Exhibit 10(xxiii)

BJU CARRY AND EARNING AGREEMENT

THIS BJU CARRY AND EARNING AGREEMENT (this “Agreement”) executed October 31,
2012 but effective as of November 1, 2012 (the “Effective Date”) is between
ENCANA OIL & GAS (USA) INC., a Delaware corporation (“Encana”), with an address
of 370 17th Street, Suite 1700, Denver, Colorado 80202, and NUCOR ENERGY
HOLDINGS INC., a Delaware corporation (“Nucor”), and NUCOR CORPORATION
(“Parent”), a Delaware corporation, both with an address of 1915 Rexford Road,
Charlotte, North Carolina 28211. Encana and Nucor may be referred to herein,
individually, as a “Party” and, collectively, as the “Parties.”

RECITALS

A. Encana owns oil and gas leasehold and mineral interests and may acquire
additional interests (collectively, the “Oil and Gas Interests”) in certain
lands comprising the Big Jimmy Unit in the Piceance Basin in Garfield and Rio
Blanco Counties, Colorado, within the area outlined on Exhibit A attached
hereto, from the surface to the base of the Formation (the “Property”).

B. Nucor desires to participate in the development of Encana’s Oil and Gas
Interests in the Property by paying a portion of the costs incurred by Encana
associated with the drilling, completing, and equipping of Carry Wells in
exchange for an undivided fifty percent (50%) of Encana’s interest from the
surface to the base of the Formation in and to the wellbores of such Carry
Wells, the oil and gas production therefrom, and the tubulars and equipment
therein and thereon. Nucor may propose and participate in additional Head’s Up
Wells as described below.

C. The Parties desire to enter into this Agreement to govern their rights and
obligations with respect to exploration and development of the Property.

AGREEMENT

IN CONSIDERATION OF ONE HUNDRED DOLLARS ($100) and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
Parties hereby agree as follows:

Definitions

For purposes of this Agreement, the following terms and phrases shall have the
following meanings:

“Acquiring Party” is defined in Section 22.2.

“Acquisition Costs” is defined in Section 22.2

“AFE” means that Authority for Expenditure to be tendered by Encana to Nucor for
each Carry Well or Head’s Up Well reflecting the estimated costs to drill,
complete, and equip, or plug and abandon, each Nucor Well.

[***] Certain confidential information contained in this document, marked by
bracketed asterisks, has been omitted and filed separately with the Securities
and Exchange Commission pursuant to Rule 24b-2 of the Securities Exchange Act of
1934, as amended.

 

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“Affiliate” means, as to the Person specified, any Person controlling,
controlled by or under common control with such specified Person. The concept of
control, controlling, or controlled as used with respect to any Person means the
possession, directly or indirectly, of the power to direct or cause the
direction of the management and policies of such Person, whether through the
ownership of voting securities, by contract, or otherwise. No Person shall be
deemed an Affiliate of any Person solely by reason of the exercise or existence
of rights, interests, or remedies created or arising under this Agreement.

“AMI Area” means all of the lands coextensive with the area outlined on Exhibit
A attached hereto.

“AMI Interests” means royalty interests, overriding royalty interests,
nonparticipating royalty interests, net profits interests, and similar interests
in effect during the AMI Term over any of the lands comprising the AMI Area. AMI
Interests do not include leasehold or mineral interests.

“AMI Purchase Price” is defined in Section 22.2.

“AMI Term” is defined in Section 22.1.

“Applicable Law” means any applicable statute, law (including common law),
regulation, rule, ruling, order, writ, injunction, or decree of or by any
Governmental Authority.

“Arbitrators” is defined in Section 18.

“Base Price” is defined in Section 2.3 A.

“Business Day” means a day, other than Saturday or Sunday, on which commercial
banks are open for business with the public in New York, New York.

“Carried working interest” is defined in Section 4.2.

“Carry Price” is defined in Section 2.2 C.

“Carry Well Threshold” is defined in Section 2.4 C.

“Carry Wells” means the oil and gas wells contemplated to be drilled to the
Formation on the Property by the Parties under this Agreement pursuant to
Section 2.2.

“Change of Control” means (a) with respect to Encana, (i) a sale of all or
substantially all of the assets of Encana or (ii) a transaction which results in
Encana no longer being an Affiliate of Encana Corporation or any successor to
Encana Corporation, and (b) with respect to Nucor, (i) a sale of all or
substantially all of the assets of Nucor or (ii) a transaction which results in
Nucor no longer being an Affiliate of Nucor Corporation or any successor to
Nucor Corporation.

“Commencement of drilling operations” or “commence drilling operations” means,
with respect to any Nucor Well, the date that a drilling rig capable of reaching
the Formation is rigged up and rotating under power on the Well Location for
such well.

 

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“Completed, complete, or completing” with respect to any Nucor Well, means that
point in time when a Nucor Well is (i) drilled to a depth sufficient to test the
Member; and (ii) either (a) equipped for oil and gas production from the
Formation (including, without limitation, setting production casing and
installing, if applicable, downhole safety valves, packers, and tubing and an
appropriate wellhead / Christmas tree), or (b) plugged and abandoned in
accordance with Applicable Law.

“Composite PPI” means Composite Producer Price Index. The Composite PPI is the
weighted average of the Producer Price Indices shown on Exhibit B, weighted in
the proportions shown on Exhibit B.

“Costs of completing” a Nucor Well means all actual direct costs plus per well
drilling well rate overhead charges under the New Operating Agreement incurred
in completing such well, including but not limited to, the costs of fracture
stimulation, installing lines for frac fluid, and the drilling out of frac plugs
with respect to such well, regardless of when such cost is incurred.

“Costs of drilling” a Nucor Well means all actual direct costs plus per well
drilling well rate overhead charges under the New Operating Agreement relating
to the drilling of such well incurred from and after the date two (2) years
prior to the Effective Date hereof (except that the two (2) year requirement
shall not apply with respect to the costs of drilling the Pre-Effective Date
Carry Wells), including but not limited to, costs of constructing and upgrading
access roads, obtaining and preparing the Wellpad, obtaining permits and title
opinions, obtaining drilling contractor services and consultants necessary for
the drilling of such well, obtaining mud chemicals, pipe and supplies and all
other costs and expenses associated with or incurred in moving in, rigging up,
drilling, logging and testing so that a decision can be made to either attempt
to set pipe and complete such well or to plug and abandon it as a dry hole.

“Costs of equipping” a Nucor Well means all actual direct costs plus per well
drilling well rate overhead charges to the extent properly chargeable under the
New Operating Agreement incurred in the acquisition and installation of the
initial equipment for such well, including but not limited to, the acquisition
and installation of wellhead and Wellpad equipment (including but not limited
to, associated flowlines, Wellpad separation facilities, Wellpad tanks and
storage facilities, measurement/metering equipment, power lines and electrical
facilities, and expansions and improvements of such wellhead and Wellpad
equipment), regardless of when such cost is incurred.

“Cumulative Amount” is defined in Section 2.2 D.

“Damages” means losses, damages (whether compensatory, punitive, consequential,
or special in nature, but excluding a Party’s own exemplary or punitive
damages), obligations, liabilities, demands, claims, costs and expenses
(including, but not limited to, reasonable attorneys’ fees, expenses, and court
costs).

“Defaulting Party” is defined in Section 9.

“Effective Date” is defined in the heading.

 

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“Encana” means Encana Oil & Gas (USA) Inc.

“Environmental Condition” means (a) any release of any Hazardous Materials into
the air or into or on the soil, sediments, surface water, or groundwater on,
under, or from, or migrating from, the Oil and Gas Interests (or adjoining
lands) or any Nucor Well or other well, or (b) any breach, in any material
respect, of any Environmental Law.

“Environmental Damages” means Damages arising with respect to any Environmental
Condition including, without limitation, those relating to the presence,
release, discharge, or threatened discharge of any Hazardous Material in or into
the air, surface water, ground water, soil, land surface, or subsurface strata;
Damages incurred in investigating and remediating such presence, release,
discharge, or threatened discharge; and Damages relating to Hazardous Materials.
Environmental Damages include investigatory costs mandated by a Government
Authority based upon suspected contamination by Hazardous Materials, and any
reasonable consultant and lab fees that arise out of or relate to any actual or
suspected Environmental Condition involving the Well Locations or the Nucor
Wells or under any Environmental Laws.

“Environmental Laws” means all applicable laws, statutes, regulations, rules,
ordinances, codes, licenses, permits, orders, approvals, plans, authorizations,
concessions, franchises, and similar items, as amended, of all governmental
agencies, departments, commissions, boards, bureaus, or instrumentalities of the
United States, and the states and political subdivisions thereof, and all
principles of common law, pertaining to the health, safety, or protection of the
environment, and/or Damages thereto, including, without limitation, CERCLA, the
Clean Air Act, the Federal Water Pollution Control Act, the Resource
Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substances
Control Act, the Hazardous Materials Transportation Act, and the Oil Pollution
Act.

“Excess Well Costs” is defined in Section 2.2 B.

“Existing Drilling Program” is defined in Section 2.1 F.

“Formation” means the [***].

“Force majeure event” is defined in Section 6.

“Force-pooled Owner” is defined in Section 2.1 H(v).

“Governmental Authority” means any federal, state, tribal or local government or
any court, arbitral tribunal, administrative or regulatory agency or commission
or other governmental authority instrumentality or political subdivision
thereof.

“Hazardous Materials” means any substance, product, waste, or other material
which is, or becomes identified, listed, published, or defined as a hazardous
substance, hazardous waste, hazardous material, toxic substance, solid waste or
pollutant, or which is otherwise regulated or restricted under any Applicable
Law (including any Environmental Law) or permits, licenses, or other Government
Authority approvals, including the Comprehensive Environmental Response
Compensation and Liability Act (CERCLA), the Superfund Amendments and
Reauthorization

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

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Act (SARA), the Hazardous Materials Transportation Act, the Resources
Conservation and Recovery Act (RCRA), the Toxic Substances Control Act (TSCA),
the Clean Water Act and the Oil Pollution Act of 1990 (OPA 90). Without
limitation, Hazardous Materials includes hydrocarbons, asbestos, and
polychlorinated biphenyls.

“Head’s Up Well” means a well proposed by either Party to be drilled to the
Formation on the Oil and Gas Interests in the Property in excess of the number
of Carry Wells described in Section 2.2.

“HUW Restriction” is defined in Section 2.4 B.

“Individual Carry Well Cap” is defined in Section 2.2 B.

“Individual Nucor Well Cost” means [***].

“JIB” means Joint Interest Billing.

“Knowledge,” of a Party shall mean, for purposes of this Agreement, the actual
knowledge of the Party at the time the assertion regarding knowledge is made. If
the Party is a corporation or other entity other than a natural person,
knowledge of such Party shall mean the actual knowledge on the part of the
person having authority over the matters to which such knowledge pertains. An
individual will be deemed to have actual knowledge of a particular matter if
such individual is actually aware of such fact or other matter, or has an
awareness or an understanding of such information as would lead a reasonable
person to inquire further.

