Magnum Hunter Provides First Quarter 2012 Company Wide Operational Update

HOUSTON, TX--(Marketwire - Apr 16, 2012) - Magnum Hunter Resources Corporation (NYSE: MHR) (NYSE Amex: MHR-PrC) (NYSE Amex: MHR-PrD) (the "Company" or "Magnum Hunter") announced today an operational update on each of the Company's three upstream unconventional resource plays for the first quarter of 2012 which include (i) the Eagle Ford Shale, (ii) the Williston Basin, and (iii) the Appalachia/Marcellus/Utica Shale. Additionally, the Company has also provided an operational update for the Company's midstream division, Eureka Hunter Pipeline, LLC ("Eureka Hunter").

Magnum Hunter achieved an average production rate of 12,600 barrels of oil equivalent per day ("Boepd") during the first quarter of 2012. This production rate represents a 379% increase from the first quarter 2011 production and a 38% increase from the prior quarter (fourth quarter 2011) average production number of 9,124 Boepd. This production increase is due primarily to the drilling and completion success achieved in each of the Company's operating regions.

Proved Reserves

Magnum Hunter's total proved reserves increased by 5.7 million barrels of oil equivalent (Boe), or 13%, to 50.7 million Boe (54% crude oil & ngl; 49% proved developed producing) as of March 31, 2012 as compared to 44.9 million Boe (48% crude oil & ngl; 51% proved developed producing) at December 31, 2011. This reserve growth of almost 2 million barrels per month during the first quarter of 2012 continues the trend experienced during the fourth quarter of last year. These new proved reserve additions were based upon an internal evaluation.

Eagle Ford

During the first quarter of 2012, Eagle Ford Hunter, Inc. ("Eagle Ford Hunter") completed and placed on production three gross operated wells (1.26 net) and four gross non-operated (2.0 net) wells in the Eagle Ford Shale. Additionally, Eagle Ford Hunter was also in the process of fracture stimulating one gross (.45 net) operated well during the first quarter which has been subsequently placed on production in April 2012. All four wells had an initial production rate in excess of 1,325 Boepd separately in their initial one-day test period, with one of the wells testing over 2,250 Boepd. Highlights for Eagle Ford Hunter include:

• The Leopard Hunter 1H was drilled and cased to a measured depth of 16,936 feet (horizontal lateral length of 6,708 feet), fraced with 25 stages and placed on production January 8, 2012. The 24 hour flowing initial production rate was 1,333 Boepd on an 18/64" choke with 1,700 psi FCP. Magnum Hunter operates the Leopard Hunter 1H and owns a 50% working interest.
  
  
• The Gonzo North 2H which was drilled and cased to a measured depth of 15,827 feet (horizontal lateral length of 6,120 feet), fraced with 24 stages and placed on production February 12, 2012. The 24 hour flowing initial production rate was 1,336 Boepd on a 20/64" choke with 1,650 psi FCP. Magnum Hunter operates the Gonzo North 2H and owns a 50% working interest.
  
  
• The Hawg Hunter 1H which was drilled and cased to a measured depth of 17,050 feet (horizontal lateral length of 6,214 feet), fraced with 23 stages and placed on production March 30, 2012. The 24 hour flowing initial production rate ("IP") was 2,289 Boepd on an 18/64" choke with 2,850 psi FCP. Magnum Hunter operates the Hawg Hunter 1H and owns a 26% working interest.
  
  
• The Oryx Hunter 2H which was drilled and cased to a measured depth of 16,780 feet (horizontal lateral length of 6,277 feet), fraced with 21 stages and placed on production April 3, 2012. The 24 hour flowing initial production rate was 1,545 Boepd on an 18/64" choke with 2,700 psi FCP. Magnum Hunter operates the Oryx Hunter 2H and owns a 45% working interest.

