Magnum Hunter Resources Reports Fourth Quarter and Full Year 2013
Financial and Operating Results
HOUSTON, TX--(Marketwired - Feb 24, 2014) - Magnum Hunter
Resources Corporation (NYSE: MHR) (NYSEMKT: MHR.PRC) (NYSEMKT:
MHR.PRD) (NYSEMKT: MHR.PRE) (the "Company" or "Magnum Hunter")
announced today financial and operating results for the three
months and twelve months ended December 31, 2013. The Company plans
to file its Form 10-K for the year ended December 31, 2013 with the
Securities and Exchange Commission tomorrow, Tuesday, February 25,
2014. Highlights of the Company's financial and operating results
include the following:
- Oil and gas revenues increased 64% to $59.4 million for the
fourth quarter of 2013, compared with revenues of $36.1 million for
the fourth quarter of 2012
- Midstream and marketing revenues increased 595% to $18.2
million for the fourth quarter of 2013, compared with revenues of
$2.6 million for the fourth quarter of 2012
- Adjusted EBITDAX(a) for the fourth quarter of 2013 and full
year 2013 were $37.0 million and $112.4 million, an increase of 54%
and 48%, respectively
- Adjusted net loss(a) of ($0.14) per diluted share is reported
for the fourth quarter of 2013
- Production of 11,298 BOEPD and adjusted production(b) of 15,386
BOEPD for the fourth quarter of 2013
- Form 10-K to report remediation of 11 of the 14 previously
identified material weaknesses in internal controls over financial
reporting
- All derivatives contracts for 2014 natural gas production
converted from collars to fixed price swaps and 20,000 MMBtu/d of
fixed price swaps added for calendar year 2015 natural gas
production
- Executed on $69.5 million of non-core asset sales over the last
60 days with up to $400 million of additional non-core asset sales
targeted in fiscal 2014
- Current throughput on Eureka Hunter Pipeline System of 171,634
MMBtu/d with a recent peak throughput rate of 198,000 MMBtu/d
(a) See Non-GAAP Financial Measures and Reconciliations below
(b) Adjusted production includes 2,118 BOEPD of actual
production from discontinued operations, and, on a pro forma basis,
shut-in and curtailed production of 1,970 BOEPD in Appalachia
Financial and Operating Results for the Three Months Ended
December 31, 2013
Magnum Hunter reported an increase in oil and gas revenues of
64% to $59.4 million for the three months ended December 31, 2013,
compared with $36.1 million for the three months ended December 31,
2012. The increase in oil and gas revenues resulted principally
from (i) increases in the Company's oil and natural gas production
as a result of prior acquisitions and expanded drilling efforts in
the Company's unconventional resources plays this past year and
(ii) higher average realized commodity prices for the period.
Midstream and marketing revenues also increased to $18.2 million
for the three months ended December 31, 2013, or 595%, from $2.6
million for the three months ended December 31, 2012. The increase
in midstream and marketing revenues was due primarily to (i)
increased throughput volumes on the Eureka Hunter Pipeline System,
(ii) increased utilization of TransTex Hunter, LLC's gas treating
and processing equipment and (iii) increased third-party gas
marketing volumes.
The Company reported a net loss of ($61.2) million attributable
to common shareholders, or ($0.36) per basic and diluted common
shares outstanding, for the three months ended December 31, 2013,
compared with a net loss of ($87.2) million, or ($0.52) per basic
and diluted common shares outstanding, for the three months ended
December 31, 2012. When adjusted for a combination of non-cash and
non-recurring gains on asset sales and expenses, the Company's
adjusted net loss attributable to common shareholders for the three
months ended December 31, 2013 was ($0.14) per basic and diluted
common shares outstanding (see Non-GAAP Financial Measures and
Reconciliations below).
For the three months ended December 31, 2013, Magnum Hunter's
Adjusted Earnings Before Interest, Income Taxes, Depreciation,
Amortization and Exploration ("Adjusted EBITDAX") was $37.0
million, compared with $24.1 million for the three months ended
December 31, 2012 (See Non-GAAP Financial Measures and
Reconciliations below), an increase of 54%. The increase in
Adjusted EBITDAX was due primarily to (i) an overall production
increase as a result of prior acquisitions and expanded drilling
operations with a greater focus on oil and liquids as a percentage
of total production (56.7% oil/liquids) in the Company's core areas
of operations and (ii) higher average realized commodity prices
during the period. However, natural gas production shut-ins
(described below), and higher lease operating expenses ("LOE") per
barrel of oil equivalent ("BOE") partially offset these increases.
The increase in LOE per BOE was primarily due to (i) higher costs
in the Appalachian region due to increased liquids production which
generally have higher LOE per BOE than natural gas production, (ii)
higher gas transportation reservation charges and (iii) increased
maintenance, labor, transportation and electrification costs in the
Williston Basin. The Company anticipates LOE in the Williston Basin
to decrease over time due to increased efficiencies at the field
level which continue to be implemented. Recurring general and
administrative expenses per BOE for the three months ended December
31, 2013 decreased 34% to $6.32 per BOE from $9.54 per BOE during
the three months ended December 31, 2012, primarily due to (i)
production increases during the period and (ii) less reliance on
third-party consultants (See Non-GAAP Financial Measures and
Reconciliations below). The Company anticipates that its reliance
on third-party consultants will continue to decrease, thus reducing
its recurring general and administrative expenses per BOE.
Oil and gas production increased 44.0% for the three months
ended December 31, 2013 to 1.039 million BOE ("MMBoe") or an
average of 11,298 BOE per day ("Boe/d") (56.7% oil/liquids),
compared with production of 722 thousand BOE ("MBoe") or an average
of 7,846 Boe/d for the three months ended December 31, 2012. The
increase in production was attributable primarily to the Company's
expanded drilling program in its core areas of operations. In
addition, the Company's oil/liquids production mix increased to
56.7% of overall production in the fourth quarter of 2013, compared
with 44.0% in the fourth quarter of 2012. This increase is a result
of (i) last year's shift in our capital expenditure program towards
more of an oil and liquids rich development program and (ii)
shut-in production during the period due to adverse weather and
pipeline delays. For the three months ended December 31, 2013,
adjusted production, which includes actual production from
continuing operations, actual production from discontinued
operations of 2,118 Boe/d and production shut-ins of 1,970 Boe/d as
described below, increased 96.1% to 15,386 Boe/d(b) compared with
7,846 Boe/d for the three months ended December 31, 2012.