“Member” means the Williams Fork Member of the Formation.

“New Operating Agreement” is defined in Section 4.1.

“Nucor” means Nucor Energy Holdings Inc.

“Nucor Carry,” with respect to any Carry Well, means the difference between
fifty percent (50%) of the Individual Nucor Well Cost and the Nucor Cost Share,
without consideration of Excess Well Costs.

“Nucor Cost Share” is defined in Section 2.2 B.

“Nucor Head’s Up Share” means Nucor’s share of all costs for a Head’s Up Well.

“Nucor Wells” means (i) the Carry Wells to be drilled by the Parties pursuant to
this Agreement and (ii) the Head’s Up Wells in which Nucor elects to
participate, the number of which shall not exceed the Well Limit, subject to
Section 2.4 E.

“NYMEX” means New York Mercantile Exchange, and the NYMEX website is
www.cmegroup.com.

“Oil and Gas Interests” is defined in Recital A.

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

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“Parent” means Nucor Corporation.

“Party” and “Parties” are defined in the heading.

“Permitted Encumbrances” means (i) lessor’s royalties, overrides and all other
burdens of record as of the Effective Date under the Oil and Gas Interests
including, without limitation, the Encana overriding royalty interest under
Sections 2.1 H (i)(c) and 2.1 H (i)(d) and the Encana royalty interest under
Section 2.1 H (iv); (ii) all federal, state, local, and tribal regulatory orders
and rules to which the Oil and Gas Interests are presently subject, and the
express terms and provisions of the Oil and Gas Interests; (iii) preferential
rights to purchase and required Third Party consents to assignments and similar
agreements with respect to which (A) waivers or consents have been obtained from
the appropriate parties, or (B) notice has been given to the holders of such
rights and the appropriate time period for asserting such rights has expired
without an exercise of such rights; (iv) liens for taxes or assessments not due
or not delinquent as of the Effective Date of this Agreement; (v) all rights to
consent by, required notices to, filings with, or other actions by Governmental
Authority in connection with the drilling and development of the Oil and Gas
Interests that are customarily obtained prior to the commencement of drilling
operations; (vi) surface estates, leases, easements, rights-of-way, servitudes,
permits, and other rights in respect of surface operations, pipelines, or the
like; and easements for pipelines, and other easements and rights-of-way, on,
over or in respect of any of the Oil and Gas Interests; (vii) liens of Third
Party vendors or service providers over the Oil and Gas Interests relating to
obligations not yet due or pursuant to which Encana is not delinquent;
(viii) the terms of the royalty payment formula for certain Oil and Gas
Interests referred to in the Memorandum of Agreement recorded as Reception
Number 767957 in Garfield County, Colorado and as Reception Number 295765 in Rio
Blanco County, Colorado; and (ix) title problems commonly encountered in the oil
and gas business which would not be considered material by a reasonable and
prudent operator in the Colorado Piceance Basin engaged in the business of the
ownership, drilling, development, and operation of oil and gas interests with
knowledge of all the facts and appreciation of their legal significance.

“Person” means any Governmental Authority or any individual, firm, partnership,
limited partnership, corporation, limited liability company, joint venture,
trust, unincorporated organization, or other entity or organization.

“Pre-Effective Date Carry Wells” is defined in Section 2.2 A.

“Price” is defined in Section 2.3 A.

“Property” is defined in Recital A.

“Rig Limitation Period” is defined in Section 2.2 A.

“Spud Date” means, with respect to any Nucor Well, the date of commencement of
setting surface casing with a surface casing rig.

“Suspension Notice” is defined in Section 2.3 A.

“Term” of this Agreement is set forth in Section 7.

 

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“Third Party” means any Person other than Encana, Nucor, or any of their
Affiliates.

“Undivided Interest” is defined in Section 22.3.

“Well Limit” means 3,850 wells.

“Well Location” means the legal location selected for each Nucor Well on the Oil
and Gas Interests in the Property.

“Wellbore Assignment” is defined in Section 2.1 H, and shall cover all depths
from the surface to the deepest depth drilled in a Nucor Well.

“Wellpad” means the location of wellheads and associated production facilities
for one or more Nucor Wells.

Section 1.

Exhibits and Schedules

The following Exhibits and Schedules are attached hereto and shall be considered
part of this Agreement:

 

1.1 Exhibit A – Property

 

1.2 Exhibit B – Producer Price Index Data

 

1.3 Exhibit C – Form of Wellbore Assignment for Carry Wells

 

1.4 Exhibit D – Tax Partnership Agreement

 

1.5 Exhibit E – Form of New Operating Agreement

 

1.6 Schedule 2.2 A – Pre-Effective Date Carry Wells

 

1.7 Schedule 5.2 – Encana and Affiliate Burdens over the Property

Section 2.

Drilling of Nucor Wells

 

2.1 General Provisions Relating to Nucor Wells.

A. Well Locations and Depth. Encana shall act in good faith with regard to the
best interests of each of the Parties hereto to determine the optimum Well
Locations for all Nucor Wells on the Oil and Gas Interests in the Property based
upon its analysis of the anticipated total estimated recovery, Individual Nucor
Well Costs, the status of title, and the absence of Environmental Conditions.
Prior to commencing drilling operations for any Nucor Well, Encana will present
to Nucor its selected Well Location, together with any relevant geological,
geophysical, engineering, title and environmental materials, information, and
reports, applicable Third Party joint operating agreements and any other Third
Party agreements burdening or in effect over the Well Location. All Well
Locations shall be at legal locations in accordance with

 

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Applicable Law. Each Carry Well shall be drilled to a depth sufficient to test
adequately the Member, or as otherwise agreed by the Parties. Once Encana has
commenced drilling operations on any Nucor Well, it shall diligently proceed
with the drilling and completing of such well.

B. Periodic Planning Meetings. On or before June 1 of each year, commencing in
2013, the Parties shall meet to discuss drilling plans with respect to the
Property, including the number of Carry Wells proposed by Encana and proposed
well locations, the number of Head’s Up Wells proposed by each Party (subject to
the restrictions in Section 2.4) and proposed well locations, an estimate of
Encana’s drilling schedule and Spud Dates, and the estimated costs of the
proposed wells. Nucor may not propose a Head’s Up Well on a wellpad from which
wells have been drilled for the Existing Drilling Program. Nucor shall not be
required to provide the exact bottomhole location of a Head’s Up Well but shall
provide at least a proposed section, township and range. The Parties shall
consult to determine and approve the Well Locations; provided, however, that if
Encana and Nucor are unable to agree on any Well Location, Encana shall
determine the Well Location. Encana shall also determine the Spud Dates for
Nucor Wells. With respect to Nucor Wells drilled in calendar year 2015 and
thereafter, if Encana has proposed fewer than [***] Carry Wells and Nucor has
proposed Head’s Up Wells, then at Encana’s election, the first [***] Nucor Wells
drilled shall be Carry Wells.

C. AFEs for Nucor Wells. At least thirty (30) days prior to the anticipated Spud
Date for a Carry Well and at least ninety (90) days prior to the anticipated
Spud Date for a Head’s Up Well, Encana shall issue to Nucor an Authorization for
Expenditure (“AFE”) for each Nucor Well (i) identifying each such well as a
Carry Well or a Head’s Up Well (together with a specific description of the Well
Locations and the survey plat and wellbore diagram for such well), (ii) showing
the Nucor Carry (if such well is a Carry Well), (iii) setting forth Encana’s
best estimate of the Individual Nucor Well Cost based upon historical costs and
current market information and any Third Party bids, (iv) providing the total
that Nucor is expected to pay by virtue of each AFE, and (v) setting forth the
anticipated Spud Date of the Nucor Well.

D. Proportionate Reduction; Third Party Nonconsent Costs. If Encana owns less
than one hundred percent (100%) of the Oil and Gas Interests comprising any
Nucor Well, then the interests of Encana and Nucor in such Nucor Well, and in
the case of a Carry Well, the Individual Carry Well Cap and Nucor Cost Share,
shall be reduced in proportion to the actual Oil and Gas Interest owned by
Encana in each such Nucor Well. With respect to a Carry Well or a Head’s Up Well
in which both Parties have elected to participate, Nucor and Encana shall bear
equally the costs of drilling, completing, and equipping any such well which are
attributable to the interest of any Third Party working interest owner who has
elected not to participate in the drilling of such well under any applicable
Third Party joint operating agreement, or otherwise, and shall be entitled to
the corresponding amount of any interest or right to production occurring by
reason of the failure of such working interest owner to participate. With
respect to a Head’s Up Well in which Encana has elected not to participate,
Encana shall not bear any of the costs of drilling, completing, and equipping
any such well which are attributable to the interest of a Third Party working
interest owner who has elected not to participate in the drilling of such well,
but Encana shall be entitled to any interest or right to production with respect
to its carried working interest percentage as set forth in Section 4.2. The case
of a Force-pooled Owner who does not participate in the drilling of a well is
addressed in Section 2.1 H(v).

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

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E. Land Costs; Affiliated Services. With respect to each Well Location, during
the Term of this Agreement, Nucor shall not bear any acquisition costs or lease
bonuses for any Oil and Gas Interests owned by Encana or any of its Affiliates.
In addition, Nucor may elect to participate in geologic and geophysical
activities and data gathering on or related to the Property, but Nucor shall not
be required to participate. If Nucor elects to participate, it shall bear its
share of the cost of such activity and shall be provided with any resulting
data. If Nucor does not bear its share of the costs of such activity, it shall
not be entitled to the data. For the avoidance of doubt, Nucor shall bear its
share of the costs of downhole microseismic or other downhole geophysical
activity. Furthermore, if Encana (or any of its Affiliates) conducts or provides
any of the drilling, completing, or equipping operations, services, equipment,
or materials on any Nucor Well, then it shall do so in a prudent and efficient
manner, and it shall charge no more than the prevailing market rate for such
operations, services, equipment, or materials which would be charged by a Third
Party contractor in a bona fide arm’s length transaction. If there are costs
related to both Nucor Wells and non-Nucor Wells, such costs shall be pro-rated
as applicable. After the Effective Date, if either Party, or any of its
Affiliates, acquires any mineral or leasehold interest within the boundaries of
the Property, then such interest will be subject to this Agreement. Only Head’s
Up Wells shall be proposed and drilled on any mineral or leasehold interest
within the boundaries of the Property acquired by Nucor or any of its
Affiliates. In any such Head’s Up Well drilled on a Nucor mineral or leasehold
interest, Encana will receive from Nucor a wellbore assignment in substantially
the form attached hereto as Exhibit C of (i) an undivided fifty percent
(50%) interest, (ii) one hundred percent (100%) interest, or (iii) two and
one-half percent (2.5%) interest, as applicable, depending upon Encana’s level
of participation in any such well.