In addition to the Company's operated wells, Eagle Ford Hunter also participated in four new non-operated wells with its joint venture partner, Hunt Oil Company of Dallas, Texas. These wells were recently completed and are currently flowing back after fracture stimulation treatment. These new wells were all stimulated with 15-17 stages of frac. Eagle Ford Hunter owns a 50% working interest in each of the following new wells:

Well Name	Choke Size	Casing Pressure	Current Production
JP Ranch D #4H	17/64"	FCP 1575#	920 Boepd
JP Ranch C #3H	17/64"	FCP 780#	520 Boepd
JP Ranch #1H	19/64"	FCP 420#	483 Boepd
Borchers #1H	14/64"	FCP 400#	167 Boepd

Mr. H.C. "Kip" Ferguson, President of Eagle Ford Hunter, commented, "We continue to see improvement in our well-by-well production profile over the last six months. We are continuing to form new 600+ acre units and we are holding the bulk of our acreage position in both Gonzales and Lavaca Counties by existing production. Our wells have continued to exceed our initial expectations. New wells have shown improvement in IP24, 30 and 60 day production rates as a result of our improved fracing techniques, drilling practice of maintaining a narrow target window 'in zone' and the combination of longer laterals and more frac stages per lateral to better efficiently treat the horizontal section. Since we have implemented these changes, our average IP24 rates have averaged more than 1,650 Boepd with a high test rate of 2,289 Boepd. We are fortunate to hold one of the better mineral lease acreage positions in the entire Eagle Ford play."

Williston Basin

Tableland
The Tableland core field production continued to benefit from the implementation of our re-designed fracture stimulation technique. Initial well productivity (IP24) averaged 573 barrels of oil per day ("Bopd"). IP30 and IP60 rates increased to 273 and 255 Bopd, respectively. Of the three wells drilled this quarter, two were drilled from a dual pad site, the first of a new program being utilized to reduce the development footprint and costs through efficient rig moves and back-to-back completions. Electrification of the newly expanded Tableland Field Battery, in conjunction with the addition of 3,000 barrels of oil storage and increased fluid handling, has further reduced current operating costs. All wells completed this quarter have been pipelined into the expanded facility.

Highlights for the Tableland Field include:

• 9-2-1-10W2M, a 100% WI operated well was drilled to a measured depth of 12,140 feet including 3,891 feet of horizontal lateral section. The well was fracture stimulated with 24 - 22 ton stages and placed on production February 4, 2012. The 24 hour flowing initial production rate was 236 Bopd.
  
  
• 5-15-1-10W2M, a 100% WI operated well was drilled to a measured depth of 11,716 feet including 3,973 feet of horizontal lateral section. The well was fracture stimulated with 26 - 22 ton stages and placed on flow back March 24, 2012. The 24 hour flowing initial production rate was 605 Bopd.
  
  
• 8-14-1-10W2M, a 100% WI operated well was drilled to a measured depth of 12,140 feet including 4,442 feet of horizontal lateral section. Fracture stimulated with 27 - 22 ton stages and placed on flow back March 30, 2012. The 24 hour flowing initial production rate was 810 Bopd.

North Dakota
First quarter activities in Divide and Burke Counties, North Dakota included spudding 16 gross wells and 1.1 net wells, and completing 16 gross wells and 1.4 net wells. There are 10 gross wells and 0.6 net wells drilled waiting on completion. Initial Production Rates continue to increase, with 16 new wells having an average 24-hour initial production rate of 852 Bopd. Operations benefitted from optimal weather conditions and increased workover activity, which resulted in reduced behind pipe inventory and increased production.