In the fourth quarter of 2013, the Company's production was
impacted by production shut-ins in the Appalachian region primarily
due to the previously reported shut-down of MarkWest's Mobley
processing facilities from August 2013 to early October 2013 as a
result of a break in a MarkWest natural gas liquids pipeline. All
processing plant issues affecting the production of the Company's
Marcellus Shale natural gas were resolved in mid-October 2013, and
all such natural gas production is now flowing through the Eureka
Hunter Pipeline System for processing at the Mobley processing
facilities. The Mobley processing facilities' shut-down resulted in
a decrease in the Company's daily production by approximately 925
Boe/d for the three months ended December 31, 2013. The Company
also experienced approximately 1,045 Boe/d of curtailments for the
three months ended December 31, 2013 at its Ormet Pad location in
Ohio as a result of the Company's continued build out of midstream
infrastructure and liquids handling equipment and delays in
obtaining certain air permits.
Financial and Operating Results for the Twelve Months Ended
December 31, 2013
Magnum Hunter reported an increase in oil and gas revenues of
72.3% to $197.6 million for the twelve months ended December 31,
2013, compared with $114.7 million for the twelve months ended
December 31, 2012. The increase in oil and gas revenues resulted
principally from increases in our oil and natural gas production as
a result of (i) acquisitions and expanded drilling operations in
the Company's unconventional resources plays throughout 2013 and
(ii) higher average realized commodity prices during the period.
Midstream and marketing revenues increased to $60.6 million for the
twelve months ended December 31, 2013, or 365.0%, from $13.0
million for the twelve months ended December 31, 2012. The increase
in midstream and marketing revenues was primarily due to (i)
increased throughput volumes of the Eureka Hunter Pipeline System,
(ii) increased utilization of TransTex Hunter, LLC's gas treating
and processing equipment and (iii) increased third-party gas
marketing volumes.
The Company reported a net loss of ($278.9) million attributable
to common shareholders, or ($1.64) per basic and diluted common
shares outstanding, for the twelve months ended December 31, 2013,
compared with a net loss of ($167.4) million, or ($1.07) per basic
and diluted common shares outstanding, for the twelve months ended
December 31, 2012. When adjusted for non-cash and non-recurring
gains on asset sales and expenses, the Company's adjusted net loss
attributable to common shareholders for the twelve months ended
December 31, 2013 was ($0.65) per basic and diluted common shares
outstanding (see Non-GAAP Financial Measures and Reconciliations
below).
For the twelve months ended December 31, 2013, Magnum Hunter's
Adjusted EBITDAX was $112.4 million, compared with $76.2 million
for the twelve months ended December 31, 2012 (See Non-GAAP
Financial Measures and Reconciliations below). The 48% increase in
Adjusted EBITDAX was primarily due to (i) an overall production
increase as a result of prior acquisitions and expanded drilling
operations with a greater focus on oil and liquids as a percentage
of total production (52.0% oil/liquids) in the Company's core areas
of operations and (ii) higher average realized commodity prices
during the period. However, natural gas production shut-ins (as
discussed above), higher LOE costs per BOE, and higher
non-recurring cash general and administrative costs (see Non-GAAP
Financial Measures and Reconciliations below) per BOE partially
offset the increase. The increase in LOE per BOE was primarily due
to (i) higher costs in the Appalachian region due to increased
liquids production which generally have higher LOE per BOE than
natural gas production, (ii) higher gas transportation reservation
charges and (iii) increased maintenance, labor, transportation and
electrification costs in the Williston Basin. The Company
anticipates LOE in the Williston Basin to decrease over time due to
increased efficiencies at the field level which continue to be
implemented. General and administrative expenses increased overall
during the twelve months ended December 31, 2013 due to (i)
expansion activities necessitated by the growth of the Company and
(ii) its focus on remediation of previously identified internal
control deficiencies. The Company anticipates that its reliance on
third-party consultants will continue to decrease in fiscal 2014,
thus reducing its recurring general and administrative expenses per
BOE.
Oil and gas production increased 26.9% for the twelve months
ended December 31, 2013 to 3.593 MMBoe or an average of 9,845 Boe/d
(52.0% oil/liquids), compared with 2.832 MMBoe or an average of
7,739 Boe/d for the twelve months ended December 31, 2012. The
increase in production was attributable primarily to the Company's
expanded drilling program in its core areas of operations. In
addition, the Company's oil/liquids production mix increased to
52.0% of overall production for the twelve months ended December
31, 2013, compared with 34.0% for the twelve months ended December
31, 2012. For the twelve months ended December 31, 2013, adjusted
production, which includes actual production from continuing
operations, production from discontinued operations of 2,925 Boe/d
and production shut-ins of 2,061 Boe/d as described above,
increased 91.6% to 14,831 Boe/d compared with 7,739 Boe/d for the
twelve months ended December 31, 2012.
2013 Significant Divestitures
During 2013, Magnum Hunter completed several divestitures
resulting in proceeds in excess of $500 million, including purchase
price adjustments. The Company successfully divested its Eagle Ford
assets in Lavaca and Gonzales Counties, in South Texas, for a
contracted price of $401 million to Penn Virginia Corporation
("PVA") (and recorded a gain of $8.3 million on the sale of the PVA
stock received as partial consideration for such sale), properties
in Burke County, North Dakota for $32.5 million and legacy
waterfloods in North Dakota for $45 million.
Capital Expenditures and Liquidity
Magnum Hunter's total upstream and midstream capital
expenditures, including leasehold acquisitions, were $173.3 million
for the three months ended December 31, 2013. Total upstream
capital expenditures for the three months ended December 31, 2013
were $76.9 million, consisting of $19.7 million for the Williston
Basin, $53.0 million for the Appalachian region and $4.2 million
for the South Texas region. Leasehold acquisition expenditures for
the three months ended December 31, 2013, were $56.2 million with a
primary emphasis in the Utica and Marcellus Shale plays. Total
midstream capital expenditures for such period were $40.2
million.
For the twelve months ended December 31, 2013, total upstream
capital expenditures were $301.9 million, consisting of $131.8
million for the Williston Basin, $132.4 million for the Appalachian
region and $37.7 million for the South Texas region. Leasehold
acquisition expenditures for the twelve months ended December 31,
2013, were $144.3 million with a primary emphasis in the Utica and
Marcellus Shale plays. Total midstream capital expenditures for
such period were $87.5 million.
Magnum Hunter believes that its internally generated cash flows,
anticipated increased borrowing availability under its Senior
Revolving Credit Facility resulting from anticipated borrowing base
increases, and additional liquidity sources, including but not
limited to proceeds from non-core asset sales and potential capital
market financings, will provide it with sufficient liquidity to
fund its fiscal 2014 capital budget. As of January 31, 2014, the
Company had total liquidity of approximately $55.5 million,
comprised of approximately $48.5 million of cash and $7.0 million
of borrowing availability under its Senior Revolving Credit
Facility. To further enhance its liquidity, the Company is actively
pursuing up to $400 million (estimated) of non-core asset sales,
which the Company expects to close throughout the 2014 fiscal
year.
