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MPET > SEC Filings for MPET > Form 10-K on 16-Sep-2013All Recent SEC Filings

Show all filings for MAGELLAN PETROLEUM CORP /DE/



Annual Report


The following discussion and analysis presents management's perspective of our business, financial condition, and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition, and outlook for the future, and should be read in conjunction with Item 8: Financial Statements and Supplementary Data of this Form 10-K. In the following tables, the combination of Palm Valley and Mereenie (until May 2012) represents our MPA reporting segment. Amounts expressed in Australian currency are indicated as "AUD." Forward looking statements are not guarantees of future performance, and our actual results may differ significantly from the results expressed or implied in the forward looking statements. See "Forward Looking Statements" at the end of this section. Factors that might cause such differences include, but are not limited to, those discussed in Item 1A: Risk Factors of this Form 10-K. We assume no obligation to revise or update any forward looking statements for any reason, except as required by law.

Magellan is an independent energy company engaged in the exploration, development, production, and sale of crude oil and natural gas. Our operations are conducted through three wholly owned subsidiaries: NP, which owns and operates an oilfield in Poplar; MPA, which owns and operates onshore gas fields in Australia, and owns an offshore exploration license in Australia; and MPUK, which owns a large acreage position in the Weald and Wessex Basins in southern England. Our strategy

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is to enhance shareholder value by maximizing the value of these existing assets. We accomplish this through the exploration and development of our assets as outlined in Items 1 and 2: Business and Properties of this report.

During fiscal year 2013, the Company took important steps in its strategy of creating value from our existing assets. Administratively, we completed the two-year turn-around of the Magellan platform through a number of achievements, including: hiring new engineering and geologic personnel, completing the overhaul of our accounting function, delisting from the Australian Securities Exchange ("ASX"), repurchasing 17% of our common shares plus warrants from an unsupportive shareholder, and raising $23.5 million in convertible preferred equity on terms the Company believes were attractive. As a result, we believe we now have an organized and effective platform poised to achieve growth and the successful development of our assets.
Operationally, we made steady progress on each of our key projects such that we can continue to achieve key developmental and operational milestones in fiscal year 2014. At Poplar, our work on the CO2-EOR pilot during fiscal year 2013 resulted in obtaining a CO2 supply contract and receiving the permits to start the drilling of our pilot wells in July and August 2013, respectively. With the drilling of CO2-EOR pilot wells now underway, we expect to deliver results by the end of calendar year 2014. In parallel, we initiated a water shut-off program to increase oil production from the existing wells at Poplar and reduce our operating costs. This program has started to yield positive results, and we will continue to implement it across the field as we gather results from each treatment. Onshore Australia, we spent most of fiscal year 2013 in discussions and contract negotiations with potential customers of Dingo gas, resulting in the signing of a long term gas sales contract, the Dingo GSPA with PWC for the sale of the majority of Dingo's reserves. Gas sales are expected to commence in early calendar year 2015 once surface facilities and a tie-in pipeline are constructed at Dingo. With gas sales contracts in place at both Palm Valley and Dingo, and considering the cost of Dingo's surface facilities and pipeline tie-in, we expect our Amadeus Basin assets to provide Magellan with reasonably predictable cash flows. Offshore Australia, we conducted 2-D and 3-D seismic surveys over NT/P82, our 100% owned exploration license in the Bonaparte Basin. Based on the preliminary interpretation of the seismic data we acquired, we are optimistic about our ability to execute a successful farmout transaction in fiscal year 2014 whereby a new partner will drill the large gas prospects that lie within our block. In the UK, together with our partner Celtique, we completed an extensive geological analysis of the potential prospects underlying our Weald Basin acreage. In addition, we prepared and filed permit applications to drill exploratory wells on our acreage, which will allow us to drill and further assess the potential for conventional and unconventional oil production in fiscal year 2014.
As a result of the achievements and improvements realized in fiscal year 2013, in fiscal year 2014 we expect to receive the results of various operational initiatives that will allow us to demonstrate the potential value of our assets and develop an asset rationalization strategy to maximize Magellan's net asset value per share.

For the year ended June 30, 2013, revenues totaled $7.1 million compared to $13.7 million in the prior year, a decrease of 48%. Operating loss totaled $22.5 million compared to operating income of $19.8 million in the prior year. Net loss totaled $19.8 million ($0.41/basic share), compared to a net income of $26.5 million ($0.49/basic share) in the prior year, primarily due to the favorable impact of the Santos SA in fiscal year 2012. Adjusted EBITDAX (see Non-GAAP Financial Measures and Reconciliation under Part 1, Items 1 and 2:
Business and Properties) totaled negative $10.9 million, compared to negative $11.2 million in the prior year, a change of (2)%. For further detail, please refer to the discussion below in this section under Comparison of Financial Results and Trends Between Fiscal 2013 and 2012.