Highlights for North Dakota include:

							IP7	IP30
							7 Day	30 Day
		MHR	Lateral	Frac	Producing	IP24hr	Average	Average
	County	W.I.%	Length	Stages	Formation	boepd	boepd	boepd
Blue Jay 32-29-163-95	Divide	11.4	2 Mile	23	Bakken	852	455	346
Olson 15-22-162-100	Divide	11.5	2 Mile	15	TFSanish	409	301	220
Lark 29-32-162-96	Divide	9.2	2 Mile	26	TFSanish	636	417	350
Stork 20-17-162-96	Divide	10	2 Mile	20	TFSanish	621	515	358
Edna 14-23-160-100	Divide	8.3	2 Mile	15	TFSanish	422	354	335
Hauge 28-33-163-99	Divide	1.9	2 Mile	20	TFSanish	897	782	598
Calistoga 18-7-161-92	Burke	29.8	2 Mile	26	Bakken	684	428	345
Pelican 26-35-162-96	Divide	10	2 Mile	30	TFSanish	622	451	328
Thomte 8-5-163-99	Divide	10	2 Mile	30	TFSanish	1525	1264	1139
Bel Aire 14-23-163-99	Divide	7.2	2 Mile	30	TFSanish	1212	905	790
Titan 36-25-164-99	Divide	10	2 Mile	30	TFSanish	1203	1011	818
Sonoma 19-30-161-92	Burke	21.7	2 Mile	26	Bakken	607	398	302
Marauder 13-24-162-98	Divide	10.2	2 Mile	26	TFSanish	900	765	591
Nomad 6-7-163-99	Divide	10.9	2 Mile	26	TFSanish	1188	1166
Montclair 1-12-163-99	Divide	10	2 Mile	30	TFSanish	869	764
Dorado 14-23-162-98	Divide	10	2 Mile	30	TFSanish	988	886

Williston Basin (Operated)
On March 30, 2012, Williston Hunter closed on the previously announced acquisition of oil and gas properties owned by Eagle Operating Inc. ("Eagle"). The acquisition includes all of Eagle's operating working interest ownership in oil and gas mineral leases and 191 existing wells on approximately 15,500 gross mineral acres located within four counties of the Williston Basin. Current net production from the acquisition is approximately 350 barrels of oil equivalent per day. Total proved reserves attributable to the acquired properties are estimated at 2.1 million barrels of oil equivalent. Williston Hunter now operates and owns 95% working interest in these oil and gas properties, up from 47% working interest prior to the acquisition. Williston Hunter intends to begin development of the Middle Bakken and Three Forks Sanish formations over this land position in 2012.

Gas Conservation
On April 2, 2012, Williston Hunter, along with its operating partners, executed an agreement with a third-party midstream company to gather and process natural gas and natural gas liquids in Divide County, North Dakota which is currently being flared. Projected to be online sometime during the first quarter of 2013, this project will add significant production, cash flow and reserves.

Mr. Glenn Dawson, President of Williston Hunter, commented: "In the first quarter of 2012, we continued to focus on organic growth through the drill bit and optimizing our hydraulic fracing technique. Initial Production rates of 42 API oil from new wells in Saskatchewan and North Dakota continue to improve. This, combined with our strategic acquisition, is a positive step-change for Williston Hunter as we move into a much stronger operating position. Magnum Hunter's in-house reservoir engineers and geologists have identified net resource potential of 114 Million BOE over the Company's 85,000 acre Williston Basin position."

Appalachia

During the first quarter of 2012, the Appalachian Basin Division had four wells drilled awaiting completion. Magnum Hunter completed one of the wells in April in order to obtain test data, and has decided to delay completion of the other three wells until the fourth quarter of this year, when gas processing facilities are projected to be completed and in service. This new area promises "Magnum Rich" gas once processing is established later this year.

• The Spencer Unit #1115, located in the Middleborne Area of Tyler County, West Virginia, was drilled to a measured depth of 10,881 feet (horizontal lateral length of 3,900 feet) and is a 100% working interest owned well by Triad Hunter. The well was fraced with 16 stages and tested at a 24-hour initial flowing production rate of 7.028 million cubic feet equivalent per day ("MMcfepd") (5.01 MMcf per day of natural gas and 335 barrels of condensate per day) on an adjustable choke with 1,850 psi FCP. The well is still in its clean up phase, and the Company plans step rate testing over next week, which will most likely establish the peak 24-hour initial flowing production rate. In addition to the 335 barrels of condensate reported above, modeling from gas analysis calculates another 316 barrels per day of natural gas liquids would be recovered with cryogenic processing, for a total of 651 barrels per day of liquids, or a yield of 130 barrels per MMcf. First sales during flowback began April 11, 2012.