Operations
During the quarter ended December 31, 2013, the Company
commenced or participated in the drilling of a total of 23 gross
wells, of which 10 were operated by the Company. The Company had a
100% success rate on the 24 wells in which it had a working
interest that were completed in the fourth quarter of 2013.
The table below summarizes the Company's gross drilling
activities by area for the fourth quarter of 2013:
|
|
Fourth Quarter 2013 |
|
|
Total Drilled Wells |
|
Operated Wells |
|
Completed Wells |
|
Awaiting Frac |
|
|
|
|
|
|
|
|
|
Marcellus Shale |
|
7 |
|
7 |
|
8 |
|
8 |
Utica
Shale |
|
1 |
|
1 |
|
0 |
|
1 |
Williston Basin |
|
15 |
|
2 |
|
16 |
|
3 |
Total |
|
23 |
|
10 |
|
24 |
|
12 |
|
|
|
|
|
|
|
|
|
Currently, the Company is running six drilling rigs (two
operated and four non-operated rigs). Of these six rigs, three rigs
(two operated and one non-operated) are drilling wells in the
Marcellus and Utica Shales in West Virginia and Ohio, and three
non-operated rigs are drilling wells in the Williston Basin/Bakken
Shale in North Dakota.
Marcellus and Utica Shale
During the fourth quarter of 2013, the Company completed the
drilling of 7 gross (7 net) wells and completed 8 gross (6 net)
wells in the Marcellus Shale and Utica Shale plays. These 8 gross
(6 net) completed wells are currently flowing to sales via the
Eureka Hunter Pipeline System. The Company's net production in the
fourth quarter of 2013 attributable to Triad Hunter, LLC's
operations was approximately 37.6 Mcfe/d, a 24% increase over such
production during the fourth quarter of 2012.
The Company's first dry gas Utica Shale well, the Stalder #3UH
located on the Stalder Pad (18 potential wells) in Monroe County,
Ohio, was placed on production approximately two weeks ago and
tested at a peak rate of 32.5 MMCF of natural gas per day on an
adjustable rate choke with 4,300 psi FCP. The well continues to
flow to sales points via the Eureka Hunter Pipeline System with the
amount of frac water continuing to decrease since the commencement
of initial sales.
The Company's first Marcellus Shale well drilled on the Stalder
Pad, the Stalder #2MH, is awaiting the start of completion
operations which the Company expects to commence in the next
several weeks. The Stalder #2MH was drilled and cased to a true
vertical depth of 6,070 feet with a 5,474 foot horizontal lateral.
The Company expects the production from this well to be very
liquids rich.
On the Farley Pad located in Washington County, Ohio, the
Company has drilled and cased the Farley #1306H well in the Utica
Shale to a true vertical depth of 7,850 feet with a 6,313 foot
horizontal lateral. The Company has commenced the drilling of
another Utica Shale well on the Farley Pad, the Farley #1304H. The
Company is currently drilling the vertical section of this well and
anticipates reaching a true vertical depth of 7,885 feet, and
completing the drilling of a 5,500 foot horizontal lateral, within
the next 30 days. Following the drilling of the Farley #1304H, the
Company will begin fracture stimulation of these two new Farley
wells in mid-March 2014 and expects to report initial production
test rates in early-summer 2014 following an approximate 30-day
resting period. The Company is in the advanced stages of
negotiating new take-away capacity with a third-party midstream
company and expects to be ready to flow production of all three
wells on the Farley Pad to sales following the resting period.
On the WVDNR Pad located in Wetzel County, West Virginia, the
Company has drilled and is in the process of completing three 100%
owned Marcellus Shale wells, the WVDRN #1207, #1208 and #1209. The
wells were drilled and cased to an average vertical depth of 7,500
feet with a 4,000 foot average horizontal lateral. The Company has
fracture stimulated 9 of the proposed 20 stages on each of the
three wells. During the last several weeks, the Company has
experienced substantial completion delays in this region primarily
due to the effects of extreme cold weather conditions. The Company
expects to complete fracture stimulating the three WVDNR wells over
the next 7 to 10 days, and anticipates production from the wells to
begin to flow to sales in mid-March 2014.
On the Stewart Winland Pad located in Tyler County, West
Virginia, the Company has drilled and cased the pad's first
Marcellus Shale well, the Stewart Winland #1301. The Stewart
Winland #1301 was drilled to a true vertical depth of 6,144 feet
with a 5,770 foot horizontal lateral. The Company has skid the
drilling rig and commenced the drilling of another Marcellus Shale
well, the Stewart Winland #1302, on this pad. One additional
Marcellus Shale well and one Utica Shale well will be subsequently
drilled on this pad. The Company expects to report initial
production test rates from the four wells on the Stewart Winland
Pad during mid-summer 2014. As previously reported, the Company is
in the process of making several production equipment changes at
both its Collins and Spencer Pads in Tyler County, West Virginia to
better handle the anticipated new liquids production. The Company
is on target for these production equipment changes to be completed
within the next 30 to 45 days. As a result, the Company does not
expect to encounter any liquids infrastructure issues associated
with the initial production from the four wells on the Stewart
Winland Pad.
Williston Basin
During the fourth quarter of 2013, the Company drilled a total
of 15 gross (6.2 net) wells in the Bakken/Three Forks Sanish
formations in North Dakota. In the Company operated areas, the
Company drilled 2 gross (2.0 net) wells, and in the Company
non-operated areas, 13 gross (4.2 net) wells were drilled. During
the fourth quarter, (i) six two-mile lateral wells were completed
in the Middle Bakken formation, with an average IP 24-hour rate of
561 Boe/d and an average IP 30-day rate of 389 Boe/d, (ii) seven
two-mile lateral wells were completed in the Three Forks Sanish
formation with an average IP 24-hour rate of 584 Boe/d and an
average IP 30-day rate of 287 Boe/d and (iii) three one-mile
lateral wells were completed, one in the Three Forks Sanish
formation, with an IP 24-hour rate of 760 Boe/d and an IP 30-day
rate of 282 Boe/d, and two in the Middle Bakken formation, one with
an IP 24-hour rate of 680 Boe/d and an IP 30-day rate of 253 Boe/d
and the other for which the Company is still awaiting more complete
initial production results. At the end of the fourth quarter of
2013, 12 gross (4.3 net) Company wells were drilling or waiting on
fracture stimulation in North Dakota.
Eureka Hunter
As of February 16, 2014, Eureka Hunter Pipeline, LLC, ("Eureka
Hunter"), was gathering approximately 171,634 MMBtu/d. The Eureka
Hunter Pipeline System's gathering flow through recently hit a peak
rate of 198,000 MMBtu/d. Eureka Hunter has connected a significant
amount of new Marcellus production volumes from several Triad
Hunter, LLC and third-party wells into the Eureka Hunter Pipeline
System located in Tyler and Wetzel Counties, West Virginia.
