Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
MHR > SEC Filings for MHR > Form 10-K on 25-Feb-2014All Recent SEC Filings

Show all filings for MAGNUM HUNTER RESOURCES CORP

Form 10-K for MAGNUM HUNTER RESOURCES CORP


25-Feb-2014

Annual Report


Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our results of operations and our financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this annual report contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. See "Cautionary Notice Regarding Forward-Looking Statements" at the beginning of this annual report and "Risk Factors" for additional discussion of some of these factors and risks.

Business Overview
We are an independent oil and natural gas company engaged in the exploration for and the exploitation, acquisition, development and production of crude oil, natural gas and natural gas liquids resources in the United States. We are active in what we believe to be three of the most prolific unconventional shale resource plays in the United States, specifically, the Marcellus Shale in West Virginia and Ohio; the Utica Shale in southeastern Ohio and western West Virginia; and the Williston Basin/Bakken Shale in North Dakota. Our core oil and natural gas reserves and operations are primarily concentrated in West Virginia, Ohio and North Dakota. We are also engaged in midstream and oil field services operations, primarily in West Virginia and Ohio.
Our business strategy is to create significant value for our stockholders by growing reserves, production volumes and cash flow at an attractive rate of return through a combination of efficient development of our properties and strategic acquisitions and joint ventures, and to selectively monetize properties at opportune times and attractive prices. As part of our strategy:
We have approved a $400 million capital expenditure budget for fiscal year 2014, excluding acquisitions. We have allocated approximately $260 million in the Utica Shale and Marcellus Shale plays, approximately $50 million in the Williston Basin and approximately $90 million (net to our majority interest) for midstream operations. We expect this Appalachian-focused capital program to further drive our future production volumes and reserve additions and enable us to achieve our 2014 projected exit production rate of 35,000 Boe/d;

         We have recently completed in excess of $500 million in divestitures,
          including sales of our Eagle Ford Shale properties in south Texas and
          certain non-core North Dakota properties (see "Business-Our Significant
          Recent Developments");


         We are actively marketing our southern Appalachian Basin properties

located in Kentucky and Tennessee, which we refer to as Magnum Hunter Production, or MHP, and our Canadian properties located in Saskatchewan and Alberta pursuant to a plan to divest those assets adopted in September 2013. We anticipate completing the Canadian divestiture in the second quarter of 2014 and the southern Appalachian Basin divestiture in the second half of 2014. We have reclassified the associated assets and liabilities to assets and liabilities held for sale and the operations are reflected as discontinued operations for all periods presented. As a result, we have recorded an impairment expense (net) of $56.7 million relating to the discontinued operations which is recorded in income (loss) from discontinued operations and an expense (net) of $92.4 million to reflect the net assets at their estimated selling prices, less costs to sell, which is recorded in loss on disposal of discontinued operations; and

         We have identified a number of other non-core U.S. upstream properties
          for possible divestiture in 2014 that we believe represent (together
          with the planned southern Appalachian Basin and Canada divestitures
          described above) in excess of $400 million in value.

As a result of our recent and planned divestitures, we are now strategically focused on our Marcellus Shale and Utica Shale plays in the Appalachian Basin in West Virginia and Ohio and our Bakken Shale play in the Williston Basin in North Dakota.
Our capital expenditure budget for fiscal year 2014 is currently (a) $310 million for our core upstream operations, consisting of approximately $260 million for the Marcellus and Utica Shales in West Virginia and Ohio and approximately $50 million for the Williston Basin/Bakken Shale in North Dakota, and (b) $90 million (net to our majority interest) for our midstream operations (excluding, in each case, any budgeted amounts for operations that may be acquired pursuant to acquisitions). We expect that the 2014 capital expenditure budget for our midstream operations will be funded by us and by the third-party equity and non-recourse debt facilities we have obtained for our midstream operations.
Our midstream operations are conducted through our majority-owned subsidiary, Eureka Hunter Holdings. Eureka Hunter Pipeline, a subsidiary of Eureka Hunter Holdings, owns and operates our Eureka Hunter Gas Gathering System. We are also engaged in the business of leasing natural gas treating pants to third-party producers in Texas and other states. We have obtained financing for our midstream operations through an equity purchase commitment from an unaffiliated third party, which also gives us the right to make capital contributions in conjunction with or alongside the capital contributions from the third party, and two separate credit facilities on a non-recourse basis to Magnum Hunter Resources Corporation.


