUs'). Such CGUs are based on geographic areas such as a concession and are not larger than a segment.

E&E costs are initially capitalised within 'Intangible assets'. Such E&E costs may include costs of license acquisition, third party technical services and studies, seismic acquisition, exploration drilling and testing, but do not include costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to the income statement as they are incurred. Plant, Property and Equipment ('PPE') acquired for use in E&E activities are classified as property, plant and equipment. However, to the extent that such PPE is consumed in developing an intangible E&E asset, the amount reflecting that consumption is recorded as part of the cost of the intangible E&E asset. Intangible E&E assets related to exploration licenses are not depreciated and are carried forward until the existence (or otherwise) of commercial reserves has been determined. The Company's definition of commercial reserves for such purpose is proven and probable reserves on an entitlement basis.

If commercial reserves have been discovered, the related E&E assets are assessed for impairment on a CGU basis as set out below and any impairment loss is recognised in the income statement. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as development and production assets within property, plant and equipment and are amortised on a unit of production basis over the life of the commercial reserves of the pool to which they relate. Intangible E&E assets that relate to E&E activities that are not yet determined to have resulted in the discovery of commercial reserves remain capitalised as intangible E&E assets at cost, subject to meeting impairment tests as set out below.

E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include the point at which a determination is made as to whether or not commercial reserves exist. Where the E&E assets concerned fall within the scope of an established CGU, the E&E assets are tested for impairment together with all development and production assets associated with that CGU, as a single cash generating unit. The aggregate carrying value is compared against the expected recoverable amount of the pool. The recoverable amount is the higher of value in use and the fair value less costs to sell. Value in use is assessed generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. Where the E&E assets to be tested fall outside the scope of any established CGU, there will generally be no commercial reserves and the E&E assets concerned will generally be written off in full. Any impairment loss is recognised in the income statement.

Oil and gas assets: development and production

Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the decommissioning asset (see below) and the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above. They are presented as oil and gas properties in Note 9.

The net book values of producing assets are depreciated on units of production basis. The depletion rate was calculated using the proven 1P reserves.

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit. The recoverable amount is the higher of value in use and the fair value less costs to sell. Value in use is assessed generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash generating unit where the cash flows of each field are interdependent. The Company has potential decommissioning obligations in respect of its producing interests. The extent to which a provision is required in respect of these potential obligations depends, inter alia, on the legal requirements at the time of decommissioning, the cost and timing of any necessary decommissioning works, and the discount rate to be applied to such costs. The Company recognised a provision in its accounts at 31 March 2015.

Financial assets

Financial assets are recognised at initial recognition at fair value plus, in the case of financial assets not recorded at fair value through profit and loss, transaction costs that are attributable to the acquisition of the financial asset. The Company's financial assets consist of loans and receivables, cash and cash equivalents and financial assets classified as fair value through profit or loss. All financials assets, other than cash and cash equivalents are initially measured at fair value and subsequently at amortised cost. Cash and cash equivalents comprise cash on hand or held on current account or on short-term deposits (up to 90 days) at variable interest rates. Any interest earned is accrued monthly and classified as finance income.

Financial liabilities

All financial liabilities are recognised initially at fair value and, in the case of loans and borrowings and payables, net of directly attributable transaction costs. The Company's financial liabilities include trade and other payables, loans and borrowings including bank loans and derivative financial liabilities. Financial liabilities, including trade and other payables, loans and borrowings, are initially stated at their fair value and subsequently at amortised cost. Interest and other borrowing costs are recognised on a time-proportion basis using the effective interest method and expensed as part of financing costs in the statement of comprehensive income. Derivative financial liabilities are initially recognised at fair value of the date a derivative contract is entered into and subsequently re-measured at each reporting date. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Company has not designated any derivatives as hedges as at 31 March 2014 or 31 March 2015.