During fiscal year 2013, the Company took important steps in its strategy of creating value from our existing assets. We made steady progress on meeting developmental and operational milestones on each of our key projects. The below discussion should be read in conjunction with the discussion of Significant Developments in Fiscal Year 2013 under Part 1, Items 1 and 2: Business and Properties above and the section covering Comparison of Financial Results and Trends between Fiscal Years 2013 and 2012 below.

Poplar (Montana, United States)
Magellan 100% operated intervals. During the year ended June 30, 2013, Magellan sold 72 Mbbls of oil attributable to its net revenue interests in Poplar, compared to 75 Mbbls of oil sold during the same period in 2012. These results represent a 4% decrease in average daily sales for the year from 205 boepd to 198 boepd.
During this period, Magellan focused heavily on advancing its CO2-EOR pilot project in the Charles formation at Poplar. The Company worked with various governmental agencies, including the Bureau of Land Management and the Bureau of Indian Affairs, to gain permits for the drilling of five wells as part of a CO2-EOR pilot project. These permits were received and drilling on these wells began in August 2013. In parallel to the permitting process, Magellan evaluated various options for the supply and transportation of CO2 for its pilot project, resulting in the signing of an approximately two-year CO2-supply contract with Air Liquide in July 2013. The CO2 supplied by Air Liquide will be trucked and stored on the drilling site and is expected

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to satisfy the CO2 volume requirements to our CO2-EOR pilot project. However, the current arrangement with Air Liquide will not be sufficient for a full field CO2-EOR program.
Magellan also remained focused on increasing oil production at Poplar and reducing operating expenses by reducing associated water production. Since most of the wells at Poplar were drilled in the 1950s, we regularly have to perform various work-overs on the wells such as small acid stimulations, fixing parted rods, and tanks and flowline repairs. These work-overs, combined with the cost of handling relatively high water production, result in high fixed costs and, while oil production remains at current levels, in high LOE/bbls. In order to increase oil production and reduce operating costs, we have identified a possible solution in the form of water shut-off treatments, which seek to block off part of the water influx and allow increased oil production. We continue to monitor and evaluate the results of these treatments to determine where they are most effective and which existing wells are the most likely candidates for future treatments. On the EPU 104 well, Magellan successfully executed a water shut-off treatment in December 2012. Prior to the water shut-off treatment, this well produced approximately 5 bopd and 1,050 bwpd. Following the treatment, the EPU 104's initial production rate was approximately 80 bopd and now produces at an average rate of 28 bopd and 337 bowd. Since then, the Company has performed water shut-off treatments on the EPU 119, EPU 34-11H, and EPU 42 wells, the results of which are still under evaluation. In July 2013, we performed similar operations on EPU 55 with the greatest results to date: the EPU 55 well is currently producing approximately 134 bopd and 35% oil cut. We believe that since these results are very recent, we need more time to estimate the well production decline rate of this well. During fiscal year 2013, we have invested approximately $1.2 million in several water shut-off treatments, and we will continue to prudently manage the allocation of the Company's cash resources to such treatments.
Finally, production from the Amsden formation from the EPU 117, which was a new pool discovery in January 2012, has declined from early production of approximately 80 bopd to approximately 7 bopd. We continue to test various stimulation techniques on this well.
Deep Intervals. Under the terms of the VAALCO PSA signed in September 2011, VAALCO was obligated to drill and complete at their own expense three test wells in the deeper formations at Poplar in order to earn a 65% working interest in and operatorship of these formations. Following completion of the first test well, the EPU 120, in fiscal year 2012, VAALCO completed its second test well, the EPU 133-H, as a horizontal well targeting the Bakken/Three Forks formation in September 2012. In March 2013, VAALCO completed its third test well, the EPU 125, a vertical well targeting the Nisku formation. Although core and log analyses taken during drilling of these wells were indicative of the potential for commercial hydrocarbon production from the Deep Intervals, the three test wells, upon completion and production testing, were found to be water bearing. Based on these inconclusive results and Magellan's desire to use those well bores for further exploration and/or potential salt water disposal, Magellan renegotiated certain terms of the VAALCO PSA in December 2012. Under the revised terms, Magellan (i) became the operator; (ii) obtained a 100% working interest in and operatorship of the wellbores for the first two wells, the EPU 133-H and the EPU 120; and (iii) increased its working interest in the Deep Intervals at Poplar from 35% to 50%, except for the spacing unit associated with EPU 125, VAALCO's third test well, which Magellan will operate but in which Magellan's working interest will remain 35%.
During fiscal year 2014, Magellan may attempt to recomplete the EPU 125 well in the Nisku formation. The Nisku formation at Poplar has produced approximately 200 thousand barrels of oil from a single well between 1970 and 1990, and data collected from the EPU 120 and EPU 125 wells confirmed the potential for commercial oil production from this formation. The decision to recomplete the EPU 125 will be based on further ongoing geological analysis by the Company and available cash resources.