Our midstream pipeline is a strategic asset to the development and delineation of our acreage position in the both the Utica Shale and Marcellus Shale plays. We believe that we have a competitive advantage by being vertically integrated and maintaining control of our natural gas gathering activities. From time to time, we have discussions with strategic companies in our core area of operations and may pursue joint ventures or other strategic transactions with respect to this asset.
Our oil field services operations consist of the ownership and operation of six drilling rigs that are used primarily for vertical section (top-hole) air drilling in the Appalachian Basin for us and third parties. Our fleet of rigs includes a robotic walking drilling rig that can also drill the horizontal sections of wells in the shale plays where we are active. This drilling rig was designed especially for pad drilling with its unique footprint and capability to walk and rotate without being dismantled. Summary of Principal Upstream Properties Appalachian Basin
As of December 31, 2013, our Appalachian Basin properties included approximately 531,590 gross (461,341 net) acres, located primarily in the Marcellus Shale, Utica Shale and southern Appalachian Basin. At December 31, 2013, proved reserves attributable to our Appalachian Basin properties were 53.4 MMBoe on an SEC basis, of which 26% were oil and liquids and 57% were classified as proved developed producing. As of December 31, 2013, our Appalachian Basin properties included approximately 3,866 gross (2,745.6 net) productive wells, of which we operated approximately 83%.
Williston Basin
As of December 31, 2013, our Williston Basin properties included approximately 418,716 gross (180,153 net) acres. As of December 31, 2013, proved reserves attributable to our Williston Basin properties were 20.8 MMBoe on an SEC basis, of which 94% were oil and natural gas liquids and 44% were classified as proved developed producing. As of December 31, 2013, our Williston Basin properties included approximately 342 gross (138.8 net) productive wells, of which we operated approximately 27%.
Summary of Midstream Operations
As of December 31, 2013, our Eureka Hunter Gas Gathering System consisted of approximately 100 miles of 20-inch and 16-inch mainline, of which approximately 86 miles is currently active, located in northwestern West Virginia and crossing into Ohio, in the Marcellus Shale and Utica Shale. Summary of Oil Field Services Operations As of December 31, 2013, we owned and operated five Schramm T200XD drilling rigs and one Schramm T500XD drilling rig. The drilling rigs are used for our Appalachian Basin operations and to provide drilling services to third parties also in the Appalachia Basin. The Schramm T200XD drilling rigs primarily drill the top-holes of wells in preparation for larger drilling rigs, such as the Schramm T500XD, which drill the horizontal sections of the wells. 2013 Highlights and 2014 Outlook
Our activities in 2013 included significant divestitures in excess of $500 million, including sales of our Eagle Ford Shale properties in south Texas and certain non-core North Dakota properties. Following such divestitures, we reallocated our drilling capital expenditure program to focus on oil and liquids rich natural gas projects in the Marcellus Shale and Utica Shale and Williston Basin. As a result of this reallocation and focus on our core areas of operations:

         Our production mix consisted of approximately 57% oil and liquids in
          the fourth quarter of 2013 compared to 44% oil and liquids in the
          fourth quarter of 2012.


         Our production increased 27.2% from 7,740 Boe/d for 2012 to 9,844 Boe/d
          for 2013 as a result of acquisitions in 2012 as well as the continued
          success of our drilling programs in the Marcellus Shale and Williston
          Basin.


         Our revenues from continuing operations increased 72.3%, or $82.9
          million, to $197.6 million in 2013, compared to $114.7 million in 2012
          primarily due to acquisitions in 2012 and an increased focus on oil and
          NGL production in the Marcellus Shale and Williston Basin.

We have approved a $400 million capital budget for fiscal year 2014, excluding acquisitions. The Company intends to spend approximately $260 million in the Utica Shale and Marcellus Shale plays, approximately $50 million in the Williston Basin and approximately $90 million (net to our majority interest) for midstream activities at Eureka Hunter Pipeline. The contemplated capital budget includes the acquisition of mineral leases in both the Utica Shale and Marcellus Shale plays.
The Company's drilling capital in 2014 will be primarily concentrated on the delineation and development of its combined 180,000 net mineral acres located in the Utica and Marcellus Shale plays of Ohio and West Virginia. Specifically, the Company's development plan will be to further delineate its acreage position located in Monroe, Noble, and Washington Counties, Ohio and in Tyler, Richie and Wetzel Counties, West Virginia. In the Appalachian Basin, we intend to operate two to three drilling rigs during 2014, and anticipate drilling approximately 25 gross (19 net) horizontal wells in the Utica Shale and Marcellus Shale