When the Company's borrowings are refinanced, the difference between the carrying amount of a financial liability (or part of a financial liability) extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is accelerated when the refinancing is considered to be a substantial modification of terms. The refinancing is considered a substantial modification if either the quantitative tests set out by IFRS are breached or the Directors consider the qualitative factors (coupon rate, security, term, etc.) to be a substantial modification. Upfront fees are set-off against the fair value of the liability upon initial recognition and amortised to the income statement using the effective interest method. The derivative recognised at 31 December 2015 relates to share options issued to Macquarie Bank as part of the refinancing. These options were subject to shareholder approval which was received in the post balance sheet period. This transaction falls outside of the scope of IFRS 2 and is fair valued as a derivative financial liability. The cost is recognised as a transaction cost netted off against the loan balance.

Share based payments

The Company issues equity-settled share-based payments to certain employees. Equity-settled share-based payments are measured at fair value at the date of grant. The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Company's estimate of shares that will eventually vest. Where equity instruments are granted to persons other than employees, the income statement is charged with the fair value of goods and services received. 

Significant accounting judgements estimates and assumptions

The Company makes judgements and assumptions concerning the future that impact the application of policies and reported amounts. The resulting accounting estimates calculated using these judgements and assumptions will, by definition, seldom equal the related actual results but are based on historical experience and expectations of future events. The judgements and key sources of estimation uncertainty that have a significant effect on the amounts recognised in the financial statements are discussed below.

Impairment of assets

Financial and non-financial assets are subject to impairment reviews based on whether current or future events and circumstances suggest that their recoverable amount may be less than their carrying value. Recoverable amount is based on a calculation of expected future cash flows which includes management assumptions around future production, costs, capital expenditure, inflation and discount rates.

Sugarloaf Block A

The carrying value of the individual wells comprising the Sugarloaf Block A were tested for impairment by comparing the carrying value with the estimated future revenues for each well. The Baker Trust #2 (A-4) and Marlene Olson #1(A-5) wells remain suspended so the Company has adopted a conservative approach to fully write off the carrying value of these 2 wells. Kunde #3 (A-1) well has had a significant reduction in production during the year ended 31 March 2015 and has been assessed for impaired and partially impaired accordingly as a result. The partial impairment has been calculated by using a value in use model to provide a conservative estimate of monthly revenue, multiplied by an estimate of the well life (based on third party extrapolation of depletion curves), discounted at 10%. The difference has resulted in the partial impairment charge. Refer to Note 9 for the impairment charge.

Riverbend

The carrying value of the Cartwright well was tested for impairment by comparing the carrying value with the recent capitalised expenditure. As the well only remains suspended, with a view to recommencing production in an improved economic environment, it has been partially impaired for the Wilcox Phase of expenditure. Refer to Note 8 for the impairment charge.

Exploration and evaluation expenditure

The Company's policy for E&E expenditure requires an assessment of both the future likely economic benefits from future exploitation or sale and whether the activities are at a stage that permit a reasonable assessment of the existence of reserves. Any such assessment may change as new information becomes available . If after capitalisation, information becomes available suggesting that the recovery of the carrying amount is unlikely, the relevant capitalised amount is written off in the statement of comprehensive income in the period when the new information becomes available.

Share-based payments

Certain Directors of the Company receive remuneration in the form of equity-settled share-based payment transactions, whereby services are rendered in exchange for rights over shares ("equity-settled transactions"). The cost of equity-settled transactions with Directors and the Company Secretary is measured by reference to the fair value at the date at which they are granted. The fair value is determined using the Black-Scholes pricing model. The cost of equity-settled transactions with parties other than Directors and the Company Secretary is measured at the fair value of the services received at the date of receipt, with a corresponding increase in equity.

Notes to the Financial Statements

For the Year Ended 31 March 2015

1. Segmental analysis

The primary segmental reporting format is determined to be the geographical segment according to the location of the asset. The Directors consider the Company to have two business being the exploration for, development and production of oil and gas properties.

There is one geographical trading segment being North America which is involved in the exploration for, development and production of oil and gas properties. The Company's registered office is located in the United Kingdom.

2. Administrative expenses

3. Finance expense

4. Share based payments

The Company had no employees during the year, other than Directors and the Company Secretary who are either directly employed or employed on a consultancy basis or a combination.

The Company's equity settled share based payments comprise options granted to Macquarie Bank. The option value per security is being spread over the expected life of the facility.

During the year ended 31 March 2015, there were no options were granted to Directors and the Company Secretary. Options were granted to Macquarie Bank in relation to the loan facility in a prior year. These are disclosed in detail under Note 17.