Eureka Hunter is in the process of installing liquids
stabilization equipment and loading facilities near its Ohio River
crossing near Sardis, Ohio, which are expected to be in full
operation during the first quarter of 2014. To further assist with
volume demands and to reduce line pressure for producers, Eureka
Hunter is also adding new mainline compression at its Carbide
facility in Tyler County, West Virginia.
The new Marcellus Shale volumes flowing into Eureka Hunter's
gathering system are coupled with the addition of dry Utica Shale
production in Ohio from various third-party producers and Triad
Hunter, LLC. Eureka Hunter expects to connect significant volumes
of new Utica Shale production throughout 2014.
The build out of Eureka Hunter's gathering system in Ohio
continues despite weather delays. The first lateral to be completed
in Ohio was a 20-inch extension from the Ohio River past Triad
Hunter, LLC's Stalder Pad extending approximately 11 miles to the
west to gather gas from Eclipse Resources' Tippens pad site. This
line is initially gathering dry Utica Shale gas production and was
put into service in December 2013. The second Ohio line, the "Ormet
lateral", is also a 20-inch line, and is approximately 95% complete
at this time. The Company expects to complete the Ormet lateral in
April 2014 barring any further weather delays. The necessary
liquids handling equipment should also be installed in March 2014
with production anticipated in April 2014.
Other Eureka Hunter pipeline construction projects slated for
2014 include a northerly extension to interconnect with Rocky
Mountain Express, Texas Eastern Transmission and possibly Dominion
Transmission, all near Clarington, Ohio. Eureka also plans to
connect to rich gas production for delivery to the Blue Racer
Natrium plant in Marshall County, West Virginia and to a residue
gas line extension from the MarkWest Mobley processing facilities
tailgate to Columbia Gas. The Company's goal is to have as many
production take-away outlets from this region as possible.
Management Comments
Mr. Gary C. Evans, Chairman of the Board and Chief Executive
Officer of Magnum Hunter, commented, "Calendar year 2013 was a
pivotal year for Magnum Hunter. We made the decision to sell our
Eagle Ford assets, producing approximately 3,000 barrels of oil
equivalent per day, for a contracted price of $401 million and
redeploy those proceeds to our two remaining core areas, Appalachia
and the Williston Basin. Revenues were still up over 72% and
EBITDAX increased 48%. We drilled 21 gross wells (12.5 net) in the
Marcellus and Utica resource plays and drilled 72 gross (24.6 net)
in the Bakken and Three Forks Sanish plays of the Williston Basin.
All 93 gross wells were deemed commercially successful. We also
completed 23 miles of new pipeline in our midstream division,
Eureka Hunter, where throughput increased 390%. Our lease acreage
position has grown to 957,953 gross acres and 642,643 net acres,
most of which is held by existing production which give us a
tremendous amount of future inventory. In 2014, we will continue
our divestiture efforts with respect to non-core assets which could
bring in approximately $400 million of proceeds, an amount much
greater than our current capital expenditure funding gap. The high
grading of our portfolio is being reflected in our proved reserve
additions, higher EUR's per well and higher production rates on new
drills. Management's goal will be to continue improving our
internal rates of return on every single dollar deployed and drill
predominately in the core areas of the shale plays where we
operate."
Non-GAAP Financial Measures
This release contains certain financial measures that are
non-GAAP measures. We have provided reconciliations within this
release of the non-GAAP financial measures to the most directly
comparable GAAP financial measures. These non-GAAP financial
measures should be considered in addition to, but not as a
substitute for, measures for financial performance prepared in
accordance with GAAP that are presented in this release.
Magnum Hunter defines adjusted income (loss) as reported net
income (loss) attributable to common shareholders, plus
non-recurring and non-cash items which include (1) exploration, (2)
impairment of proved oil and gas properties, (3) non-cash stock
compensation expense, (4) non-cash 401k matching expense, (5)
non-recurring transaction and other expense, (6) unrealized (gain)
loss on investments, (7) interest expense - fees, (8) unrealized
(gain) loss on derivatives, (9) (gain) loss on sale of assets, (10)
income tax expense (benefit), (11) (gain) loss from sale of
discontinued operations and (12) income from discontinued
operations.
Magnum Hunter defines Adjusted EBITDAX as net income (loss) from
continuing operations before (1) net interest expense, (2) (gain)
loss on sale of assets, (3) depletion, depreciation, amortization
and accretion, (4) impairment of proved oil and gas properties, (5)
exploration, (6) non-cash stock compensation expense, (7) non-cash
401k matching expense, (8) non-recurring transaction and other
expense, (9) unrealized (gain) loss on investments, (10) income tax
(benefit) and (11) unrealized (gain) loss on derivatives. Adjusted
EBITDAX is not a measure of net income or cash flows as determined
by GAAP.
Magnum Hunter defines recurring cash G&A as total general
and administrative expenses before (1) non-cash stock compensation
and (2) transaction and other non-recurring expense.
Management believes these non-GAAP financial measures facilitate
evaluation of the Company's business on a "normalized" or recurring
basis and without giving effect to certain non-cash expenses and
other items, thereby providing management, investors and analysts
with comparative information for evaluating the Company in relation
to other oil and gas companies providing corresponding non-GAAP
financial measures. These non-GAAP financial measures should be
considered in addition to, but not as a substitute for, measures
for financial performance prepared in accordance with GAAP, and
that the reconciliations to the closest corresponding GAAP measure
should be reviewed carefully.
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
oil, natural gas and natural gas liquids, primarily in the states
of West Virginia, Ohio and North Dakota. The Company is presently
active in three of the most prolific unconventional shale resource
plays in North America, namely the Marcellus Shale, Utica Shale and
Williston Basin/Bakken Shale.
Availability of Information on the Company's Website
Magnum Hunter is providing a reminder that it makes available on
its website (at www.magnumhunterresources.com) a variety of
information for investors, analysts and the media, including the
following:
- annual reports on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and any amendments to those reports as
soon as reasonably practicable after the material is electronically
filed with or furnished to the Securities and Exchange
Commission;
- the most recent version of the Company's Investor Presentation
slide deck;
- announcements of conference calls, webcasts, investor
conferences, speeches and other events at which Company executives
may discuss the Company and its business and archives or
transcripts of such events;
- press releases regarding annual and quarterly earnings,
operational developments, legal developments and other matters;
and
- corporate governance information, including the Company's
corporate governance guidelines, committee charters, code of
conduct and other governance-related matters.
Magnum Hunter's goal is to maintain its website as the
authoritative portal through which visitors can easily access
current information about the Company. Over time, the Company
intends for its website to become a primary channel for public
dissemination of important information about the Company.
Investors, analysts, media and other interested persons are
encouraged to visit the Company's website frequently.