plays, with the wells coming online throughout the year. We expect to process our liquids rich gas production from the Utica Shale and Marcellus Shale plays at the Mobley Processing Plant (or other anticipated closer gas processing facilities) using our gathering capacity on our Eureka Hunter Gas Gathering System.
In the Williston Basin, we expect to participate predominantly as a non-operated working interest owner and drill approximately 15 to 20 gross (6 to 8 net) wells located primarily in the Ambrose Field in northwest Divide County, North Dakota. We believe this area has the potential for the highest rate of return in our current inventory of properties in the Williston Basin. We are focusing our efforts on developing the Three Forks Sanish and Middle Bakken zones in this area.
The 2014 capital budget of $400 million is expected to be funded from a combination of internally-generated cash flow, capital market related funding, anticipated borrowing capacity under our revolving credit facility associated with anticipated borrowing base increases, anticipated borrowings under Eureka Hunter Pipeline's two existing credit facilities (or under an expected new senior secured credit facility for Eureka Hunter Pipeline, currently being negotiated, that would replace the two existing credit facilities) and proceeds from non-core asset sales. We have targeted non-core asset sales, which we believe represent in excess of $400 million in aggregate value, for possible divestiture in 2014. These potential divestitures would allow us to significantly expand our activities in our core areas of operations in the Utica and Marcellus Shale plays while improving our financial flexibility and balance sheet. It is possible that such sales could lead to us recognizing losses on disposal, and such losses could be significant.

Recent Events
Eagle Ford Properties Sale
On April 24, 2013, we sold our core properties in the oil window of the Eagle Ford Shale in Gonzales and Lavaca Counties, Texas to an affiliate of Penn Virginia for a total contract purchase price of $401 million, consisting of $361 million in cash (before customary purchase price adjustments) and $40 million in Penn Virginia common stock. At closing, we received $422.1 million in cash and stock, based on initial cash purchase price adjustments and the market price of the Penn Virginia common stock on the closing date. The cash portion of the purchase price is subject to final settlement of the purchase price adjustment amounts, and we estimate that the final adjustment will result in an obligation to Penn Virginia of $22 million to $33 million, net of taxes. See "Item 3. Legal Proceedings-Eagle Ford Properties Sale Final Settlement." We used the cash portion of the purchase price to repay all then outstanding borrowings under our revolving credit facility and for general corporate purposes. The properties sold to Penn Virginia included approximately 19,000 net Eagle Ford Shale leasehold acres, and our operating and non-operating leasehold working interests in certain existing wells, in Gonzales and Lavaca Counties, Texas. The effective date of the transaction was January 1, 2013. Sale of Non-Core North Dakota Assets
On September 27, 2013, we sold our non-operated working interests in certain oil and natural gas properties located in Burke County, North Dakota, to Oasis for a contract purchase price of $32.5 million in cash (before customary purchase price adjustments). The effective date of the transaction was July 1, 2013. On December 30, 2013, we sold our North Dakota waterflood properties located in Burke, Renville, Bottineau and McHenry Counties, North Dakota to Enduro for a contract purchase price of $45 million in cash (before customary purchase price adjustments) and final determination of the customary adjustments to the purchase price will be made by the parties approximately 120 days after closing. The effective date of the transaction was September 1, 2013. Sale of Remaining Eagle Ford Shale and Pearsall Shale Assets On January 28, 2014, we sold substantially all of our remaining oil and natural gas properties in the Eagle Ford Shale and Pearsall Shale in south Texas to an affiliate of NSE for a total contract purchase price of $24.5 million, consisting of $15 million in cash (before customary purchase price adjustments) and $9.5 million in ordinary shares of NSE valued. The effective date of the transaction was December 1, 2013.
MNW Leasehold Acquisition
On August 12, 2013, we entered into an asset purchase agreement with MNW. MNW represents an informal association of various land owners, lessees of mineral acreage and sublessees of mineral acreage who own or have rights in mineral acreage located in Monroe, Noble and/or Washington Counties, Ohio. Pursuant to the agreement, we agreed to acquire from MNW up to 32,000 net mineral acres, including currently leased and subleased acreage, located in Monroe, Noble and/or Washington Counties, Ohio, over a period of time, in staggered closings, subject to the satisfaction of certain closing conditions, including our right to receive satisfactory title to the acreage. As of January 31, 2014, we had acquired 6,129 net acres pursuant to MNW closings. On December 30, 2013, a lawsuit was filed against us, MNW and others asserting certain claims relating to the acreage covered by our agreement with MNW. We believe the claims asserted against us in the lawsuit are without merit. However, the