5. Directors' emoluments

(1) Services provided by Apnea Holdings Pty Ltd

(2) Services provided by F J Brophy Pty Ltd

No UK pension benefits are provided for any UK resident Director.

There has been no increase in Directors emoluments during the period. Any year on year variance is a result of minor fluctuations in currency as the Directors are paid in £ and this is recorded in US$.

As announced on 2 March 2015, subsequent to year end, Director's salaries and fees were reduced by 10%pa.

Directors' share options

The terms of the share option interests of Directors in office during the year ended 31 March 2015 were as follows:

(1)As announced on 20 March 2014, these options had their expiry date extended to four months following the publication of the Company's Annual Report & Accounts for the period to 31 March 2014.

(2)As announced on 2 March 2015, these options had their expiry date extended to 19 July 2016.

6. Taxation

Tax losses of approximately US$46.1m (2014: US$43.1m) are available to be claimed going forward, which are inclusive of the exploration expenditure and oil & gas properties impairment total write off of US$14.6m (2014: US$12.6m).

7. Earnings per share

The basic earnings per share is derived by dividing the net profit before taxation for the year attributable to ordinary shareholders by the weighted average number of shares in issue.

8. Oil and gas properties: exploration and evaluation

2Impairment resulted from Riverbend well review of Wilcox Phase, refer to Significant accounting judgements estimates and assumptions for details of key judgements applied.

9. Oil and gas properties: development and production

2Impairment resulted from Sugarloaf Block A wells review of future revenue assessment. An impairment of the wells' net book value was made where there was no future revenue expected. A partial impairment of the wells' net book value was made where expected future revenue was lower than the current net book value. Refer to Statement of Accounting Policies: Significant accounting judgements estimates and assumptions - Impairment of assets. In addition, refer to Note 13 for information regarding the fixed and floating charge over the Sugarloaf AMI asset by Macquarie Bank.

10. Trade and other receivables

11. Current trade and other payables

12. Provisions

The provision for decommissioning costs is calculated on the following assumptions:

• decommissioning cost of US$70,000 per well (gross)

• US CPI rate of 2% and long term bond rate of 3%

• Average life of 19 years per well

13. Borrowings

(1) The Macquarie Bank Facility totalling US$20,832,000 was entered into on 30 May 2012, drawn down on twice during the year and is repayable at an interest rate of 9%pa plus LIBOR. The first repayment was on 28 June 2013 and 7 repayments have been made subsequently. The Macquarie Bank Facility is secured by a fixed and floating charge over the Company, a Company guarantee and a specific charge over the Sugarloaf AMI asset.

14. Derivatives

Derivative liabilities consist of the fair value of options attached to the Macquarie loan facility. The options were subject to shareholder approval at 31 March 2015 and were subsequently granted after the General Meeting on 27 July 2015. The 15,000,000 options are exercisable at £0.10 per option, expiring 26 July 2019. This transaction falls outside of the scope of IFRS 2 and is fair valued as a derivative financial liability. The cost is recognised as a transaction cost netted off against the loan balance. The fair value of the warrant was estimated using a Black Scholes Model with the following inputs:

15. Deferred tax

The deferred tax assets and liabilities are offset to determine the amounts stated in the Consolidated Statement of Financial Position when the taxes can legally be offset and will be settled net. Deferred taxation comprises:

Deferred tax assets of US$15,181,000 (31 March 2014: Nil) have been recognised in respect of tax losses and to be utilised by future taxable profits generated by operations in the US. The unrecognised deferred tax losses represent losses at a UK company level. The Company does not expect to pay tax in the UK as all profits are generated in the US branch and subject to tax in that jurisdiction. The Company claims double tax treaty relief for those taxable profits in the UK.

16. Reconciliation of net profit before taxation to operating cash flows

17. Called up share capital

On 23 October 2014, 100,000 fully paid ordinary shares of 0.2p each were issued as a result of option conversions for cash at a price of £0.08 per share.

On 27 February 2015, 300,000 fully paid ordinary shares of 0.2p each were issued as a result of option conversions for cash at a price of £0.08 per share.