F. Restriction on Other Drilling Programs. Except for the presently existing
drilling program with a Third Party that includes up to one hundred fifty
(150) wells to be drilled on the Property (the “Existing Drilling Program”),
until the Nucor Wells reach the Well Limit, (i) Encana shall not enter into any
other drilling program with any party other than Nucor for the drilling and
completion of wells above the base of the Formation on the Property, and
(ii) Encana shall not increase the number of wells to be drilled to the
Formation on the Property in the Existing Drilling Program to more than one
hundred fifty (150) wells. Furthermore, until the Well Limit is reached, Encana
shall not drill and complete any well on the Property above the base of the
Formation for its own account unless such wells are Head’s Up Wells proposed by
Encana in which Nucor elects not to participate.

G. Payment of Nucor Cost Share and Nucor Head’s Up Share. Except as provided in
Section 4.2, Nucor shall pay Encana the Nucor Cost Share and Nucor Head’s Up
Share by wire transfer to Encana by the fifteenth (15th) day of the month
following Nucor’s receipt of a JIB invoice from Encana. If the fifteenth
(15th) day of the month falls on a weekend or holiday, then payment shall be
made on the preceding Business Day. The proceeds of each payment shall be used
by Encana solely and exclusively for Individual Nucor Well Costs. After spudding
a Nucor Well, Encana shall drill and complete such Nucor Well with due diligence
and in a good and workmanlike manner, in accordance with good oil field practice
as a reasonable and prudent Piceance Basin oil and gas operator.

H. Wellbore Assignment in Nucor Wells.

 

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(i) Provided Nucor has paid the Nucor Cost Share and the Nucor Head’s Up Share
then due and owing, then on or before the thirtieth (30th) day after the end of
each calendar quarter for each Nucor Well drilled and completed as a producer in
the prior calendar quarter, Encana shall execute, acknowledge, and deliver to
Nucor sufficient counterparts of a wellbore assignment which shall comply with
the recordation requirements of any Governmental Authority with whom Encana
would appropriately record such wellbore assignment on behalf of Nucor, and
which shall otherwise be in substantially the form attached hereto as Exhibit C
(the “Wellbore Assignment”). Each Wellbore Assignment shall:

(a) be effective as of the date of first production of each Nucor Well,

(b) be subject only to those lessor’s royalties, overrides and other burdens of
record in existence on the later of the Effective Date or the date of
acquisition of the Oil and Gas Interest, those royalties described in
(iv) below, or, in the case of overrides owned by Encana or its Affiliates, be
subject only to those which are disclosed in Schedule 5.2,

(c) with respect to a Carry Well, assign to Nucor an undivided fifty percent
(50%) of Encana’s interest, but not including any royalty or overriding royalty
interest owned by Encana, in and to (A) the wellbore of such Carry Well, and
(B) all oil and gas production therefrom, and a like interest in the oil and gas
leases associated with such wellbore, insofar and only insofar as are sufficient
to produce and own an undivided fifty percent (50%) of Encana’s interest in and
to the oil, gas, gas condensate, casinghead gas and other liquid and gaseous
hydrocarbons produced from the wellbore of the Carry Well, and (C) all casing,
tubulars, downhole pumps, fixtures and equipment and wellhead and surface
equipment (limited only to equipment for such Carry Well), and

(d) with respect to a Head’s Up Well, assign to Nucor either an undivided fifty
percent (50%) of Encana’s interest, or ninety-seven and one-half percent
(97.5%) of Encana’s interest if Encana has elected not to participate in such
well, as applicable, but in either case not including any royalty or overriding
royalty interest owned by Encana, in and to (A) the wellbore of such Head’s Up
Well, and (B) all oil and gas production therefrom, and a like interest in the
oil and gas leases associated with such wellbore, insofar and only insofar as
are sufficient to produce and own an undivided fifty percent (50%), or
ninety-seven and one-half percent (97.5%), as applicable, of Encana’s interest
in and to the oil, gas, gas condensate, casinghead gas and other liquid and
gaseous hydrocarbons produced from the wellbore of the Head’s Up Well in which
Encana has elected not to participate, and (C) a like interest in and to all
casing, tubulars, downhole pumps, fixtures and equipment and wellhead and
surface equipment (limited only to equipment for such Head’s Up Well).

(ii) The Wellbore Assignment shall be in recordable form, and shall contain
legally-sufficient property descriptions.

 

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(iii) The Wellbore Assignment shall contain a special warranty of title by,
through, or under Encana, but not otherwise.

(iv) If any Nucor Well includes a mineral interest owned by Encana or an
Affiliate that is not subject to a lease, then such mineral interest will
receive a royalty interest payable to Encana or such Affiliate of 16.67% (which
royalty interest shall be borne (a) equally by Nucor and Encana, (b) by Encana
as the sole participating Party if Nucor elects not to participate in a Head’s
up Well, or (c) in the proportions set forth in Section 4.2, as applicable),
which interest shall be proportionately reduced if the Encana mineral interest
covers less than the full interest in the wellbore of the Nucor Well.

(v) Nucor and Encana shall each bear fifty percent (50%) of the drilling,
completing, and equipping costs attributable to the interest of any working
interest owner pooled pursuant to the provisions of Colorado Revised Statutes
§34-60-116, as amended (a “Force-pooled Owner”) who does not participate in the
drilling of a Carry Well or a Head’s up Well in which both Parties have elected
to participate (subject to the interest of any other Third Party working
interest owner who has elected to participate). The Wellbore Assignment to Nucor
shall include the right to receive one-half (1/2) of the revenue attributable to
the interest of such Force-pooled Owner, and the interest reflected in the
Wellbore Assignment for casing, tubulars, downhole pumps, fixtures and equipment
will be increased to reflect Nucor’s interest. Nucor shall bear one hundred
percent (100%) of the drilling, completing, and equipping costs attributable to
the interest of any Force-pooled Owner in any Head’s Up Well in which Encana has
elected not to participate in accordance with Section 4.2 below.

(vi) The Wellbore Assignment shall be made subject to the terms and conditions
of any existing operating agreement with a Third Party, any pooling or
unitization agreement and any applicable Third Party agreements. Nucor’s
interest in the Nucor Wells shall include the right to participate, in
accordance with the terms of the New Operating Agreement, for its proportionate
interest in any subsequent completions or recompletions in the wellbore.

(vii) It is expressly agreed and understood that the interest to be assigned to
Nucor in any Nucor Well shall be proportionately reduced to the extent that
Encana owns less than an undivided 100% working interest in the Carry Well.

I. Well Takeover. If any Nucor Well is determined by Encana to be a dry hole or
cannot otherwise be completed as a producer to the Formation and Encana elects
to continue drilling operations below the Formation, then Nucor may elect to
participate in such drilling operation. If Nucor elects to participate, then
(i) with respect to a Carry Well, Nucor shall pay the Nucor Cost Share of such
Nucor Well without regard to the Individual Carry Well Cap, and (ii) with
respect to a Head’s Up Well, Nucor shall pay its proportionate share of costs.
Encana shall make a wellbore assignment to Nucor in accordance with Section 2.1
H, provided that such assignment shall be made to the total depth drilled. Nucor
shall make its election with regard to participation within forty-eight hours
(48) hours of telephone notice from Encana. If Nucor does not elect to
participate in such drilling operation, then Encana promptly shall reimburse
Nucor all costs of drilling paid by Nucor with respect to such Nucor Well, and
shall indemnify and hold Nucor harmless from any losses or liability with
respect to such well including, without limitation, plugging and abandonment
obligations or Environmental Damages with respect to such well.

 

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J. Use of Nucor Steel and Steel Products. Encana shall use its commercially
reasonable best efforts to utilize Nucor steel and steel products, provided such
products are readily available, meet Encana’s requirements, and are
competitively priced, for tubulars and other downhole equipment to be installed
in all Nucor Wells. For greater clarity, such consideration shall not in any way
disadvantage the cost of a proposed Nucor Well.

K. Operation of Nucor Wells. After a Nucor Well is drilled, completed, and
equipped, Encana and Nucor shall each bear and pay its working interest share of
the costs and expenses of such Nucor Well in accordance with the New Operating
Agreement. Subject to Section 9 and provided Nucor has paid the Nucor Cost Share
or Nucor Head’s Up Share, as applicable, of costs of such well then due and
owing, Nucor shall be entitled to, and Encana shall tender to Nucor, its net
revenue interest share of production (or the proceeds from the sale thereof)
from each such Nucor Well from the date of first production, notwithstanding
that the applicable Wellbore Assignment has not yet been made.

L. Tax Partnership. On the date of execution of this Agreement, the Parties
shall enter into a tax partnership agreement in the form set forth in Exhibit D.

 

2.2 Carry Wells.

A. Number of Carry Wells; Rig Limitation Period; Pre-Effective Date Carry Wells.
Unless otherwise agreed by the Parties, Encana shall not (i) spud more than
[***] Carry Wells (including the Pre-Effective Date Carry Wells) in calendar
year 2012 or (ii) conduct drilling operations for Carry Wells with an average of
more than [***] drilling rigs throughout calendar year 2013, and shall not
conduct drilling operations for Carry Wells with an average of more than [***]
drilling rigs throughout calendar year 2014 (the “Rig Limitation Period”);
provided, however, if the average price for natural gas as reported by Platts
Inside FERC’s Gas Market Report (Platts IFERC) Colorado Interstate Gas Co. Rocky
Mountains for the three (3) months preceding the then-current month exceeds
$[***], then Encana shall have the option to operate one (1) additional drilling
rig to drill Carry Wells for the remaining term of the Rig Limitation Period.
For calendar year 2015 and thereafter, Encana shall spud a minimum of [***] and
a maximum of [***] Carry Wells in each calendar year until such time as the
Carry Well Threshold has been met. The Parties recognize and acknowledge that,
prior to the date of execution of this Agreement, Encana has spud or drilled,
but not completed or equipped, those wells described in Schedule 2.2 A (the
“Pre-Effective Date Carry Wells”). The wells described in Schedule 2.2 A shall
be considered as Carry Wells for all purposes hereunder and costs with respect
to such wells shall be paid by Nucor as provided in Section 2.2 B. Encana shall
diligently complete the Pre-Effective Date Carry Wells and, in accordance with
Section 2.1 H, Encana shall execute, acknowledge, and deliver to Nucor
appropriate Wellbore Assignments for the Pre-Effective Date Carry Wells.