Palm Valley. Following the termination of the PWC Palm Valley Contract in January 2012, Magellan successfully re-contracted the remaining 23 Bcf of Palm Valley's gas reserves through the Palm Valley GSPA with Santos. The Palm Valley gas field, which is operated by MPA, produced a gross average of approximately
0.5 MMcf/d of natural gas for sale for the year ended June 30, 2013. For the same time period in the prior year, the Palm Valley gas field produced approximately 2.7 MMcf/d. Gas sales volumes at Palm Valley decreased due to the termination of the PWC Palm Valley Contract in January 2012. The average price of gas, net of royalties and prior year royalty adjustments, at Palm Valley was AUD $4.80/Mcf for the year ended June 30, 2013, compared to AUD $3.01/Mcf for the prior year. Gas volumes during fiscal year 2013 were sold under the Palm Valley GSPA to Santos. Gas sales volumes under this contract are expected to ramp up based on currently scheduled contracts to approximately 3.3 MMcf/d by the third quarter of fiscal year 2014 and to 4.1 MMcf/d by the fourth quarter of fiscal year 2015, at which point the field will be selling at its full deliverability capacity and generating revenues of approximately AUD $8.0 million per year. Dingo. During the fiscal year, the Company undertook marketing efforts to identify and attract long term customers for Dingo's gas resources. These efforts resulted in the signing of the Dingo GSPA with PWC in September 2013 for the supply of

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31 PJ (30 Bcf) of gas over a 20-year period. In parallel to the marketing efforts, during the fiscal year Magellan completed a pre-front-end engineering and design study to evaluate the cost and logistics of installing gas treatment facilities and tying the Dingo field into the existing pipeline infrastructure near Alice Springs. This study will serve as the basis for bringing Dingo to operational capability in fiscal year 2015.
NT/P82. During fiscal year 2013, Magellan focused on conducting a seismic survey over portions of its NT/P82 Exploration Permit in the Bonaparte Basin, offshore Northern Territory, Australia. In December 2012, the Company successfully conducted, via a third-party contractor, a 2-D and 3-D seismic survey over portions of the block. The seismic recording vessel Voyager Explorer, operated by Seabird Exploration FZ-LLC, acquired a total of 76 square miles of 3-D full fold data and 65 miles of 2-D full fold data. Between January and August 2013, the seismic data was undergoing processing and interpretation, including additional processing to address the impact of fluvial channeling on the seabed. The results of the seismic surveys interpretation are expected to be received by the end of the first quarter of fiscal year 2014 and we hope will allow us to begin a farmout process during the second quarter of fiscal year 2014. Through this process, we expect to identify a partner to drill exploratory wells over the large gas prospects that may lie in the permit area in exchange for an ownership interest in and operatorship of the license. The overall cost of the seismic surveys and related processing and interpretation is estimated to total approximately AUD $3.7 million, which is under the originally estimated budget.