Share options and warrants

The following equity instruments have been issued by the Company and have not been exercised at 31 March 2015:

(1)As announced on 20 March 2014, these options had their expiry date extended to four months following the publication of the Company's Annual Report & Accounts for the period to 31 March 2014.

(2)As announced on 2 March 2015, these options had their expiry date extended to 19 July 2016.

(3)The value of these options is being expensed over a period of 4 years.

(4)Subsequent to the prior year end, the exercise price of the warrants was converted to US$0.147175 each.

(5)On issue of the warrants in 2012, nil value was attributed to the securities.

18. Reserves

19. Commitments

As at 31 March 2015, the Company had no material capital commitments, other than Authority For Expenditures ("AFE's") received from the operator of the Sugarloaf AMI in the normal course of business for operations, including future wells and facilities, that the Company intends to participate.

20. Related party transactions

There were no related party transactions during the year ended 31 March 2015 other than disclosed in Note 5.

21. Financial instruments

The Board of Directors determine, as required, the degree to which it is appropriate to use financial instruments to mitigate risk. Currently the Company's principal financial instruments comprise cash and the Macquarie Bank Facility at an interest rate of 9%pa plus LIBOR. Refer to Note 13 for further details. Together with the issue of equity share capital, the main purpose of these is to finance the Company's operations. The Company has other financial instruments such as short-term receivables and payables which arise directly from normal trading.

Interest rate risk

Short-term receivables and payables are not exposed to interest rate risk. The Company's borrowing with Macquarie is subject to the 9%pa plus LIBOR rate. The following table illustrates sensitivities to the Company's exposures to changes in interest rates. The table indicates the impact of how profit at balance date would have been affected by changes in the relevant risk variable that management considers to be reasonably possible. These sensitivities assume that the movement in a particular variable is independent of other variables. At 31 March 2015, the effect on profit as a result of changes in the interest rate on the Macquarie borrowing facility, with all other variable remaining constant would be as follows:

Credit risk

Credit risk is the risk of financial loss to the Company if a customer or a counter party to a financial instrument fails to meet its contractual obligations. The Company is mainly exposed to credit risk through cash and cash equivalents and deposits with banks and financial institutions. The risk is mitigated by reviewing the credit rating of banks (which are HSBC Bank and Macquarie Bank). The operating partners are global companies (refer to Note 9) with significant market capitalisations and therefore credit risk is low.

Currency risk

The Company's functional currency is US$ and as the majority of its operating expenses and revenues are denominated in USD, the Company does not consider that it is exposed to a significant foreign currency risk.

Liquidity risk

The Company's policy throughout the year has been to ensure that it has adequate liquidity by careful management of its working capital. The following table details the remaining contractual maturity for the non-derivative financial assets and liabilities of the Company. The table has been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Company can be required to pay. The table includes both interest and principal cash flows including rates for loan liabilities and cash deposits on actual contractual arrangements.

Commodity risk

The Board recognises that through the normal course of business the Company is exposed to commodity risks for the revenue's received. To manage commodity risk the Company entered into a hedging arrangement during the year to manage the Company's price risk exposure during the year ended 31 March 2015 as a requirement of Macquarie Bank. Empyrean announced on 8 April 2015 that it had entered hedging in the form of Commodity Swap Transaction (the 'SWAP') contracts with Macquarie bank for an aggregate 97,371 barrels of oil ('bbl') for a period of 12 months commencing 1 April 2015 through to 31 March 2016. The SWAP is for a fixed price of US$51 per bbl based on OIL-WTI-NYMEX ('WTI'). In addition, the Company has entered into put and call option arrangements (the Options') with Macquarie to effect a collar in respect of 102,469 bbl for a period of 24 months commencing 1 April 2016 through to 31 March 2018 with prices between US$50 and US$62.80 per bbl. For the months of April 2014 through August 2014, Empyrean had SWAP hedging in place for an aggregate total of 18,249 bbls at a fixed price of US$95.90. These contracts were required as part of the Company's finance facility with Macquarie Bank. All positions had closed in September and the Company was not required by Macquarie Bank to take out additional hedging at that time.