Certain information included on the Company's website
constitutes forward-looking statements and is subject to the
qualifications under the heading "Forward-Looking Statements" below
and in the Company's Investor Presentation slide deck.
Forward-Looking Statements
This press release includes "forward-looking statements." All
statements other than statements of historical facts included or
incorporated herein may constitute forward-looking statements.
Actual results could vary significantly from those expressed or
implied in such statements and are subject to a number of risks and
uncertainties. Although Magnum Hunter believes that the
expectations reflected in the forward-looking statements are
reasonable, Magnum Hunter can give no assurance that such
expectations will prove to be correct. The forward-looking
statements involve risks and uncertainties that affect operations,
financial performance, and other factors as discussed in filings
made by Magnum Hunter with the Securities and Exchange Commission
(SEC). Among the factors that could cause results to differ
materially are those risks discussed in the periodic reports filed
by Magnum Hunter with the SEC, including Magnum Hunter's Annual
Report on Form 10-K for the fiscal year ended December 31, 2012,
and its to-be-filed Annual Report on Form 10-K for the fiscal year
ended December 31, 2013, and its Quarterly Reports on Form 10-Q for
the fiscal quarters ended after such fiscal year. You are urged to
carefully review and consider the cautionary statements and other
disclosures made in those filings, specifically those under the
heading "Risk Factors." Forward-looking statements speak only as of
the date of the document in which they are contained, and Magnum
Hunter does not undertake any duty to update any forward-looking
statements except as may be required by law.
MAGNUM HUNTER RESOURCES CORPORATION UNAUDITED RESULTS
OF OPERATIONS |
(Continuing Operations) |
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
MAGNUM HUNTER RESOURCES CORPORATION |
UNAUDITED CONSOLIDATED BALANCE SHEETS |
(In thousands, except share and per share data) |
|
|
|
December 31, |
|
|
|
2013 |
|
|
2012 |
|
ASSETS |
|
|
|
|
|
|
CURRENT ASSETS |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
41,713 |
|
|
$ |
57,623 |
|
|
Restricted cash |
|
|
5,000 |
|
|
|
1,500 |
|
|
Accounts receivable, net of allowance for doubtful
accounts of $292 and $448 as of December 31, 2013 and 2012,
respectively |
|
|
55,681 |
|
|
|
124,861 |
|
|
Derivative assets |
|
|
608 |
|
|
|
5,146 |
|
|
Inventory |
|
|
7,158 |
|
|
|
9,162 |
|
|
Investments |
|
|
2,262 |
|
|
|
3,278 |
|
|
Prepaid expenses and other assets |
|
|
2,938 |
|
|
|
2,249 |
|
|
Assets held for sale |
|
|
5,366 |
|
|
|
500 |
|
|
|
Total
current assets |
|
|
120,726 |
|
|
|
204,319 |
|
|
|
|
|
|
|
|
|
|
PROPERTY, PLANT AND EQUIPMENT |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts
method of accounting |
|
|
1,355,288 |
|
|
|
1,908,659 |
|
|
Accumulated depletion, depreciation, and accretion |
|
|
(130,629 |
) |
|
|
(186,156 |
) |
|
Total oil and natural gas properties, net |
|
|
1,224,659 |
|
|
|
1,722,503 |
|
|
Gas transportation, gathering and processing equipment
and other, net |
|
|
289,420 |
|
|
|
201,910 |
|
|
|
Total
property, plant and equipment, net |
|
|
1,514,079 |
|
|
|
1,924,413 |
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS |
|
|
|
|
|
|
|
|
|
Deferred financing costs, net of amortization of
$12,842 and $8,024 as of December 31, 2013 and 2012,
respectively |
|
|
20,008 |
|
|
|
23,862 |
|
|
Derivatives assets |
|
|
25 |
|
|
|
- |
|
|
Intangible assets, net |
|
|
6,530 |
|
|
|
8,981 |
|
|
Goodwill |
|
|
30,602 |
|
|
|
30,602 |
|
|
Other assets |
|
|
1,994 |
|
|
|
6,455 |
|
|
Assets held for sale |
|
|
162,687 |
|
|
|
- |
|
|
|
Total
assets |
|
$ |
1,856,651 |
|
|
$ |
2,198,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MAGNUM HUNTER RESOURCES CORPORATION |
|
UNAUDITED CONSOLIDATED BALANCE SHEETS |
|
(In thousands, except share and per share data) |
|
|
|
|
|
December 31, |
|
|
|
2013 |
|
|
2012 |
|
LIABILITIES AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
CURRENT LIABILITIES |
|
|
|
|
|
|
|
|
|
Current portion of notes payable |
|
$ |
3,804 |
|
|
$ |
3,991 |
|
|
Accounts payable |
|
|
107,860 |
|
|
|
196,515 |
|
|
Accrued liabilities |
|
|
44,629 |
|
|
|
11,212 |
|
|
Revenue payable |
|
|
6,313 |
|
|
|
20,394 |
|
|
Derivatives liabilities |
|
|
1,903 |
|
|
|
3,501 |
|
|
Other liabilities |
|
|
6,491 |
|
|
|
8,043 |
|
|
Liabilities associated with assets held for sale |
|
|
12,865 |
|
|
|
- |
|
|
|
Total
current liabilities |
|
|
183,865 |
|
|
|
243,656 |
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
876,106 |
|
|
|
886,769 |
|
|
Asset retirement obligation |
|
|
16,163 |
|
|
|
28,322 |
|
|
Deferred tax liability |
|
|
- |
|
|
|
74,258 |
|
|
Derivative liabilities |
|
|
76,310 |
|
|
|
47,524 |
|
|
Other long-term liabilities |
|
|
2,279 |
|
|
|
5,573 |
|
|
Liabilities associated with assets held for sale |
|
|
14,523 |
|
|
|
- |
|
|
|
Total
liabilities |
|
|
1,169,246 |
|
|
|
1,286,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REDEEMABLE PREFERRED STOCK |
|
|
|
|
|
|
|
|
|