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

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B. Costs of Carry Wells. Except as provided in Section 2.2 D, Nucor shall pay
not less than [***] and not more than [***] of the Individual Nucor Well Cost
for each Carry Well (the “Nucor Cost Share”) as further described in Section 2.2
C; provided that if the Individual Nucor Well Cost exceeds $[***] for a Carry
Well (the “Individual Carry Well Cap”), then the Individual Nucor Well Cost for
such Carry Well in excess of the Individual Carry Well Cap (the “Excess Well
Costs”) will be borne fifty percent (50%) by Encana and fifty percent (50%) by
Nucor. From and after the Effective Date, Nucor shall pay the Nucor Cost Share
(subject to Section 2.2 D) and fifty percent (50%) of Excess Well Costs, as
applicable, of the Pre-Effective Date Carry Wells. The provisions of this
Section 2.2 B regarding the Individual Carry Well Cap and adjustments thereto
shall apply to the Pre-Effective Date Carry Wells, and all costs incurred for
such wells, regardless of when they are incurred, shall be included when
determining if the Individual Carry Well Cap has been reached. Except as
provided in Section 2.2 D, the Nucor Cost Share shall be [***] for Carry Wells
spud in 2012.

[***]

C. Determination of Nucor Carry. [***]

D. 100% Nucor Cost Share Period. Notwithstanding the foregoing, the Nucor Cost
Share for Carry Wells spud after the Effective Date shall be [***] until the
cumulative amount of the Nucor Carry paid by Nucor equals the sum of (i) [***]
of the costs of drilling, completing and equipping the Pre-Effective Date Carry
Wells (but not costs in excess of the Individual Carry Well Cap) incurred prior
to the Effective Date, plus (ii) [***] of the Excess Well Costs of drilling,
completing and equipping the Pre-Effective Date Carry Wells incurred prior to
the Effective Date. The foregoing amount is referred to as the “Cumulative
Amount.” The Individual Carry Well Cap shall not apply to the cost of Carry
Wells until the Cumulative Amount is reached.

E. Horizontal Wells. The Parties acknowledge that the provisions of this
Section 2.2 with respect to number of Carry Wells and the amount of the
Individual Carry Well Cap and the provisions of Section 2.4 with respect the
number of Head’s Up Wells do not apply to horizontal wells. If horizontal wells
are drilled, the Individual Carry Well Cap shall be no less than [***] of the
actual Individual Nucor Well Cost for such horizontal well. For the purpose of
determining the number of Nucor Wells counted toward the Well Limit if a
horizontal well is drilled, the Parties shall endeavor to agree upon the number
of vertical wells displaced by such horizontal well and such agreed upon number
shall be used in the calculation of the Well Limit. For the avoidance of doubt,
the provisions of Section 2.4 E shall also apply in the calculation of the Well
Limit.

 

2.3 Ability to Suspend Funding of Carry Wells. [***]

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

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2.4 Head’s Up Wells.

A. Election to Participate in Head’s Up Wells. At least sixty-five (65) days
prior to the anticipated Spud Date of a Head’s Up Well, each Party shall notify
the other Party whether it elects to participate in such well. Failure of a
Party to elect to participate in a Head’s Up Well shall be deemed an election
not to participate in such well. At its discretion, Encana may simultaneously
conduct drilling operations for Carry Wells and Head’s Up Wells subject to the
Rig Limitation Period.

B. HUW Restriction. At the planning meeting to be held in 2014 in accordance
with Section 2.1 B to establish the well selection and drilling schedule for
calendar year 2015 and continuing each year thereafter until the Carry Well
Threshold is paid by Nucor, Nucor shall have the right to propose to Encana
Head’s Up Wells to the Formation on the Oil and Gas Interests in the Property in
excess of the number of Carry Wells described in Section 2.2; provided, however,
that (i) the number of additional wells to be spudded pursuant to this section
in calendar year 2015 and subsequent calendar years until the Carry Well
Threshold is paid by Nucor shall not exceed [***] of the number of Carry Wells
spudded in the prior calendar year (the “HUW Restriction”). Prior to meeting the
Carry Well Threshold, if, due to a Suspension Notice delivered to Nucor by
Encana in the prior (or any previous) year, the Parties have drilled fewer than
[***] Carry Wells, then Nucor may propose up to [***] Head’s Up Wells to be
drilled in a subsequent calendar year. Until the Well Limit is reached, in any
calendar year, Encana shall not propose more than [***] Head’s Up Wells until
the Carry Well Threshold is paid by Nucor and no more than [***] Head’s Up Wells
after the Carry Well Threshold is paid by Nucor.

C. Satisfaction of Carry Well Threshold. Nucor shall have satisfied its
obligation to fund Carry Wells under this Agreement from and after the time that
the cumulative amount of the Nucor Carry paid by Nucor equals $[***] with
respect to the Carry Wells (the “Carry Well Threshold”). Thereafter, Nucor may
schedule a planning meeting and propose to Encana the drilling of additional
wells to the Formation in the current calendar year without regard to the HUW
Restriction; provided, however, that Nucor may propose no more than [***] Head’s
Up Wells to be drilled in any calendar year. The maximum number of Head’s Up
Wells that Nucor may propose in the calendar year in which the Carry Well
Threshold has been achieved shall be determined by multiplying [***] by a
fraction, the numerator of which is the number of days remaining in the calendar
year, and the denominator of which is three hundred sixty-five (365). Encana
shall use its reasonable best efforts to spud all proposed Head’s Up Wells in
the calendar year reflected in the annual drilling schedule determined by the
Parties at the annual planning meeting under Section 2.1 B or as set forth
above. If Encana is unable to spud all scheduled Head’s Up Wells within a
particular calendar year, then it shall not commence drilling operations on any
Carry Wells for the next calendar year until all previously scheduled Head’s Up
Wells have been spud. Notwithstanding the foregoing, in no event shall the
number of Carry Wells and Head’s Up Wells in which Nucor elects to participate
exceed the Well Limit.

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

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D. Withdrawal of Election to Participate. Nucor may withdraw its election to
participate in any Head’s Up Well in which Encana has elected not to participate
on or before sixty (60) days prior to the Spud Date of such well as set forth on
the AFE for such well; provided, however, Nucor shall bear any and all costs
incurred with respect to such well, including penalties imposed by contracted
service providers such as rig operators and completion service companies. Encana
may withdraw its election to participate in any Head’s Up Well in which Nucor
has elected not to participate at any time prior to the Spud Date of such well
as set forth on the AFE for such well, and Encana shall bear any and all costs
incurred with respect to such well, including penalties imposed by contracted
service providers such as rig operators and completion service companies

E. Calculation of the Number of Nucor Wells. The total number of Nucor Wells
spudded shall not exceed the Well Limit. A Head’s Up Well in which Encana elects
not to participate shall be counted twice for the purpose of determining the
number of Nucor Wells. Any Head’s Up Well proposed by Encana in which Nucor
elects not to participate shall not be counted toward the Well Limit. The
Parties acknowledge that if Nucor elects not to participate in a substantial
number of Head’s Up Wells proposed by Encana, there may not be sufficient Well
Locations available to allow Nucor to propose Head’s Up Wells to reach the Well
Limit.

F. Participation in Head’s Up Wells. The costs for Head’s Up Wells in which both
Parties participate shall be borne fifty percent (50%) by Encana and fifty
percent (50%) by Nucor. If Nucor elects not to participate in a Head’s Up Well,
then it shall pay no portion of the drilling, completing, or equipping costs for
such well, and shall own no interest in such well. If Encana elects not to
participate in a Head’s Up Well and Nucor elects to proceed with such well, then
the Parties shall proceed in accordance with Section 4.2 below.

Section 3.

Title and Other Information

Prior to the commencement of drilling operations on any Nucor Well, Encana will
conduct, or cause to be conducted, title examination of the applicable Well
Location and the relevant Oil and Gas Interests and conduct any necessary title
curative work. When Encana provides Nucor with an AFE, Encana shall deliver to
Nucor copies of all title documentation relating to the Nucor Well in Encana’s
files or to which Encana has access, including, without limitation, all title
opinions and reports, title curative documents, and any applicable Third Party
joint operating agreements. Such title information shall be provided to Nucor
without warranty as to accuracy. Encana shall have no obligation to purchase new
or supplemental abstracts. Encana will undertake curative work in connection
with title to the Carry Wells which is required by the New Operating Agreement
or any other operating agreement applicable to such Carry Well and which a
reasonable and prudent Piceance Basin oil and gas operator would undertake in a
similar situation.

Section 4.

Operations

 

4.1 New Operating Agreement.

Encana and Nucor shall enter into the form of operating agreement attached
hereto as Exhibit E (“New Operating Agreement”) which shall govern all
operations for the Nucor Wells as between the Parties. Encana shall be
designated as operator of all Nucor Wells, and upon the spudding of

 

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a Nucor Well, the New Operating Agreement shall be deemed amended to include
such Nucor Well. In addition, the Parties intend that the New Operating
Agreement shall govern each Party’s election to participate in subsequent
operations on all of the Nucor Wells in which both Parties have an interest. For
the avoidance of doubt, any subsequent operations under the New Operating
Agreement with respect to any Carry Well shall be conducted on a well-by-well
basis, and the costs for the subsequent operations shall be borne fifty percent
(50%) by Encana and fifty percent (50%) by Nucor in accordance with the New
Operating Agreement.

 

4.2 Operation of Head’s Up Wells in which Encana Does Not Participate.

If Encana elects not to participate in a Head’s Up Well and Nucor elects to
proceed with such well, then Encana shall serve as operator of such well under
the New Operating Agreement. Notwithstanding anything to the contrary in this
Agreement, (i) at least thirty (30) days prior to the anticipated Spud Date of a
Head’s Up Well in which Encana elects not to participate, Nucor shall pay to
Encana the amount of the AFE for costs of drilling such well, and (ii) at least
thirty (30) days prior to the anticipated commencement of completion operations
for such well, Nucor shall pay to Encana the amount of the AFE for costs of
completing and costs of equipping such well, such payments to be made by wire
transfer. As compensation for its services as operator of a Head’s Up Well in
which Encana has elected not to participate (in addition to applicable overhead
rates set forth in the New Operating Agreement), Encana shall receive or
reserve, as applicable, an undivided two and one-half percent (2.5%) of 8/8ths
carried working interest in and to such well, proportionately reduced if the
Parties own less than the full leasehold or mineral interest in such well. As
used herein, the term “carried working interest” means that Encana shall bear
none of the costs of drilling, completing, or equipping any Head’s Up Well in
which Encana has elected not to participate, but Encana shall bear two and
one-half percent (2.5%) of 8/8ths (proportionately reduced if the Parties’
collective operating interest covers less than one hundred percent (100%) of the
mineral or leasehold estate) of (i) the monthly well operating costs,
(ii) royalty, severance, ad valorem, and property taxes and other burdens
assessed or imposed against the well or the oil and gas production therefrom,
(iii) the costs of any subsequent operations on said well, and (iv) the plugging
and abandonment costs of any such well which was completed as a well capable of
producing in paying quantities, all in accordance with the New Operating
Agreement.