In addition, the Company has drilled and cased one of its four planned wells in the Arch Field, to test the Weir formation, in its Southern Appalachia position. Surface casing has been set on the three remaining wells, and one is currently drilling the lateral section. All four wells are scheduled for completion during the second Quarter of 2012.

Mr. Jim Denny, President of the Appalachian Basin, commented, "Although Magnum Hunter has delayed the majority of its capital expenditures in the Appalachian division until the latter part of the year, we are excited about the recent production results from the Spencer #1150 well. Given the high condensate and high btu of over 1300, we believe this to be a new 'super rich' area for our Company which we have coined 'Magnum Rich.' We continue to evaluate the Utica Shale over in Eastern Ohio after closing on an acquisition of an additional 12,186 net mineral acres in February 2012. We anticipate drilling several test wells to this formation on our leasehold position prior to year-end."

Eureka Hunter

• Monetization of Eureka Hunter completed at a value in excess of $400 million
• Acquired a gas treatment company for $58 million - moving towards a fully integrated MLP
• Construction continues to be within budget and ahead of schedule
• Deployed initial JT-Unit which has begun separating and selling heavy liquids

The first quarter of 2012 was extremely active for the company's midstream division including a partial monetization of pipeline equity in Eureka Hunter, an acquisition of a natural gas treating and processing company, increased contracted pipeline throughput volumes that will exceed 100,000 mmbtus per day in 2014, began construction on the final pipeline laterals necessary to deliver gas for processing and have permitted for extensions of Eureka across the Ohio River to gather Marcellus and anticipated Utica volumes in Ohio.

Eureka Hunter monetized approximately 28% of its equity ownership in a transaction with ArcLight Capital Partners, LLC for an initial investment of $106.8 million and the ability to draw down an additional $93.2 million, based on certain terms and conditions and approval of Eureka Hunter, which would further fund Eureka's pipeline expansion growth plans. Magnum Hunter retained $359 million of value in Eureka Hunter units and cash, which is equivalent to $2.71 per Magnum Hunter common share.

Eureka Hunter acquired TransTex Gas Services, LP ("TransTex") on April 2, 2012, for $58.5 million in cash and Eureka Hunter common units. TransTex is headquartered in Houston, Texas, and contracts natural gas treating, processing and well head production equipment to the energy industry. TransTex owns a fleet of amine treating plants as well as JT and refrigeration processing plants that are deployed in Texas, Oklahoma, Arkansas, Kansas and West Virginia to capitalize on liquids rich gas and associated gas on oil shale drilling areas. The acquisition of TransTex brings additional cash flow as well as positive earnings to Eureka and substantially broadens its midstream capabilities to include not only gathering but also gas treating and processing.

Eureka Hunter completed construction of a 4 mile, 16-inch lateral into Doddridge County, WV, that could eventually be extended to the MarkWest Sherwood Plant. Eureka Hunter also completed phase 1 of the 20-inch Pursley Lateral in Tyler County, WV, to gather gas for Triad Hunter from the new Spencer lease wells. It is expected that the Pursley Lateral will be extended across the Ohio River into Ohio within the next few months.