Series C Cumulative Perpetual Preferred Stock, ("Series
C Preferred Stock") cumulative dividend rate 10.25% per annum,
4,000,000 authorized, 4,000,000 issued and outstanding as of
December 31, 2013 and 2012, with liquidation preference of $25.00
per share |
|
|
100,000 |
|
|
|
100,000 |
|
|
Series A Convertible Preferred Units of Eureka Hunter
Holdings, LLC, cumulative distribution rate of 8.0% per annum,
9,885,048 and 7,672,892 issued and outstanding as of December 31,
2013 and 2012, respectively, with liquidation preference of
$200,620 and $167,403 as of December 31, 2013 and 2012,
respectively |
|
|
136,675 |
|
|
|
100,878 |
|
|
|
|
236,675 |
|
|
|
200,878 |
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
|
|
Preferred Stock of Magnum Hunter Resources Corporation,
10,000,000 authorized, including authorized shares of Series C
Preferred Stock |
|
|
|
|
|
|
|
|
|
|
Series D Cumulative Preferred Stock, ("Series D Preferred Stock")
cumulative dividend rate 8.0% per annum, 5,750,000 authorized,
4,424,889 and 4,208,821 issued and outstanding as of December 31,
2013 and December 31, 2012, respectively, with liquidation
preference of $50.00 per share |
|
|
221,244 |
|
|
|
210,441 |
|
|
|
Series E Cumulative Convertible Preferred Stock, ("Series E
Preferred Stock") cumulative dividend rate 8.0% per annum, 12,000
authorized, 3,803 and 3,755 issued and 3,722 and 3,705 shares
outstanding as of December 31, 2013 and 2012, respectively, with
liquidation preference of $25,000 per share |
|
|
95,069 |
|
|
|
94,371 |
|
|
Common stock, $0.01 par value; 350,000,000 and
250,000,000 authorized, 172,409,000 and 170,032,999 issued and
171,494,071 and 169,118,047 outstanding as of December 31, 2013 and
2012, respectively |
|
|
1,724 |
|
|
|
1,700 |
|
|
Exchangeable common stock, par value $0.01 per share,
none and 505,835 shares issued and outstanding as of December 31,
2013 and 2012, respectively |
|
|
- |
|
|
|
5 |
|
|
Additional paid in capital |
|
|
733,753 |
|
|
|
715,033 |
|
|
Accumulated deficit |
|
|
(586,365 |
) |
|
|
(307,484 |
) |
|
Accumulated other comprehensive loss |
|
|
(19,901 |
) |
|
|
(8,889 |
) |
|
Treasury Stock, at cost |
|
|
|
|
|
|
|
|
|
|
Series E Cumulative Preferred Stock, 81 shares and 70 as of
December 31, 2013 and 2012, respectively |
|
|
(2,030 |
) |
|
|
(1,750 |
) |
|
|
Common stock, 914,952 shares as of December 31, 2013 and 2012,
respectively |
|
|
(1,914 |
) |
|
|
(1,914 |
) |
Total Magnum Hunter Resources Corporation shareholders'
equity |
|
|
441,580 |
|
|
|
701,513 |
|
Non-controlling interest |
|
|
9,150 |
|
|
|
10,139 |
|
|
|
Total
shareholders' equity |
|
|
450,730 |
|
|
|
711,652 |
|
|
|
Total
liabilities and shareholders' equity |
|
$ |
1,856,651 |
|
|
$ |
2,198,632 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MAGNUM HUNTER RESOURCES CORPORATION |
UNAUDITED CONSOLIDATED STATEMENT OF OPERATIONS |
(In thousands, except share and per share data) |
|
|
|
Year Ended December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
|
|
|
REVENUES AND OTHER |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
197,599 |
|
|
$ |
114,659 |
|
|
$ |
58,726 |
|
|
Natural gas transportation, gathering, processing, and
marketing |
|
|
60,632 |
|
|
|
13,040 |
|
|
|
494 |
|
|
Oilfield services |
|
|
18,431 |
|
|
|
12,333 |
|
|
|
7,149 |
|
|
Other revenue |
|
|
3,749 |
|
|
|
324 |
|
|
|
86 |
|
|
|
Total
revenue |
|
|
280,411 |
|
|
|
140,356 |
|
|
|
66,455 |
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
53,961 |
|
|
|
26,839 |
|
|
|
14,998 |
|
|
Severance taxes and marketing |
|
|
17,721 |
|
|
|
7,854 |
|
|
|
5,341 |
|
|
Exploration |
|
|
97,342 |
|
|
|
78,221 |
|
|
|
2,605 |
|
|
Natural gas transportation, gathering, processing, and
marketing |
|
|
52,099 |
|
|
|
8,028 |
|
|
|
373 |
|
|
Oilfield services |
|
|
14,825 |
|
|
|
10,037 |
|
|
|
6,759 |
|
|
Impairment of proved oil and gas properties |
|
|
9,968 |
|
|
|
3,772 |
|
|
|
- |
|
|
Depreciation, depletion, amortization and
accretion |
|
|
99,198 |
|
|
|
59,730 |
|
|
|
23,246 |
|
|
Loss on sale of assets, net |
|
|
44,654 |
|
|
|
628 |
|
|
|
361 |
|
|
General and administrative |
|
|
75,407 |
|
|
|
53,454 |
|
|
|
54,360 |
|
|
|
Total
operating expenses |
|
|
465,175 |
|
|
|
248,563 |
|
|
|
108,043 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING LOSS |
|
|
(184,764 |
) |
|
|
(108,207 |
) |
|
|
(41,588 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
220 |
|
|
|
199 |
|
|
|
10 |
|
|
Interest expense |
|
|
(72,423 |
) |
|
|
(51,616 |
) |
|
|
(11,752 |
) |
|
Gain (loss) on derivative contracts, net |
|
|
(25,274 |
) |
|
|
22,239 |
|
|
|
(6,346 |
) |
|
Other income (expense) |
|
|
7,892 |
|
|
|
(1,583 |
) |
|
|
- |
|
|
|
Total
other expense, net |
|
|
(89,585 |
) |
|
|
(30,761 |
) |
|
|
(18,088 |
) |
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX |
|
|
(274,349 |
) |
|
|
(138,968 |
) |
|
|
(59,676 |
) |
|
Income tax benefit (expense) |
|
|
70,297 |
|
|
|
19,312 |
|
|
|
2,862 |
|
LOSS FROM CONTINUING OPERATIONS |
|
|
(204,052 |
) |
|
|
(119,656 |
) |
|
|
(56,814 |
) |
|
Loss from discontinued operations, net of tax |
|
|
(71,131 |
) |
|
|
(19,474 |
) |
|
|
(19,598 |
) |
|
Gain on disposal of discontinued operations, net of
tax |
|
|
52,019 |