United Kingdom
Going forward, the Company's primary objectives in the UK are (i) to receive drilling approval for a number of different sites in order to demonstrate that, assuming the prospect for producing commercial quantities of hydrocarbons is geologically and technically viable, access to drill sites is achievable within the existing regulatory framework and current social and environmental realities; and (ii) to establish the potential of its unconventional prospects, most of which lie within the licenses co-owned with Celtique, by drilling exploratory wells and collecting cores and logs. As part of this effort, the Company plans to participate in up to three evaluation wells with Celtique, the first of which will be spud in or around the third quarter of fiscal year 2014. Celtique Operated Licenses. PEDLs 231, 234, and 243 overlay the center portion of the Weald Basin prospect for unconventional hydrocarbon resources and are subject to "drill or drop" rules by the end of June 2014 and a 50% relinquishment requirement to the extent that drilling obligations have been met by the term of the PEDLs. During fiscal year 2013, Magellan, in conjunction with Celtique, completed extensive geological analysis of the Weald Basin and focused on securing and permitting various potential well site locations.
We and our partner, Celtique, believe that the drilling of one well located in PEDL 234 may qualify to meet our work commitments for both PEDLs 234 and 243. We expect this well will be spud in the third quarter of fiscal year 2014. In addition, we are in the process of permitting a well in PEDL 231 to fulfill our commitments for drilling in PEDL 231 and have applied for a 12-month extension to our current PEDL to allow additional time to receive planning approval. In PEDL 234, we are also awaiting final planning approval to drill a well in the center of the Weald Basin, which may spud in the fourth quarter of fiscal year 2014. The purpose of these wells is to test and evaluate the Kimmeridge Clay and Liassic formations in order to substantiate the unconventional oil production potential of our acreage and to test and evaluate the conventional potential of the Triassic formations. Under the terms of our joint operating agreement with Celtique, we are required to participate in these commitment wells to maintain our working interest in the PEDLs. We intend to participate in the drilling of these wells and expect to fund our share of the costs through either our cash reserves, the farmout of a portion of our interests, or the proceeds from other asset sales.
Northern Petroleum Operated Licenses. In the Weald and Wessex Basins, Magellan owns working interests of between 23% and 40% in five licenses operated by Northern Petroleum (PEDL 126, 155, 240, and 256 and P1916), which expire between June 2014 and January 2016. During fiscal year 2013, Magellan determined it had no further development plans with respect to the Markwells Wood-1 well (located in PEDL 126), which was drilled in fiscal year 2011, and wrote off its remaining investment in that well of approximately $2.2 million. During the same period, the Company continued to evaluate the exploration options for its most recently acquired license, P1916, which lies offshore, west of the Isle of Wight, and PEDL 240 which is onshore and contiguous to P1916 and could provide a potential drilling site for the offshore prospect. P1916 is prospective for a Wytch Farm extension play.
Magellan Operated Licenses. In the Weald Basin, Magellan owns a 100% interest in two licenses (PEDL 137 and 246), which expire in September 2013 and June 2014, respectively. During fiscal year 2013, the Company actively pursued a farm-in partner for the drilling of an exploration well on the Horse Hill prospect in PEDL 137, for which the Company has obtained planning approval from the Surrey County Council. The Horse Hill well would target conventional oil plays in the Portland Sandstone and Corrallian Limestone, which are productive in nearby oil fields and a new Triassic gas play identified on 2-D seismic data which was reprocessed by the Company. The planning approval does not allow the operator to use hydraulic fracturing technology in this well. We will evaluate the Kimmeridge Clay and Liassic formations to contribute to the appraisal

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of the potential of these formations in the Weald Basin. In addition, Magellan has applied to the UK Government for a 12 month renewal of the PEDL 137 license to allow time for a farmout well to be drilled.

Voluntary ASX Delisting
On March 28, 2013, Magellan completed the voluntary delisting of its shares from trading on the Australian Securities Exchange ("ASX"). The Company's shares had traded on the ASX in the form of CHESS Depository Interests since Magellan's 2006 acquisition of the 45% interest it did not already own in MPA. In addition, effective April 5, 2013, Magellan converted the legal status of MPA to a proprietary company, allowing Magellan to alter the MPA board structure and eliminate related compensation expense. As a result of both initiatives, Magellan expects to realize annual savings of approximately $0.3 million.

US Federal Tax Withholdings
In connection with the Company's non-payment of required US Federal tax withholdings in the course of its 2009 acquisition of an interest in NP from White Bear and YEP I, both affiliated entities with Mr. Bogachev, a former director of Magellan, the Company estimated that it had a potential total liability of approximately $2.0 million as of June 30, 2012. As of June 30, 2013, the Company believes that this matter has been fully addressed as a result of a disclosure process with the IRS. During fiscal years ending June 30, 2012, and 2013, the Company incurred total cash expenses of $0.5 million related to this matter. The effect of this transaction on the consolidated statements of operations for the year ended June 30, 2013, resulted in other income of $0.4 million representing the difference between the original estimate and the approximate final liability of $0.1 million (see Note 13).

Transfer of MPUK
In June 2013, the Company completed the transfer of MPUK from MPA to MPC. The estimated fair value of the transfer was approximately $10.9 million. This transfer is not expected to give rise to any cash tax expenditures for the Company and will provide greater flexibility to the operation and funding of the Company's assets in the UK. As a result, the Company will now report MPUK as a third reportable segment together with NP and MPA.