 

4.3 Conflicts with Existing Operating Agreements.

If any of the Nucor Wells is subject to an existing joint operating agreement
with a Third Party, such existing joint operating agreement shall control as to
such Third Party, and the Wellbore Assignment shall be subject to such existing
joint operating agreement; however, as between Nucor and Encana, this Agreement
and the New Operating Agreement shall control. In the event of any conflict or
inconsistency between the terms of this Agreement and the New Operating
Agreement, this Agreement shall prevail to the extent of such conflict. If Nucor
and/or Encana acquire the entire Oil and Gas Interest governed by an existing
Third Party joint operating agreement, then such Third Party joint operating
agreement shall terminate and be superseded and replaced in its entirety by the
New Operating Agreement.

4.4 Payment of Burdens.

 

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After the Effective Date, if Encana or Nucor creates any additional burdens on
the Property, the Party creating such additional burden shall be solely
responsible for and shall pay such additional burden; provided however, any Oil
and Gas Interest in a Nucor Well owned by Encana or its Affiliate that is not
subject to an oil and gas lease will be subject to a royalty payable to Encana
or such Affiliate of 16.67%, which shall be borne (i) equally by Nucor and
Encana, (ii) by Encana as the sole participating Party in a Head’s Up Well, or
(iii) in the proportions set forth in Section 4.2, as applicable. Subject to the
foregoing sentence, Encana shall make payment of all burdens affecting the Nucor
Wells, and Nucor shall reimburse Encana for Nucor’s portion of all burdens.
Encana shall make shut-in royalty payments, minimum royalty payments, delay
rentals, and similar payments in order to maintain the Oil and Gas Interests on
which Nucor Wells are located in force and effect. The Parties shall bear all of
such payments in proportion to their interest in the Nucor Wells affected.
Encana shall not be liable for any damages resulting from the failure to make
proper payment if such failure is a result of mistake or oversight.

Section 5.

Representations, Warranties and Agreements

 

5.1 Representations and Warranties.

Each Party, with respect to itself only, hereby represents and warrants to the
other Party the following:

A. Each Party is duly organized, validly existing and in good standing under the
Applicable Law of the State of its incorporation or formation, and is qualified
to do business and is in good standing in the State of Colorado and in every
other jurisdiction where the failure to so qualify would have a material adverse
effect on its ability to execute, deliver, and perform this Agreement and the
other agreements contemplated herein.

B. Each Party has all requisite power and authority to (i) own, lease or operate
its assets and properties and to carry on the business as contemplated
hereunder, and (ii) enter into and perform its obligations under this Agreement
and to carry out the transactions contemplated hereby, including the ownership
of interests in federal oil and gas leases.

C. Without diminishing the effects of the specific representations, warranties
and covenants contained in this Agreement, each Party has conducted the
necessary inquiries and due diligence in support of the commitments made
hereunder with full knowledge of the risks and obligations inherent in the
ownership and operation of oil and gas interests.

D. Each Party has taken (or caused to be taken) all acts and other proceedings
required to be taken by such Party to authorize the execution, delivery and
performance by such Party of this Agreement and the other agreements
contemplated herein. This Agreement has been duly executed and delivered by each
Party and constitutes the valid and binding obligation of each Party,
enforceable against such Party in accordance with its terms, except as
enforceability may be limited by applicable bankruptcy, moratorium,
reorganization or similar laws affecting the rights of creditors generally and
by principles of equity, whether considered in a proceeding at law or in equity.
The execution, delivery, and performance of this Agreement by each Party

 

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does not and will not (i) conflict with, or result in any violation of, or
constitute a breach or default (with notice or lapse of time, or both) under
(A) any provision of the organizational documents of such Party, or (B) any
applicable statute, law, rule, regulation, order, agreement, instrument or
license applicable to such Party, except as would not have a material adverse
effect, or (ii) require the submission of any notice, report, consent or other
filing with or from any Governmental Authority or Third Parties, other than such
consents as are customarily obtained after assignment of interests similar to
the Wellbore Assignments.

E. There are no actions, suits or proceedings pending or, to such Party’s
Knowledge, threatened against a Party which if decided unfavorably to such Party
could have a material adverse effect on the ability of such Party to execute,
deliver, or perform this Agreement or could materially affect its title to, or
ownership or operation of, the Oil and Gas Interests, the Well Locations, or the
Carry Wells.

F. No Party has incurred any obligation or liability, contingent or otherwise,
for any fee payable to a broker or finder with respect to the matters provided
for in this Agreement or the other agreements contemplated herein which could be
attributable to or charged to the other Party. Each Party shall indemnify,
defend, and hold harmless the other Party from any claims, damages, liabilities,
costs and expenses, including reasonable attorney’s fees in the event the prior
sentence should be or become untrue as to such Party.

 

5.2 Representations and Warranties of Encana.

Encana hereby represents and warrants to Nucor the following:

A. Schedule 5.2.

attached hereto sets forth all of the overriding royalty, royalty, net profits,
production payment, and other similar interests owned by Encana or its
Affiliates in the Oil and Gas Interests, except that the Oil and Gas Interests
subject to a royalty payable to Encana or its Affiliate of 16.67% in accordance
with Section 4.4 are not set forth in Schedule 5.2. Encana’s interest in the Oil
and Gas Interests comprising the Well Locations on which the Nucor Wells are
drilled will not be subject to any liens or encumbrances of any type or nature
other than the Permitted Encumbrances. As long as Nucor is taking its share of
production from the Oil and Gas Interests in kind, there will be no calls on
production or contracts for sale of production encumbering the Nucor Wells which
provide for the delivery of oil and gas at a price below the prevailing market
price. Prior to drilling a Nucor Well, Encana shall obtain the waiver of all
preferential purchase rights and all consents to assignment that must be
obtained from any Third Parties in order to make a Wellbore Assignment of such
Nucor Well to Nucor.

B. All Oil and Gas Interests comprising the Well Locations on which the Nucor
Wells are drilled will be in full force and effect. Operations with respect to
the Oil and Gas Interests insofar as they pertain to the Nucor Wells will be in
compliance with applicable rules, regulations, statutes, and laws of any
Governmental Authority.

C. Prior to the commencement of drilling operations on any Nucor Well hereunder,
Encana shall have obtained all consents, approvals, certificates, licenses,
permits, and other authorizations of all Third Parties and the necessary
Governmental Authority required for Encana to own, drill, develop, operate, and
maintain the Oil and Gas Interests comprising the Well Location for such Nucor
Well

 

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D. Each Nucor Well shall be drilled within the boundaries of the applicable Oil
and Gas Interest(s) at a legal location in accordance with all spacing and
density regulations of any Governmental Authority. None of the Nucor Wells shall
be subject to penalties or reduced allowables because of any violation of
Applicable Law, rules, regulations, permits, or judgments, orders or decrees of
any court or Governmental Authority.

With respect to each Nucor Well and Well Location, the foregoing representations
and warranties contained in this Section 5.2 shall terminate two (2) years after
the date of each Wellbore Assignment to Nucor of an interest in such Nucor Well
and shall thereafter have no further force and effect.

Section 6.

Force Majeure

If a Party is rendered unable, wholly or in part, by a force majeure event to
carry out its obligations under this Agreement (other than the obligations to
make monetary payments and to deliver Wellbore Assignments of interests in the
Nucor Wells) the affected Party shall give the other Party prompt written notice
describing the force majeure event in reasonable detail. Thereupon, the
obligations of the Party giving notice, so far as it is affected by the force
majeure event, shall be suspended and any time periods provided for in this
Agreement shall be extended for a period equal to the period of the continuance
of the force majeure event. The affected Party shall use all reasonable
diligence to remove the force majeure event as quickly as practicable. The
requirement that any force majeure event be remedied with all reasonable
dispatch shall not require the settlement of strikes, lockouts or other labor
difficulty by the Party affected, contrary to its wishes, and settlement or
resolution of such matters shall be within the discretion of the affected Party.
The term “force majeure event” as used herein, shall mean an act of God, act of
terrorism, strike, lockout, or other industrial disturbance, act of the public
enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion, the
actions of Governmental Authority, restraint or inaction, the interruption or
suspension of the receipt or delivery of natural gas (or any of its
constituents) or water due to the inability or failure of any Third Party who is
not a party to this Agreement (other than an Affiliate of either Party hereto),
to receive or deliver such gas or water, unavailability of equipment, or
inability to gain access, ingress or egress to conduct operations (including
without limitation delays in or inability to obtain permits, approvals or
clearances from Governmental Authority, so long as the Party claiming such force
majeure event uses its commercially reasonable best efforts to obtain any such
permits, approvals or clearances from such Governmental Authority), or other
event beyond the reasonable control of the affected Party.

Section 7.

Term

The term of this Agreement (the “Term”) shall begin on the Effective Date and
shall terminate upon the earlier to occur of (i) the first day of the month
after the Parties, or their successors or permitted assigns, reach the Well
Limit for Nucor Wells and Nucor has paid all amounts for the drilling,
completing, and equipping of Nucor Wells required hereunder, or (ii) 75 years
from the Effective Date hereof.

 

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Section 8.

Assignability

 

8.1 Restrictions on Assignment.

Neither Party may assign or transfer, by assignment, sale, farmout or otherwise,
or pledge or encumber in any way, in whole or in part, any of its rights or
obligations under this Agreement without the express prior written consent of
the other Party, which may be withheld in such other Party’s sole discretion;
provided, however, that the foregoing provision shall not apply to a Change of
Control or an assignment to one (1) or more of a Party’s Affiliates. Encana
hereby unconditionally guarantees to Nucor, its successors and assigns, the
payment and performance of all of Encana’s obligations and covenants hereunder
in the case of an assignment, in whole or in part, to any of its Affiliates.
Prior written consent of the other Party shall not, however, be required for the
assignment or transfer of a Party’s interest in a Nucor Well and the associated
equipment, provided that (i) such assignment or transfer is subject to the
provisions of this Agreement (including all Exhibits hereto) and the New
Operating Agreement and (ii) any such assignment or transfer may be made only
after delivery of the Wellbore Assignment to Nucor. The foregoing sentence shall
not prevent the assignment or transfer by Encana of its interest in a Head’s Up
Well in which Nucor did not participate. Any assignment or transfer of
operations of a Nucor Well by Encana may be made only to a Third Party with
sufficient operating expertise and financial capability to operate such Nucor
Well as a reasonable and prudent operator in the Piceance Basin. Other than as
provided above, until the Well Limit is reached, Encana shall not assign or
transfer a portion of its interest in the Formation in the Property without the
prior written consent of Nucor, which consent Nucor may withhold in its sole
discretion. Any assignee of any interest hereunder shall expressly assume in
writing the obligations and liabilities under all agreements applicable to such
interest, including this Agreement and the New Operating Agreement.