claims asserted in the lawsuit may impair our right to receive satisfactory title to the acreage; therefore, any future MNW closings may be delayed until this matter is resolved. See "Item 3. Legal Proceedings-Dux Litigation." Expansion of Eureka Hunter Gas Gathering System In 2013, we expanded our Eureka Hunter Gas Gathering System, completing the construction of approximately 22 miles of additional pipeline in Monroe County, Ohio, for a total of over 100 miles of completed pipeline at January 31, 2014. In January 2013, we extended our Pursley lateral section of the pipeline (which is a 20-inch lateral section extending north from our main line) under the Ohio River from Wetzel County, West Virginia into Monroe County, Ohio. In December 2013, we completed our Tippens lateral section of the pipeline, which is a 20-inch lateral section that extends approximately 11 miles west-northwesterly from our Ohio river crossing near Sardis, Ohio, allowing for the gathering of dry Utica Shale gas production from multiple well pads, including our Stalder pad. We continue to construct the pipeline further into Ohio to support the continued development of our Marcellus Shale and Utica Shale acreage in Ohio, as well as acreage of third party producers. Equity Financings
We raised cash in the total amount of $50.8 million in net proceeds, after offering discounts, commissions and placement fees, but before other offering expenses, through equity transactions from January 1, 2013 through December 31, 2013. Those transactions included:

         $9.6 million in net proceeds from issuances of our Series D Preferred
          Stock, at an average gross sales price of $44.39 per share;


         $0.6 million in net proceeds from issuances of Depositary Shares
          representing our Series E Preferred Stock, at an average gross sales
          price of $24.24 per Depositary Share;


         $35.3 million in net proceeds from issuances of Series A Preferred
          Units of Eureka Hunter Holdings; and


         $5.4 million in net proceeds from issuances of our common stock upon
          exercise of stock options.

We may continue selling both preferred and common equity in the future depending on our working capital needs, capital expenditure program, acquisition activities, and the condition of the capital markets. Until August 2014, approximately twelve months after the date on which we became current with our SEC reporting obligations, we are ineligible to use abbreviated and less costly SEC filings, such as the SEC's Form S-3 registration statement, to register our securities for sale. Further, during such period, we will be unable to use our existing shelf registration statement on Form S-3 or conduct "at-the-market", or ATM, offerings of our equity securities, which ATM offerings we had conducted on a regular basis with respect to our preferred stock prior to our late SEC filings. We may use Form S-1 to register a sale of our securities to raise capital or complete acquisitions, but doing so would likely increase transaction costs and adversely impact our ability to raise capital or complete acquisitions in an expeditious manner.


Results of Operations
Years ended December 31, 2013, 2012 and 2011 The following table sets forth summary information regarding oil, natural gas and natural gas liquids revenues, production, average product prices and average production costs and expenses for the last three fiscal years. The results of our Eagle Ford Shale operations, MHP operations and Canadian operations have been excluded from the amounts below because they are reflected as discontinued operations for all years presented. See the "Glossary of Oil and Natural Gas Terms" section of this annual report for explanations of the terms used below.

                                                  Years Ended December 31,
                                            2013              2012            2011
                                               (in thousands except per unit)
Oil and gas revenue and production
Revenues
Oil                                  $    140,426         $    77,172     $    37,520
Gas                                        41,867              36,657          21,206
NGL                                        15,306                 830               -
Total oil and gas sales              $    197,599         $   114,659     $    58,726
Production
Oil (MBbl)                                  1,564                 939             430
Gas (MMcf)                                 10,352              11,212           4,574
NGL(MBoe)                                     304                  25               -
Total MBoe                                  3,593               2,833           1,192
Boe/d                                       9,844               7,740           3,266

Average prices (U.S. Dollars)
Oil (per Bbl)                        $      89.79         $     82.19     $     87.26
Gas (per Mcf)                        $       4.04         $      3.27     $      4.64
NGL (per Boe)                        $      50.35         $     33.20     $         -
Total average price (per
Boe)                                 $      55.00         $     40.47     $     49.27

Costs and expenses (per Boe)
Lease operating                      $      15.02         $      9.47     $     12.58
Severance tax and marketing          $       4.93         $      2.77     $      4.48
Exploration                          $      27.09         $     27.61     $      2.19
Impairment of properties             $       2.77         $      1.33     $         -
Depletion, depreciation,
amortization and accretion           $      27.61         $     21.08     $     19.50
General and administrative (1)       $      20.99         $     18.87     $     45.60

Other segments (in thousands)
Midstream and marketing operations
segment revenue                      $     69,306         $    15,692     $     1,990
Midstream and marketing operations
segment expense                      $     72,823         $    17,419     $     2,512
Oilfield services segment revenue    $     21,527         $    13,552     $     9,426
Oilfield services segment expense    $     21,610         $    12,405     $     9,320


_________________


(1) General and administrative expense includes: (i) acquisition related expenses of $2.8 million ($0.77 Boe) in 2013, $4.7 million ($1.66 Boe) in 2012, and $8.9 million ($7.47 Boe) in 2011; and (ii) non-cash stock compensation of $13.6 million ($3.79 Boe) in 2013, $15.7 million ($5.54 Boe) in 2012, and $25.1 million ($21.02 Boe) in 2011.