|
|
|
2,409 |
|
|
|
- |
|
NET LOSS |
|
|
(223,164 |
) |
|
|
(136,721 |
) |
|
|
(76,412 |
) |
|
Net loss (income) attributable to non-controlling
interest |
|
|
988 |
|
|
|
4,013 |
|
|
|
(249 |
) |
NET LOSS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES
CORPORATION |
|
|
(222,176 |
) |
|
|
(132,708 |
) |
|
|
(76,661 |
) |
|
Dividends on preferred stock |
|
|
(56,705 |
) |
|
|
(34,706 |
) |
|
|
(14,007 |
) |
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS |
|
$ |
(278,881 |
) |
|
$ |
(167,414 |
) |
|
$ |
(90,668 |
) |
|
Weighted average number of common shares outstanding,
basic and diluted |
|
|
170,088,108 |
|
|
|
155,743,418 |
|
|
|
113,154,270 |
|
|
Loss from continuing operations per share, basic and
diluted |
|
$ |
(1.53 |
) |
|
$ |
(0.96 |
) |
|
$ |
(0.63 |
) |
|
Income (loss) from discontinued operations per share,
basic and diluted |
|
|
(0.11 |
) |
|
|
(0.11 |
) |
|
|
(0.17 |
) |
NET LOSS PER COMMON SHARE, BASIC AND DILUTED |
|
$ |
(1.64 |
) |
|
$ |
(1.07 |
) |
|
$ |
(0.80 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
AMOUNTS ATTRIBUTABLE TO MAGNUM HUNTER RESOURCES |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations, net of tax |
|
$ |
(203,064 |
) |
|
$ |
(115,643 |
) |
|
$ |
(57,063 |
) |
|
Income (loss) from discontinued operations, net of
tax |
|
|
(19,112 |
) |
|
|
(17,065 |
) |
|
|
(19,598 |
) |
|
Net loss attributable to Magnum Hunter Resources |
|
$ |
(222,176 |
) |
|
$ |
(132,708 |
) |
|
$ |
(76,661 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MAGNUM HUNTER RESOURCES CORPORATION |
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS |
(In thousands, except share and per share data) |
|
|
|
Year Ended December 31, |
|
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(223,164 |
) |
|
$ |
(136,721 |
) |
|
$ |
(76,412 |
) |
|
Adjustments to reconcile net loss to net cash provided
by (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation, amortization and accretion |
|
|
134,867 |
|
|
|
135,896 |
|
|
|
49,090 |
|
|
|
Share-based compensation |
|
|
13,624 |
|
|
|
15,696 |
|
|
|
25,057 |
|
|
|
Impairment of oil and gas properties |
|
|
89,041 |
|
|
|
4,096 |
|
|
|
21,782 |
|
|
|
Exploration |
|
|
115,069 |
|
|
|
116,686 |
|
|
|
1,118 |
|
|
|
Gain
on sale of assets |
|
|
(7,318 |
) |
|
|
(3,074 |
) |
|
|
(186 |
) |
|
|
Cash
paid for plugging wells |
|
|
(14 |
) |
|
|
- |
|
|
|
- |
|
|
|
Loss
(gain) on open derivative contracts |
|
|
17,058 |
|
|
|
(10,945 |
) |
|
|
4,210 |
|
|
|
Loss
(gain) on investments |
|
|
(7,009 |
) |
|
|
2,200 |
|
|
|
- |
|
|
|
Amortization and write off of deferred financing cost and discount
on Senior Notes included in interest expense |
|
|
4,836 |
|
|
|
7,399 |
|
|
|
3,636 |
|
|
|
Deferred tax benefit |
|
|
(84,527 |
) |
|
|
(21,595 |
) |
|
|
(696 |
) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net |
|
|
22,781 |
|
|
|
(73,549 |
) |
|
|
(25,075 |
) |
|
|
Inventory |
|
|
4,658 |
|
|
|
(6,198 |
) |
|
|
(3,889 |
) |
|
|
Prepaid expenses and other current assets |
|
|
(1,073 |
) |
|
|
(538 |
) |
|
|
(124 |
) |
|
|
Accounts payable |
|
|
42,050 |
|
|
|
16,390 |
|
|
|
25,883 |
|
|
|
Revenue payable |
|
|
(11,589 |
) |
|
|
8,776 |
|
|
|
6,979 |
|
|
|
Accrued liabilities |
|
|
2,421 |
|
|
|
3,492 |
|
|
|
2,465 |
|
|
|
Net
cash provided by operating activities |
|
|
111,711 |
|
|
|
58,011 |
|
|
|
33,838 |
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in restricted cash |
|
|
(3,500 |
) |
|
|
- |
|
|
|
- |
|
|
Capital expenditures and advances |
|
|
(631,511 |
) |
|
|
(568,610 |
) |
|
|
(291,942 |
) |
|
Cash paid in acquisitions, net of cash received
of $0; $34; and $2,500, respectively |
|
|
- |
|
|
|
(444,844 |
) |
|
|
(78,524 |
) |
|
Proceeds from sale of assets |
|
|
506,297 |
|
|
|
4,158 |
|
|
|
8,709 |
|
|
Change in deposits and other long-term
assets |
|
|
854 |
|
|
|
89 |
|
|
|
42 |
|
|
|
Net cash used in investing activities |
|
|
(127,860 |
) |
|
|
(1,009,207 |
) |
|
|
(361,715 |
) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuing Senior Notes |
|
|
- |
|
|
|
596,907 |
|
|
|
- |
|
|
Proceeds from borrowings on debt |
|
|
373,991 |
|
|
|
546,043 |
|
|
|
493,906 |
|
|
Principal repayments of debt |
|
|
(380,923 |
) |
|
|
(542,654 |
) |
|
|
(242,472 |
) |
|
Proceeds from sale of Series A preferred units in
Eureka Hunter Holdings |
|
|
35,280 |
|
|
|
149,655 |
|
|
|
- |
|
|
Net proceeds from sale of common stock |
|
|
- |
|
|
|
148,241 |
|
|
|
13,892 |
|
|
Net proceeds from sale of preferred shares |
|
|
10,072 |
|
|
|
144,635 |
|
|
|
94,764 |
|
|
Proceeds from exercise of warrants and options |
|
|
5,352 |
|
|
|
2,331 |
|
|
|
7,618 |
|
|
Change in other long-term liabilities |
|
|
(1,222 |
) |
|
|
186 |
|
|
|
69 |
|
|
Purchase of treasury shares |
|
|
- |
|
|
|
(1,750 |
) |
|
|
- |
|
|
Payment of deferred financing costs |
|
|
(1,246 |
) |
|
|
(20,313 |
) |
|
|
(11,577 |
) |
|
Preferred stock dividends paid |
|
|
(40,648 |
) |
|
|
(26,839 |
) |
|
|
(14,007 |
) |
|
|
Net
cash provided by financing activities |
|
|
656 |
|
|
|
996,442 |
|
|
|
342,193 |
|
Effect of foreign exchange rate changes on cash |
|
|
(417 |
) |
|
|
(2,474 |
) |
|
|
(19 |
) |
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS |
|
|