 

8.2 Change of Control.

Notwithstanding anything to the contrary in this Agreement, in the event that a
Change of Control of either Party (the “First Party”) occurs, the other Party
(the “Other Party”) shall have the option to terminate its obligation to fund
additional Carry Wells or to drill additional Nucor Wells, as applicable, under
this Agreement. The First Party shall deliver written notice to the Other Party
of a Change of Control along with information reasonably available to the First
Party regarding the financial position and operational experience of its
successor-in-interest. The Other Party shall have thirty (30) days from the
receipt of such notice to make a one-time election to terminate its obligation
to fund additional Carry Wells or drill additional Nucor Wells, as applicable.
If Nucor elects to cease funding Carry Wells, then it shall not have any further
right to propose or to participate in Head’s Up Wells. If the Other Party fails
to deliver timely written notice to the First Party advising the First Party of
the Other Party’s election, the Other Party shall be obligated to continue to
fund additional Carry Wells or to drill Nucor Wells, as applicable, pursuant to
the terms of this Agreement. If the Other Party elects to terminate its
obligation to fund additional Carry Wells or drill additional Nucor Wells, this
Agreement (including all Exhibits hereto) shall continue in full force and
effect as to all Nucor Wells that have been funded in whole or in part prior to
such election.

 

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Section 9.

Payment Offset

If a Party fails to make any payment to the other when due under this Agreement
(the “defaulting Party”), then in addition to, and not in lieu of, other
available remedies, the non-defaulting Party may offset any other amount arising
under this Agreement owed by the non-defaulting Party against the amount owed
under this Agreement by the defaulting Party. Notwithstanding the foregoing, the
non-defaulting Party may not offset any amount that the defaulting Party has
contested in good faith within thirty (30) days of the date of its receipt of
the disputed billing statement, and as to which the defaulting Party has
provided the non-defaulting Party with written notice of defaulting Party’s
position, including the basis therefor and supporting documentation, if any.

Section 10.

Notices

All notices and communications required or permitted under this Agreement shall
be in writing addressed as indicated below, and any communication or delivery
hereunder shall be deemed to have been duly delivered upon the earliest of:
(a) actual receipt by the Party to be notified; (b) three days after deposit
with the US Postal Service, certified mail, postage prepaid, return receipt
requested; (c) if by facsimile transmission, upon confirmation by the recipient
of receipt, or if by e-mail, upon receipt of a confirming e-mail from the
recipient of the e-mail; or (d) by Federal Express overnight delivery (or other
reputable overnight delivery service), two days after deposited with such
service. Addresses for all such notices and communication shall be as follows:

To Encana:                    Encana Oil & Gas (USA) Inc.

370 17th Street, Suite 1700

Denver, Colorado 80202

Attention: Team Lead Land, South Rockies

Phone: 720.876.3644

Fax: 720.876.4644

Email: helen.capps@encana.com

With a copy of notices to:

Encana Oil & Gas (USA) Inc.

370 17th Street, Suite 1700

Denver, Colorado 80202

Attention: Legal Department

Phone: 303.623.2300

Fax: 720.876.3655

 

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To Nucor:                    Nucor Energy Holdings Inc.

1915 Rexford Road

Charlotte, North Carolina 28211

Attention: Chief Financial Officer

Phone: 704.365.1921

Fax: 704.362.4208

Email: jim.frias@nucor.com

Either Party may, upon written notice to the other Party, change the address and
person to whom such communications are to be directed.

Section 11.

Relationship of the Parties

This Agreement is not intended to create, and shall not be construed to create,
an association for profit, a trust, a joint venture, a mining partnership or
other relationship of partnership, or entity of any kind between the Parties.
Notwithstanding anything to the contrary contained herein, the Parties
understand and agree that the arrangement and undertakings evidenced by this
Agreement, taken together, result in a partnership for purposes of federal
income taxation and for purposes of certain state income tax laws which
incorporate or follow federal income tax principles as to tax partnerships. For
these purposes, the Parties agree to be governed by the tax partnership
provisions attached as Exhibit D, which are incorporated herein and made a part
of this Agreement by this reference. For every purpose other than the
above-described income tax purposes, however, the Parties understand and agree
that the liabilities of the Parties shall be individual, not joint or
collective, and that each Party shall be solely responsible for its own
obligations. In the case of any conflict or inconsistency between the terms and
conditions of this Agreement and the terms and conditions of any attachment or
exhibit hereto (other than Exhibit D), the terms and conditions of this
Agreement shall govern and control. In the event of any conflict or
inconsistency between the terms and conditions of Exhibit D and the terms and
conditions of this Agreement or any other attachment or Exhibit hereto, the
terms and conditions of Exhibit D shall govern and control.

Section 12.

Entire Agreement

This Agreement, and the exhibits and schedules hereto and thereto, contain the
entire agreement of the Parties with respect to the subject matter hereof and
supersede all previous agreements or communications between the Parties, verbal
or written, with respect to the subject matter hereof.

Section 13.

Governing Law

This Agreement shall be governed by and construed and interpreted in accordance
with the laws of the State of Colorado, without reference to its conflicts of
laws provisions.

 

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Section 14.

Amendments; Waiver

No amendments or other modifications or changes to this Agreement shall be
effective or binding on either Party unless the same shall be in a writing
executed by both Parties. No waiver by either Party of any one or more defaults
by the other in the performance of this Agreement shall operate or be construed
as a waiver of any future default or defaults, whether of a like or different
nature.

Section 15.

Public Announcements

Except as required by Applicable Law or the listing agreement or other
requirements of a national securities exchange, neither Party shall issue a
public statement or press release with respect to the transactions contemplated
herein . Nucor and Encana acknowledge and agree that Nucor intends to make
disclosures of the transaction described herein to the Securities and Exchange
Commission as required by Applicable Law contemporaneously with the execution
hereof and thereafter, and will issue a press release with respect to the
transaction described herein. Nucor shall provide Encana with copies of such
disclosures and releases prior to filing same.

Section 16.

Severability

If a court of competent jurisdiction determines that any clause or provision of
this Agreement is void, illegal, unenforceable or unconscionable under any
present or future law (or interpretation thereof), the remainder of this
Agreement shall remain in full force and effect, and the clauses or provisions
that are determined to be void, illegal, unenforceable, or unconscionable shall
be deemed severed from this Agreement as if this Agreement had been executed
with the invalid provisions eliminated; provided, however, that notwithstanding
the foregoing, if the removal of such provisions destroys the legitimate
purposes of this Agreement, then this Agreement shall no longer be of any force
or effect. The Parties shall negotiate in good faith for any required
modifications to this Agreement required as a result of this provision.

Section 17.

Mutuality

The Parties acknowledge and declare that this Agreement is the result of
extensive negotiations between them. Accordingly, if there is any ambiguity in
this Agreement, then there shall be no presumption that this instrument was
prepared solely by either Party.

Section 18.

Dispute Resolution

The Parties agree to resolve all disputes concerning or relating to this
Agreement pursuant to the provisions of this Section 18. The Parties agree to
submit all disputes to binding arbitration in Denver, Colorado. The arbitration
will be conducted according to the procedure that follows. The arbitration
proceedings shall be governed by Colorado law and shall be conducted in
accordance

 

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with the rules for Non-Administered Arbitration of Business Disputes published
by The Center for Public Resources, Inc., with discovery to be conducted in
accordance with the Federal Rules of Civil Procedure, and with any disputes over
the scope of discovery to be determined by the Arbitrators. The arbitration
shall be before a single Arbitrator chosen by the mutual agreement of the
Parties, or if no agreement as to the identity of the Arbitrator can be reached
within ten days, a three person panel of neutral Arbitrators, consisting of one
person chosen by each Party, and the two Arbitrators so selected choosing the
third. The panel so chosen or the single person are referred to herein as the
“Arbitrators.” The Arbitrators shall conduct a hearing no later than sixty
(60) days after submission of the matter to arbitration, and the Arbitrators
shall render a written decision within thirty (30) days of the hearing. At the
hearing, the Parties shall present such evidence and witnesses as they may
choose, with or without counsel. Adherence to formal rules of evidence shall not
be required, but the Arbitrators shall consider any evidence and testimony that
they determine to be relevant, in accordance with procedures that they determine
to be appropriate. Any award entered in the arbitration shall be made by a
written opinion stating the reasons and basis for the award made and any payment
due pursuant to the arbitration shall be made within fifteen (15) days of the
decision by the Arbitrators. The decision of the Arbitrators shall be binding on
the Parties, final and non-appealable, and may be filed in a court of competent
jurisdiction and may be enforced by either Party as a final judgment of such
court. Each Party shall bear its own costs and expenses of the arbitration,
provided, however, that the costs of employing the Arbitrators shall by shared
equally by the Parties.

Section 19.

Waiver of Exemplary and Punitive Damages

NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT AND FOR THE AVOIDANCE
OF DOUBT, EACH PARTY HEREBY EXPRESSLY DISCLAIMS, WAIVES AND RELEASES THE OTHER
PARTY FROM ITS OWN EXEMPLARY AND PUNITIVE DAMAGES. NO LAW, THEORY, OR PUBLIC
POLICY SHALL BE GIVEN EFFECT WHICH WOULD UNDERMINE, DIMINISH, OR REDUCE THE
EFFECTIVENESS OF THE FOREGOING WAIVER, IT BEING THE EXPRESS INTENT,
UNDERSTANDING, AND AGREEMENT OF THE PARTIES THAT SUCH DAMAGE WAIVER IS TO BE
GIVEN THE FULLEST EFFECT, NOTWITHSTANDING THE NEGLIGENCE (WHETHER SOLE, JOINT OR
CONCURRENT), GROSS NEGLIGENCE, WILLFUL MISCONDUCT, STRICT LIABILITY OR OTHER
LEGAL FAULT OF EITHER PARTY.

Section 20.

Indemnification

 

20.1 Indemnification of Nucor by Encana.

Encana shall RELEASE, DEFEND, PROTECT, INDEMNIFY, and HOLD HARMLESS Nucor, its
Affiliates, and all of their stockholders, officers, employees, directors, and
agents from and against any Damages including, without limitation, any Damages
on account of illness, injury, or death suffered by any Person, or the loss or
damage to the property of any Person, arising out of, in connection with, or
relating to (i) any grossly negligent or willful conduct of Encana, its
Affiliates, or any of their officers, employees, directors, or agents with
respect to the performance of Encana’s obligations under this Agreement,
(ii) Encana’s breach of any

 

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representation or warranty contained in this Agreement, (iii) Encana’s breach of
any covenant or agreement contained in this Agreement, (iv) all wells operated
by Encana on the Property that are not Nucor Wells, and (v) the plugging and
abandonment liability for all wells on the Property that are not Nucor Wells.

 

20.2 Environmental Indemnification of Nucor by Encana.

Encana shall RELEASE, DEFEND, PROTECT, INDEMNIFY, and HOLD HARMLESS Nucor, its
Affiliates, and all of their stockholders, officers, employees, directors, and
agents from and against any Environmental Damages arising out of, in connection
with, or relating to any Environmental Condition in, on, under or with respect
to any Well Location (or the relevant Oil and Gas Interests comprising such Well
Location) in existence prior to the commencement of drilling operations for a
Nucor Well on such Well Location.