Capital

In managing its capital, the Company's primary objective is to maintain a sufficient funding base to enable the Company to meet its working capital and strategic investment needs. In making decisions to adjust its capital structure to achieve these aims, through new share issues, the Company considers not only its short-term position but also its long-term operational and strategic objectives.

Determination of fair values

A number of the Company's accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and / or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

(i) Cash & cash equivalents, restricted cash, accounts receivable, accounts payable and accrued expenses

The fair value of cash & cash equivalents, restricted cash, accounts receivable, accounts payable and accrued expenses is estimated as the present value of future cash flows, discounted at the market rate of interest at the reporting date. As at 31 March 2015 and 31 March 2014, the fair value of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued expenses approximated their carrying value due to their short term to maturity.

(ii) Derivatives

The fair value of the Macquarie Bank options is calculated using a Black Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends, and the risk-free interest rate (based on government bonds). A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of incentive stock options that vest. Refer to Note 14.

1Included in Trade and other payables.

The hedging instrument and the derivative in Note 14 are the only financial instruments whereby a valuation has been applied. A level 1 fair value measurement is applied to the hedging instrument and the mark to market valuation is based on the quoted oil price. A level 2 fair value measurement is applied to the derivative and the fair value technique has been disclosed in Note 14. The different levels have been defined as follows:

Level 1 Fair Value Measurements

· Level 1 fair value measurements are based on unadjusted quoted market prices

Level 2 Fair Value Measurements

· Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices.

Level 3 Fair Value Measurements

· Level 3 fair value measurements are based on unobservable information.

22. Events after the reporting date

There were no significant events post reporting date other than the following:

Empyrean announced on 8 April 2015 that it had entered hedging in the form of Commodity Swap Transaction (the 'SWAP') contracts with Macquarie bank for an aggregate 97,371 barrels of oil ('bbl') for a period of 12 months commencing 1 April 2015 through to 31 March 2016. The SWAP is for a fixed price of US$51 per bbl based on OIL-WTI-NYMEX ('WTI'). In addition, the Company has entered into put and call option arrangements (the Options') with Macquarie to effect a collar in respect of 102,469 bbl for a period of 24 months commencing 1 April 2016 through to 31 March 2018 with prices between US$50 and US$62.80 per bbl. The Macquarie Hedging Contract closing positions for each month after 31 March 2015 are as follows:

April 2015: US$39,690 settled in May 2015.

May 2015: US$87,596 settled in June 2015.

June 2015: US$83,337 settled in July 2015.

July 2015: (US$640) settled in August 2015.

Financial statements are published on the Company's website in accordance with legislation in the United Kingdom governing the preparation and dissemination of financial statements, which may vary from legislation in other jurisdictions. The maintenance and integrity of the Company's website is the responsibility of the Directors. The Directors' responsibility also extends to the ongoing integrity of the financial statements contained therein.

**ENDS**

For further information please visit www.empyreanenergy.com or contact the following:

Notes to Editors:

Empyrean Energy Plc is an AIM listed (Ticker: EME) profitable US on-shore oil, gas and condensate exploration, development and production company with assets in Texas and California. The Company's portfolio represents a mix of assets at various stages of development. Its flagship project is the Sugarloaf AMI in the prolific Eagle Ford Shale, Texas, where it has a 3% working interest in approximately 24,000 gross acres centrally positioned in the liquids rich sweet-spot within the field. Empyrean has an interest in 241 gross producing wells with full development expected to reach over 770 wells. Further development of the Eagle Ford Shale anticipated to require in the order of a further 300 wells, with down spacing potential of a further 200 wells. Further development of the Austin Chalk anticipated to require in the order of a further 300 wells, with down spacing potential of a further 235 wells. The Company has a term debt facility of up to US$50 million with Macquarie Bank, subject to reserve hurdles and drawdown approvals, in place in order to develop this acreage which is operated by US major Marathon Oil Company.

Other assets include a 58.084% interest in the Eagle Oil Pool Development Project located in the San Joaquin Basin, southern California, a proven oil and gas province. Empyrean's large working interest in this project provides the Company with flexibility and leverage with potential high impact from success. Additionally, Empyrean has a 7.5% interest in the Sugarloaf Block A operated by ConocoPhillips in the Eagle Ford Shale, and a 10% working interest in the Riverbend Project in Texas.