Years ended December 31, 2013 and 2012
Oil and natural gas production. Production increased by 26.8%, or 760 MBoe, to 3,593 MBoe for the year ended December 31, 2013 compared to 2,833 MBoe for the year ended December 31, 2012. Our average daily production was 9,844 Boe/d during 2013, representing an overall increase of 27.2%, or 2,104 Boe/d, compared to 7,740 Boe/d for 2012. The increase in production in 2013 compared to 2012 is primarily attributable to acquisitions during 2012 as well as organic growth through the Company's expanded drilling program in the Williston and Appalachian Basins which focused mainly on oil and NGL. Production for 2013, on a Boe basis, was 52.0% oil and NGL and 48.0% natural gas compared to 34.0% oil and NGL and 66.0% natural gas for 2012. The increase in production during the year ended December 31, 2013 was offset by the shut-in of approximately 2,061 Boe/d of Marcellus Shale production. In January 2013, the Company experienced production shut-ins due to complications in bringing our production online after the Mobley Processing Plant was completed in late 2012. The Company experienced higher than expected NGL present in its Marcellus production which necessitated that Eureka Hunter Pipeline implement a pigging process on its gathering lines. Once the pigging process was implemented, the Company was also further delayed as new air permits for compression facilities were required from the State of West Virginia. The gathering issues related to the Marcellus production shut-in were resolved in May 2013. In addition, our production for the year ended December 31, 2013 was also adversely affected by the shut down of the Mobley Processing Plant from August 2013 to early October 2013 as a result of a break in a MarkWest natural gas liquids pipeline. The impact of the Mobley Processing Plant shut down resulted in a decrease in our daily production by approximately 1,917 Boe/d for the year ended December 31, 2013. The Company also experienced approximately 144 Boe/d of curtailments for the year ended December 31, 2013 at its Ormet Pad location as a result of the continued build out of midstream infrastructure and liquids handling equipment. These production shut-ins were largely natural gas and NGL, thus the impact on the Company's cash flow was substantially less than any reduction in our oil volumes.
Oil and natural gas sales. Oil and natural gas sales from continuing operations increased 72.3%, or $82.9 million, for the year ended December 31, 2013 to $197.6 million from $114.7 million for the year ended December 31, 2012. The increase in oil and gas sales principally resulted from increases in our oil and natural gas production as a result of acquisitions and expanded drilling completed throughout the year in our unconventional resource plays. The average price we received for our production increased from $40.47 Boe to $55.00 Boe, or 35.9% primarily due to higher natural gas prices. The $82.9 million increase in revenues comprised an increase of approximately $30.8 million attributable to increased production volumes of 760 MBoe, and an increase of $52.2 million due to an increase in price of $14.53 Boe produced. The prices we receive for our products are generally tied to commodity index prices. We periodically enter into commodity derivative contracts in an attempt to offset some of the variability in prices (see the discussion of commodity derivative activities below).
Other income. Other revenues, consisting primarily of regulated retail gas billing revenues from the Appalachian region of the U.S. Upstream segment, increased by $3.4 million for the year ended December 31, 2013.
Lease operating expense. Our lease operating expenses, or LOE, increased $27.1 million, or 101.1%, for the year ended December 31, 2013 to $54.0 million ($15.02 Boe) from $26.8 million ($9.47 Boe) for the year ended December 31, 2012. The increase in LOE attributable to increased LOE/Boe was $19.9 million, and the increase related to increased volume produced was $7.2 million. Of the increase in LOE/Boe costs, $6.4 million was related to higher LOE costs in the Appalachian Basin due in part to an increased percentage of our production as NGL which generally have higher LOE/Boe than natural gas due to higher processing fees, $5.8 million was due to higher Appalachian Basin gas transportation charges, and $1.3 million was due to increased non-recurring workover and well site reclamation costs. Other costs increasing LOE/Boe include $3.7 million from the Williston Basin higher contribution to total production from higher cost stripper and non-operated properties along with $3.1 million of Williston Basin electrification implementation costs.
Severance taxes. Our severance taxes and marketing increased by $9.9 million, or . . .

  Add MHR to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for MHR - All Recent SEC Filings
Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.