20.3 Indemnification of Encana by Nucor.

Nucor shall RELEASE, DEFEND, PROTECT, INDEMNIFY, and HOLD HARMLESS Encana, its
Affiliates, and all of their stockholders, officers, employees, directors, and
agents from and against any Damages including, without limitation, any Damages
on account of illness, injury, or death suffered by any Person, or the loss or
damage to the property of any Person, arising out of, in connection with, or
relating to (i) any grossly negligent or willful conduct of Nucor, its
Affiliates, or any of their officers, employees, directors, or agents with
respect to the performance of Nucor’s obligations under this Agreement,
(ii) Nucor’s breach of any representation or warranty contained in this
Agreement, and (iii) Nucor’s breach of any covenant or agreement contained in
this Agreement.

Section 21.

Insurance Matters

All policies of insurance carried for the joint account as set forth in Exhibit
D of the New Operating Agreement shall include the following: (i) except for
Worker’s Compensation policies, all such policies shall include Nucor as an
additional insured; (ii) all such policies shall provide that such insurance is
primary and not excess or contributory to any other policy of insurance carried
by Nucor for its own account; and (iii) all such policies shall provide that, to
the maximum extent permissible by Applicable Law, the insurers shall waive all
rights of subrogation against Nucor, and all of its stockholders, officers,
employees, directors, and agents. The costs of all policies of insurance carried
for the joint account will be borne in proportion to the Parties’ interests in
the Nucor Wells.

Section 22.

AMI Area and AMI Interests

22.1 General.

The Parties hereby designate the AMI Area as an area of mutual interest to
acquire AMI Interests. The AMI Area shall be in force and effect for a period of
fifteen (15) years from the Effective Date hereof (the “AMI Term”), unless
earlier terminated by a written agreement signed by each of the Parties hereto.

 

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22.2 AMI Interest Acquisition.

During the AMI Term, if either Party, or any Affiliate of a Party, acquires any
AMI Interest (the “Acquiring Party”), then such Acquiring Party shall within
five (5) Business Days provide the other Party with written notice of such
acquisition. The notice shall include (A) a statement of the purchase price for
the AMI Interest (the “AMI Purchase Price”) and all of the Acquiring Party’s
actual Third Party out-of-pocket costs incurred to acquire the AMI Interest (the
“Acquisition Costs”), together with reasonable support for the statement,
(B) the portion of (i) the AMI Purchase Price and (ii) the Acquisition Costs to
be paid by the other Party if such other Party elects to acquire the portion of
the AMI Interest described below, and (C) a copy of all instruments of
acquisition including, by way of example but not of limitation, copies of the
oil and gas leases, assignments, subleases, farmouts, or other contracts
creating or affecting the AMI Interest. If the AMI Purchase Price is not paid in
cash, then the AMI Purchase Price shall be the value allocated to the AMI
Interest by the Acquiring Party and the Third Party.

 

22.3 Computation of AMI Interest Offered and the Purchase Price.

The portion of an AMI Interest that may be acquired by other Party (the
“Undivided Interest”) and the portion of the AMI Purchase Price and the
Acquisition Costs to be paid for such AMI Interest is set forth below:

A. If the AMI Interest does not include depths below the base of the Formation,
then the other Party may elect to acquire an undivided one-half (1/2), but not
less than one-half (1/2), of the offered AMI Interest, and shall bear fifty
percent (50%) of the AMI Purchase Price and fifty percent (50%) of the
Acquisition Costs.

B. If the AMI Interest does not include any interest in producing wells and
includes formations below the base of the Formation, then

(i) if Nucor is the other Party, then it may elect to acquire an undivided
one-half (1/2), but not less than one-half (1/2), of the AMI Interest from the
surface to the base of the Formation, and shall bear twenty-five percent
(25%) of the AMI Purchase Price and twenty-five percent (25%) of the Acquisition
Costs, or

(ii) if Encana is the other Party, then it may elect to acquire an undivided
one-half (1/2), but not less than one-half (1/2), of the AMI Interest from the
surface to the base of the Formation and all of the AMI Interest below the base
of the Formation, and shall bear seventy-five percent (75%) of the AMI Purchase
Price and seventy-five percent (75%) of the Acquisition Costs.

C. If the AMI Interest includes an interest in producing wells above the base of
the Formation and includes formations below the base of the Formation, then the
Parties shall allocate a portion of the AMI Purchase Price to the producing
formations based upon a net present value analysis or other mutually acceptable
valuation methodology, and

(i) if Nucor is the other Party, then it may elect to acquire an undivided
one-half (1/2), but not less than one-half (1/2), of the AMI Interest from the
surface to the base of the Formation, and shall bear (1) fifty percent (50%) of
the portion of AMI Purchase Price allocated to the producing formation, and
(2) twenty-five percent (25%) of the remaining portion of the AMI Purchase Price
and twenty-five percent (25%) of the Acquisition Costs, or

 

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(ii) if Encana is the other Party, then it may elect to acquire an undivided
one-half (1/2), but not less than one-half (1/2), of the AMI Interest from the
surface to the base of the Formation and all of the AMI Interest below the base
of the Formation, and shall bear (1) fifty percent (50%) of the portion of AMI
Purchase Price allocated to the producing formation, and (2) seventy-five
percent (75%) of the remaining portion of the AMI Purchase Price and
seventy-five percent (75%) of the Acquisition Costs.

D. If the AMI Interest includes an interest in producing wells below the base of
the Formation and includes formations above the base of the Formation, then the
Parties shall allocate a portion of the AMI Purchase Price to the producing
formations based upon a net present value analysis or other mutually acceptable
valuation methodology, and

(i) if Nucor is the other Party, then it may elect to acquire an undivided
one-half (1/2), but not less than one-half (1/2), of the AMI Interest from the
surface to the base of the Formation, and shall bear (1) none (0%) of the
portion of AMI Purchase Price allocated to the producing formation, and
(2) twenty-five percent (25%) of the remaining portion of the AMI Purchase Price
and twenty-five percent (25%) of the Acquisition Costs, or

(ii) if Encana is the other Party, then it may elect to acquire an undivided
one-half (1/2), but not less than one-half (1/2), of the AMI Interest from the
surface to the base of the Formation and all of the AMI Interest below the base
of the Formation, and shall bear (1) one hundred percent (100%) of the portion
of AMI Purchase Price allocated to the producing formation, and (2) seventy-five
percent (75%) of the remaining portion of the AMI Purchase Price and
seventy-five percent (75%) of the Acquisition Costs.

 

22.4 Other Party’s Response Period.

The recipient of the notice of acquisition of an AMI Interest from the Acquiring
Party shall have a period of twenty (20) Business Days after receipt of the
Acquiring Party’s acquisition notice to furnish the Acquiring Party with
(i) written notice of its election to acquire the Undivided Interest, and (ii) a
check in the amount of the recipient’s portion of the AMI Purchase Price and the
Acquisition Costs. The recipient of the notice of acquisition of an AMI Interest
from the Acquiring Party shall not bear any of the Acquiring Party’s or its
Affiliates’ internal overhead, land, legal, acquisition, or other costs incurred
with respect to any AMI Interest.

 

22.5 Participation; Conveyances.

If the recipient of the notice of acquisition of an AMI Interest from the
Acquiring Party fails or refuses to provide the Acquiring Party with written
notice of its election to acquire the Undivided Interest within the twenty
(20) Business Day response period, then such failure or refusal shall constitute
an irrevocable election by such Party not to acquire the Undivided Interest.
Upon timely receipt by the Acquiring Party of the recipient’s notice to acquire
the Undivided Interest and payment by check, the Acquiring Party shall execute
and deliver to the recipient a legally-

 

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sufficient conveyance in recordable form of the Undivided Interest. Any
Conveyance made by the Acquiring Party shall contain a special warranty of title
that the Undivided Interest is free and clear of any burdens or encumbrances
placed thereon by, through, or under the Acquiring Party, but not otherwise.

Section 23.

Parent Guarantee

By its execution of this Agreement, Parent fully guarantees the performance by
Nucor of this Agreement.

Section 24.

No Third Party Beneficiaries

This Agreement is for the sole benefit of the Parties, their respective
successors and permitted assigns, and each Party’s Affiliates, and all of their
stockholders, officers, employees, directors, and agents who are designated as
indemnitees under Section 20, and shall not inure to the benefit of any other
Person whomsoever or whatsoever, it being the intention of the Parties that no
other Third Party shall be deemed a third party beneficiary of this Agreement.

Section 25.

Conflicts

Except as otherwise provided in Section 11, if there is any conflict or
inconsistency between any of the terms and provisions of this Agreement and the
terms and provisions of any of the instruments attached as Exhibits hereto
including, without limitation, Exhibit E—Form of New Operating Agreement, then
the terms and provisions of this Agreement shall prevail and control.

Section 26.

Specific Performance

The Parties recognize that irreparable injury to the Parties will result from
any breach of this Agreement and that money damages will be inadequate to fully
remedy the injury. The Parties, in addition to any other available remedies at
law for any breach hereof, will be entitled to enforcement of the provisions
through specific performance, which may include obtaining one (1) or more
preliminary or permanent orders (i) restraining or enjoining any act which would
constitute a breach or (ii) compelling performance of any obligation which, if
not performed, would constitute a breach.

Section 27.

Further Assurances

The Parties shall execute, acknowledge, and deliver or cause to be executed,
acknowledged and delivered such instruments and take such other action as may be
necessary or advisable to carry out their obligations under this Agreement and
under any document or other instrument delivered pursuant hereto.

 

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Section 28.

Counterpart Execution

This Agreement may be executed by signing an original or a counterpart thereof.
If this Agreement is executed in counterparts, all counterparts taken together
shall have the same effect as if all the Parties had signed the same instrument.

(Signature Page Follows)

 

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Signature page to Carry and Earning Agreement

IN WITNESS WHEREOF, this Agreement is executed and effective as of the Effective
Date first above written.

 

Encana Oil & Gas (USA) Inc.     Nucor Energy Holdings Inc. By:   /s/ Darrin
Henke     By:   /s/ Joseph Stratman   Darrin Henke       Joseph Stratman   Vice
President, South Rockies       President     Nucor Corporation       By:   /s/
Joseph Stratman         Joseph Stratman         Executive Vice President

--------------------------------------------------------------------------------

Exhibit A Property

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31,

2012 but effective November 1, 2012 by and between Encana Oil & Gas (USA) Inc.
and Nucor

Energy Holdings Inc.

[***]

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

--------------------------------------------------------------------------------

Exhibit B

Attached to and made part of the BJU Carry and Earning Agreement executed

October 31, 2012 but effective as of November 1, 2012 by and between Encana
Oil &

Gas (USA) Inc. and Nucor Energy Holdings Inc.