Magnum Hunter Chairman Comments

Mr. Gary C. Evans, Chairman of the Board and Chief Executive Officer of Magnum Hunter, commented, "With two of our three core resource plays being crude oil, we fortunately have the capability of moving our capital program around to somewhat mitigate the extremely low levels of current natural gas prices that the entire energy industry is experiencing today. That is exactly the initiative your Board of Directors and management team began in January of this year. We will continue that plan for at least the next two quarters as we watch and monitor the unprecedented natural gas storage situation. We delivered on our promise to establish a new market value on our midstream investment in Eureka Hunter which we accomplished with the successful closings of two separate transactions that value this subsidiary at over $400 million in enterprise value. Our leasehold position in the Utica Shale continues to expand with transactions closed during the first quarter that totaled over 12,000 acres net to Magnum Hunter's interest. The Company now has accumulated over 17,000 net acres that are presently prospective for the Utica Shale. Due to the combination of newly completed wells and associated company-wide production rates being experience today, we now have the confidence to once again increase our 2012 exit rate guidance to 17,000 Boe per day."

About Magnum Hunter Resources Corporation

Magnum Hunter Resources Corporation and subsidiaries are a Houston, Texas based independent exploration and production company engaged in the acquisition, development and production of crude, natural gas and natural gas liquids, primarily in the states of West Virginia, Kentucky, Ohio, Texas, North Dakota and Saskatchewan, Canada. The Company is presently active in three of the most prolific unconventional shale resource plays in North America, namely the Marcellus Shale, Utica Shale, Eagle Ford Shale and Williston Basin/Bakken Shale.

For more information, please view our website at http://www.magnumhunterresources.com/

Forward-Looking Statements

The statements and information contained in this press release that are not statements of historical fact, including all estimates and assumptions contained herein, are "forward looking statements" as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward looking statements include, among others, statements, estimates and assumptions relating to our business and growth strategies, our oil and gas reserve estimates, estimates of oil and natural gas resource potential, our ability to successfully and economically explore for and develop oil and gas resources, our exploration and development prospects, future inventories, projects and programs, expectations relating to availability and costs of drilling rigs and field services, anticipated trends in our business or industry, our future results of operations, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and gas industry and the impact of environmental and other governmental regulation. Forward-looking statements generally can be identified by the use of forward-looking terminology such as "may", "will", "could", "should", "expect", "intend", "estimate", "anticipate", "believe", "project", "pursue", "plan" or "continue" or the negative thereof or variations thereon or similar terminology. These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among other, the following: adverse economic conditions in the United States and globally; difficult and adverse conditions in the domestic and global capital and credit markets; changes in domestic and global demand for oil and natural gas; volatility in the prices we receive for our oil and natural gas; the effects of government regulation, permitting, and other legal requirements; future developments with respect to the quality of our properties, including, among other things, the existence of reserves in economic quantities; uncertainties about the estimates of our oil and natural gas reserves; our ability to increase our production and oil and natural gas income through exploration and development; our ability to successfully apply horizontal drilling techniques and tertiary recovery methods; the number of well locations to be drilled, the cost to drill, and the time frame within which they will be drilled; drilling and operating risks; the availability of equipment, such as drilling rigs and transportation pipelines; changes in our drilling plans and related budgets; and the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. Readers are cautioned not to place undue reliance on forward-looking statements, contained herein, which speak only as of the date of this document. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, including estimates, whether as a result of new information, future events, or otherwise. We urge readers to review and consider disclosures we make in our public filings made from time to time with the Securities and Exchange Commission that discuss factors germane to our business, including our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011. All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

The U.S. Securities and Exchange Commission ("SEC") requires oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. In this press release, we use the term "resource potential" to describe the Company's internal estimates of volumes of oil and natural gas that are not classified as proved reserves but are potentially recoverable through exploratory drilling or additional drilling or recovery techniques. This is a broader description of potentially recoverable volumes than probable and possible reserves, as defined by SEC regulations. The "resource potential" disclosed in this press release includes both possible reserves and potentially recoverable volumes that cannot be classified as proved, probable or possible reserves. Estimates of unproved resources are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the Company. We believe our estimates of unproved resources and future drillsites are reasonable, but such estimates have not been reviewed by independent engineers. Estimates of unproved resources may change significantly as development provides additional data, and actual quantities that are ultimately recovered may differ substantially from prior estimates.