Historically, we have funded our activities from cash from operations and our existing cash balance. The Company has limited capital expenditure obligations pertaining to its leases and licenses, which allow for significant flexibility in the use of its capital resources. Based on its existing cash position, the Company believes it has sufficient financial resources to fund its ongoing operations and to finance its core project at Poplar, the CO2-EOR pilot project, which we believe will further establish the full value of its assets. Furthermore, offshore Australia and in the UK, the Company owns interests in large potential projects, which require significant additional capital to reduce their inherent operational risk and increase their potential value. A possible funding strategy for these assets is to seek farm-in partners that will bear most of the costs of the next operational milestones in exchange for working interests in these assets alongside Magellan. The Company may also seek to raise debt facilities to fund some of its projects, including the construction of surface facilities and a pipeline to tie the Dingo gas field to Brewer Estate in Northern Territory, Australia. Finally, Magellan intends to explore the potential sale of certain assets which are more mature by the nature of their long term contracts and redeploy these proceeds in the Company's core assets, such as Poplar, which offer the potential to further increase the Company's net asset value per share.

Uses of Funds
Capital Expenditures Plans. At Poplar, the Company does not face significant mandatory capital expenditure requirements to maintain its acreage position. Substantially all of the leases are held by production and contain producing wells with reserves adequate to sustain multi-year production. Approximately 79% of the acreage has been unitized as a federal exploratory unit, which is held by production from any one well. Currently, Poplar contains 42 productive wells. In the Shallow Intervals, which are 100% owned and operated by the Company, discretionary capital expenditure plans over the next two years will be determined by the results of the CO2-EOR pilot project and results of water shut-off treatments. In the first half of fiscal year 2014, the Company intends to evaluate the potential of CO2-EOR in the Charles formation at Poplar by drilling a five-well pilot, including one CO2 injector well and four producing wells. Magellan expects to incur up to $20.0 million in capital costs on these wells. The four producing wells are designed to yield conventional oil production from the Charles formation in

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addition to enhanced production as a result of the CO2-EOR.
In the Deep Intervals, which are operated by the Company and in which the Company has a working interest ranging between 50% to 35%, the Company does not intend to incur material capital expenditures in fiscal year 2014. Based on its cash resources and other strategic considerations, the Company may invest in re-completing a well in the Nisku formation.
At Palm Valley, the Company's interest in the field is governed by Petroleum Lease No. 3, which expires in November 2024 (and is subject to automatic renewal for another 21 years). The Company is not obligated to undertake significant mandatory capital expenditures in order to maintain its position in the lease. The Company's discretionary capital expenditure plans are primarily focused on maintaining gas production from the existing facilities in order to meet delivery obligations under its gas sales contract with Santos while maintaining a safe and efficient operation, conducted in accordance with good oil field practice.
At Dingo, the Company's interest in the field is governed by Retention License No. 2, which expires in February 2014 (and is subject to renewal for an additional 5 years). Following the signing of the Dingo GSPA in September 2013, the Company expects to incur capital expenditures of approximately $20.0 million over the next 24 months in order to install surface facilities for production and processing of gas and to build a 27 mile pipeline connecting Dingo to existing pipeline infrastructure at Brewer Estate, south of Alice Springs. The Company expects to fund these expenditures from a combination of its own cash resources and through project finance debt facilities to be secured by the Dingo and/or Palm Valley assets and future cash flows therefrom or similar debt facilities.
In the Bonaparte Basin, offshore Australia, the Company holds a 100% interest in NT/P82. Under the terms of the permit, the Company is required to drill one exploratory well on the license by the license expiration date of May 2015. Following the successful completion of seismic surveys over two prospects in the license area and the associated processing and interpretation in August 2013, the Company expects to commence a farmout process in order to identify a partner experienced in offshore exploratory drilling to drill the exploratory well on our behalf. The Company expects to incur no further capital or exploratory expenditures of its own on this license at least until the first exploration well has been drilled.
In the UK, the Company's interests are governed by various Petroleum Exploration and Development Licenses and one Seaward Production License. The majority of these licenses expire in 2014, and all are subject to "drill-or-drop" obligations (for further detail, see Operations under Part 1, Items 1 and 2:
Business and Properties). In fiscal year 2014, the Company will focus on evaluating the potential of its unconventional prospects in the Weald Basin in southern England, which are contained within the license areas of PEDLs 231, 234, and 243, which the Company co-owns 50% with Celtique. The Company expects . . .

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