(15,910 |
) |
|
|
42,772 |
|
|
|
14,297 |
|
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR |
|
|
57,623 |
|
|
|
14,851 |
|
|
|
554 |
|
CASH AND CASH EQUIVALENTS, END OF YEAR |
|
$ |
41,713 |
|
|
$ |
57,623 |
|
|
$ |
14,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Magnum Hunter Resources Reconciliations
(Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted Loss per Common Share
Reconciliation |
|
Three Months Ended |
|
|
Twelve Months Ended |
|
|
|
December 31, |
|
|
December 31, |
|
($ in thousands) |
|
2013 |
|
|
2012 |
|
|
2013 |
|
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common shareholders -
reported |
|
$ |
(61,208 |
) |
|
$ |
(87,235 |
) |
|
$ |
(278,881 |
) |
|
$ |
(167,414 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-recurring and non-cash items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration expense |
|
$ |
23,940 |
|
|
$ |
60,078 |
|
|
$ |
97,342 |
|
|
$ |
78,221 |
|
|
Impairment of proved oil and gas properties |
|
$ |
- |
|
|
$ |
3,772 |
|
|
$ |
9,968 |
|
|
$ |
3,772 |
|
|
Non-cash: stock compensation expense |
|
$ |
1,790 |
|
|
$ |
938 |
|
|
$ |
13,624 |
|
|
$ |
15,696 |
|
|
Non-cash: 401k matching expense |
|
$ |
298 |
|
|
$ |
531 |
|
|
$ |
1,856 |
|
|
$ |
1,403 |
|
|
Non-recurring transaction and other expense |
|
$ |
8,487 |
|
|
$ |
7,396 |
|
|
$ |
29,807 |
|
|
$ |
15,085 |
|
|
Unrealized (gain) loss on investments |
|
$ |
(229 |
) |
|
$ |
(301 |
) |
|
$ |
814 |
|
|
$ |
- |
|
|
Interest expense - fees |
|
$ |
1,175 |
|
|
$ |
(3,326 |
) |
|
$ |
4,836 |
|
|
$ |
7,399 |
|
|
Unrealized (gain) loss on derivatives |
|
$ |
(6,699 |
) |
|
$ |
(9,851 |
) |
|
$ |
17,058 |
|
|
$ |
(10,945 |
) |
|
(Gain) loss on sale of assets |
|
$ |
2,538 |
|
|
$ |
100 |
|
|
$ |
44,654 |
|
|
$ |
628 |
|
|
Income tax (benefit) |
|
$ |
(29,353 |
) |
|
$ |
(10,169 |
) |
|
$ |
(70,297 |
) |
|
$ |
(19,312 |
) |
|
(Gain) loss from sale of discontinued operations |
|
$ |
35,979 |
|
|
$ |
4,633 |
|
|
$ |
(52,019 |
) |
|
$ |
2,409 |
|
|
Income from discontinued operations |
|
$ |
(324 |
) |
|
$ |
(16,642 |
) |
|
$ |
71,131 |
|
|
$ |
(19,474 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-recurring and non-cash items |
|
$ |
37,602 |
|
|
$ |
37,159 |
|
|
$ |
168,774 |
|
|
$ |
74,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common shareholders -
as adjusted |
|
$ |
(23,606 |
) |
|
$ |
(50,076 |
) |
|
$ |
(110,107 |
) |
|
$ |
(92,532 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to common shareholders -
as adjusted |
|
$ |
(0.14 |
) |
|
$ |
(0.30 |
) |
|
$ |
(0.65 |
) |
|
$ |
(0.59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares |
|
|
171,085,346 |
|
|
|
169,197,301 |
|
|
|
170,088,108 |
|
|
|
155,743,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX Reconciliation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Twelve Months Ended |
|
|
|
December 31, |
|
|
December 31, |
|
($
in thousands) |
|
2013 |
|
|
2012 |
|
|
2013 |
|
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (loss) from continuing operations |
|
$ |
(10,257 |
) |
|
$ |
(57,173 |
) |
|
$ |
(204,052 |
) |
|
$ |
(119,656 |
) |
Net
Interest expense |
|
$ |
19,220 |
|
|
$ |
11,237 |
|
|
$ |
72,423 |
|
|
$ |
51,616 |
|
(Gain) loss on sale of assets |
|
$ |
2,538 |
|
|
$ |
100 |
|
|
$ |
44,654 |
|
|
$ |
628 |
|
Depletion, depreciation, amortization and accretion |
|
$ |
27,242 |
|
|
$ |
17,531 |
|
|
$ |
99,198 |
|
|
$ |
59,730 |
|
Impairment of proved oil and gas properties |
|
$ |
- |
|
|
$ |
3,772 |
|
|
$ |
9,968 |
|
|
$ |
3,772 |
|
Exploration expense |
|
$ |
23,940 |
|
|
$ |
60,078 |
|
|
$ |
97,342 |
|
|
$ |
78,221 |
|
Non-cash stock compensation expense |
|
$ |
1,790 |
|
|
$ |
938 |
|
|
$ |
13,624 |
|
|
$ |
15,696 |
|
Non-cash 401k matching expense |
|
$ |
298 |
|
|
$ |
531 |
|
|
$ |
1,856 |
|
|
$ |
1,403 |
|
Non-recurring transaction and other expense |
|
$ |
8,487 |
|
|
$ |
7,396 |
|
|
$ |
29,807 |
|
|
$ |
15,085 |
|
Unrealized (gain) loss on investments |
|
$ |
(229 |
) |
|
$ |
(301 |
) |
|
$ |
814 |
|
|
$ |
- |
|
Income tax (benefit) |
|
$ |
(29,353 |
) |
|
$ |
(10,169 |
) |
|
$ |
(70,297 |
) |
|
$ |
(19,312 |
) |
Unrealized (gain) loss on derivatives |
|
$ |
(6,699 |
) |
|
$ |
(9,851 |
) |
|
$ |
17,058 |
|
|
$ |
(10,945 |
) |
Total
Adjusted EBITDAX |
|
$ |
36,977 |
|
|
$ |
24,089 |
|
|
$ |
112,395 |
|
|
$ |
76,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Cash G&A Reconciliation |
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Twelve Months Ended |
|
|
December 31, |
|
December 31, |
($ in thousands) |
|
|
2013 |
|
|
2012 |
|
|
2013 |
|
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total G&A |
|
$ |
16,849 |
|
$ |
15,228 |
|
$ |
75,407 |
|
$ |
53,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash stock compensation |
|
$ |
1,790 |
|
$ |
938 |
|
$ |
13,624 |
|
$ |
15,696 |
|
Acquisition and other non-recurring expense |
|
$ |
8,487 |
|
$ |
7,396 |
|
$ |
29,807 |
|
$ |
15,085 |
Recurring Cash G&A |
|
$ |
6,571 |
|
$ |
6,894 |
|
$ |
31,975 |
|
$ |
22,673 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Cash G&A Per BOE |
|
$ |
6.32 |
|
$ |
9.54 |
|
$ |
8.91 |
|
$ |
8.00 |
Contact: Cham King AVP Investor Relations
ir@magnumhunterresources.com (832)
203-4560