U.S. Bureau of Labor Statistics - Producer Price Index Data

Industries and their products (NAICS Classifications)

Oil and Gas Industry Data—NAICS Series 211xxx and 213xxx

PRODUCER PRICE INDICES

 

         O&G Industry—Drilling O&G Wells Indexes          Series
Id: PCU213111—213111          Industry: Drilling oil and gas wells         
Product: Drilling oil and gas wells          Base Date: 1985-12         
Composite PPI Weighted Average—20%:

 

         O&G Industry—Oilfield Services Index:          Series
Id: PCU213112—213112          Industry: Support Activities for oil and gas
operations          Product: Support Activities for oil and gas operations      
   Base Date: 1985-12          Composite PPI Weighted Average—65%:

 

         Metal & Metal Products—Steel Pipe & Tube Index:          Series
Id: WPU0101706—0101706          Commodity Group—Metal & Metal Products         
Product: Steel Pipe & Tube          Base Date: 198206          Composite PPI
Weighted Average—15%:

--------------------------------------------------------------------------------

EXHIBIT C

Attached to and made a part of the BJU Carry & Earning Agreement executed
October 31,

2012 but effective November 1, 2012 by and between EnCana Oil & Gas (USA) Inc.
and

Nucor Energy Holdings Inc.

Form of Wellbore Assignment and Conveyance

 

THE STATE OF COLORADO    

   §           §        KNOW ALL MEN BY THESE PRESENTS:

                                 Section 29.COUNTY OF
                            §

THAT Encana Oil & Gas (USA) Inc., whose address is 370 17th Street, Suite 1700,
Denver, CO 80202 (hereinafter referred to as “Assignor”) for good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged and
confessed, does hereby GRANT, BARGAIN, SELL, TRANSFER, ASSIGN, AND CONVEY unto
Nucor Energy Holdings Inc., whose address is 1915 Rexford Road, Charlotte, NC
28211 (hereinafter referred to as “Assignee”) an undivided fifty percent
(50.00%) of Assignor’s right, title, interest, and estate in and to the
following, subject to the limitations below (collectively, the “Assigned
Interests”):

 

  a. The wells and their associated wellbores described on Exhibit A (each,
individually, a “Well” and collectively, the “Wells”):

 

  b. The rights in and to the oil and gas leases described on the attached
Exhibit B (“Leases”), insofar and only insofar as said Leases cover the lands
described on Exhibit B, as are necessary to operate, maintain, produce and plug
and abandon the Wells.

 

  c. All personal property and fixtures associated with the Wells, including
without limitation the following: all tubing, casing and other equipment in the
wellbore, wellhead equipment and surface production facilities.

 

  d. All hydrocarbons produced from the Wells.

Assignor and Assignee further agree as follows:

 

  1. This Assignment is made and accepted subject to, and Assignee hereby
assumes, its proportionate share of any and all royalties, overriding royalties,
payments out of production, and other burdens or encumbrances of record as of
November 1, 2012 to the extent the same cover and affect the Assigned Interests,
except as may be otherwise provided in the Carry and Earning Agreement.

 

  2. Assignee accepts the Assigned Interest subject to all of the express and
implied covenants and obligations of the Leases, insofar as they relate to the
Assigned Interests.

 

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  3. This Assignment is made by Assignor and accepted by Assignee without any
warranty whatsoever and without warranty of title, either express or implied,
and without recourse, except that Assignor warrants title as against all parties
claiming an interest in the Assigned Interests by, through or under Assignor.
This Assignment is made with full substitution and subrogation of Assignee in
and to all covenants and warranties heretofore made or given by others.

 

  4. This Assignment is made in accordance with, and is subject to all the
terms, provisions, and conditions of, that certain BJU Carry and Earning
Agreement executed October 31, 2012 but effective November 1 , 2012, between
Assignor and Assignee (“Carry and Earning Agreement”) which is incorporated by
this reference the same as though fully set out herein. However, this assignment
is neither intended as, nor shall it be deemed to accomplish, a merger of the
terms and provisions directly set out herein and the terms and provisions of
said Carry and Earning Agreement. Should there be any conflict between this
Assignment and the Carry and Earning Agreement, the terms and conditions set out
in the Carry and Earning Agreement shall prevail.

 

  5. This Assignment is subject to that certain unrecorded Joint Operating
Agreement executed October 31, 2012 but effective November 1, 2012.

 

  6. The Assigned Interests do not include, and Assignor does not intend to
assign and Assignee does not intend to receive, any interest in the following to
the extent that such items do not directly relate to the operation of, and
production of hydrocarbons from, a Well: all lands, minerals, oil and gas leases
and lands pooled therewith, units, working interests, executory interests,
reversionary interests, net profits interests, net revenue interests, term
interests, royalty and overriding royalty interests, fee interests, surface
interests, and any other interests of a similar nature, all contracts,
agreements, licenses, and servitudes, all easements, leases, surface use, and
right-of-way agreements, all other property and equipment not directly used in
connection with the operation and production of the Wells and any and all rights
not expressly herein conveyed as part of the Assigned Interests.

 

  7. The Assigned Interests do not include, and Assignor does not intend to
assign and Assignee does not intend to receive, any overriding royalty interest
owned by Assignor in existence as of November 1, 2012, except as may be
otherwise provided in the Carry and Earning Agreement.

 

  8. The Assigned Interest is hereby limited from the surface to the deepest
depth drilled in each Well.

TO HAVE AND TO HOLD the Assigned Interests unto Assignee and its successors and
assigns, subject to all the express and implied covenants and obligations of the
Leases and this assignment.

EXECUTED this              day of              2012, but effective as of the
date of first production for each Well as set forth on Exhibit A.

 

ENCANA OIL & GAS (USA) INC.   NUCOR ENERGY HOLDINGS INC.

 

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By:         By:     Ricardo D. Gallegos,      

VP, Bus. Dev. – Negotiations

& Lead Rockies & Intl. Land

     

ACKNOWLEDGEMENTS

 

STATE OF COLORADO §

     §

CITY AND COUNTY OF DENVER §

BEFORE ME, the undersigned authority, on this day personally appeared Ricardo D.
Gallegos, VP, Bus. Dev. – Negotiations & Lead Rockies & Intl. Land for ENCANA
OIL & GAS (USA) INC., known to me to be the person whose name is subscribed to
the foregoing instrument, and acknowledged to me that he executed the same for
the purposes and consideration therein expressed and in the capacity therein
stated.

GIVEN UNDER MY HAND AND OFFICIAL SEAL OF OFFICE on this              day of
             2012.

 

MY COMMISSION EXPIRES:                           Notary Public in and for the
State of Colorado

STATE OF                                   §

     §

COUNTY OF                                   §

BEFORE ME, the undersigned authority, on this day personally appeared,
                                                              for NUCOR ENERGY
HOLDINGS INC. known to me to be the person whose name is subscribed to the
foregoing instrument, and acknowledged to me that he executed the same for the
purposes and consideration therein expressed and in the capacity therein stated.

GIVEN UNDER MY HAND AND OFFICIAL SEAL OF OFFICE on this              day of
             2012.

 

MY COMMISSION EXPIRES:                           Notary Public

Recording Requested and when Recorded

 

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Return to:

Nucor Corporation

1915 Rexford Road

Charlotte, NC 28211

Attn: Brad True

 

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Exhibit D

 

Attached to the BJU Carry and Earning Agreement executed October 31, 2012 but
effective

November 1, 2012 by and between Nucor Energy Holdings Inc. and Encana Oil & Gas
(USA) Inc.

TAX PARTNERSHIP PROVISIONS

OF THE ENCANA-NUCOR 2012 TAX PARTNERSHIP

EIN: [TBD]

Table of Contents

 

1.    

General Provisions

     2      1.1.  

Designation of Documents.

     2      1.2.  

Relationship of the Parties.

     2      1.3.  

Priority of Provisions of this Exhibit.

     2      1.4.  

Survivorship.

     2    2.    

Tax Reporting Partner

     3    3.    

Income Tax Compliance and Capital Accounts

     3      3.1.  

Tax Returns.

     3      3.2.  

Fair Market Value Capital Accounts.

     3      3.3.  

Information Requests.

     3      3.4.  

Best Efforts Without Liability.

     3      3.5.  

Tax Matters Partner

     4    4.    

Tax and FMV Capital Account Elections

     5      4.1.  

General Elections.

     5      4.2.  

Depletion.

     5      4.3.  

Election Out Under Code §761(a).

     5      4.4.  

Consent Requirements For Subsequent Tax or FMV Capital Account Elections.

     6    5.    

Capital Contributions and FMV Capital Accounts

     6      5.1.  

Capital Contributions.

     6      5.2.  

FMV Capital Accounts.

     6    6.    

Partnership Allocations

     7      6.1.  

FMV Capital Account Allocations.

     7      6.2.  

Tax Return and Tax Basis Capital Account Allocations.

     8    7.    

Termination and Liquidating Distribution

     9      7.1.  

Termination of the Tax Partnership.

     9      7.2.  

Balancing of FMV Capital Accounts.

     9      7.3.  

Deemed Sale Gain/Loss Charge Back.

     10      7.4.  

Deficit Make-Up Obligation and Balancing Cash Contributions.

     10   

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  7.5.  

Distribution to Balance Capital Accounts.

     10      7.6.  

FMV Determination.

     10      7.7.  

Final Distribution.

     11    8.    

Transfers, Indemnification, and Correspondence

     11      8.1.  

Transfer of Tax Partnership Interests.

     11      8.2.  

Farmouts, Distributions and Contributions to Other Partnerships.

     11      8.3.  

Correspondence.

     11    9.    

Elections and Changes to above Provisions

     11      9.1.  

Special Tax Elections.

     12   

 

  1. General Provisions

 

  1.1. Designation of Documents.

This exhibit is referred to in, and is part of, the agreements identified above
and, if so provided, a part of any agreement to which the agreements are an
exhibit. Such agreements (including all exhibits thereto, other than this
exhibit) shall be hereinafter referred to as the “Agreement;” and this exhibit
is hereinafter referred to as the “Exhibit” or the “Tax Partnership Provisions”
(the “TPPs”). Except as may be otherwise provided in this Exhibit, terms defined
and used in the Agreement shall have the same meaning when used herein.

 

  1.2. Relationship of the Parties.

The parties to the Agreement shall be hereinafter referred to as “Party” or
“Parties.” The Parties understand and agree that the arrangement and
undertakings evidenced by the Agreement result in a partnership for purposes of
Federal income taxation and certain State income tax laws which incorporate or
follow Federal income tax principles as to tax partnerships. Such partnership
for tax purposes is hereinafter referred to as the “Tax Partnership”. For every
other purpose of the Agreement, the Parties understand and agree that their
legal relationship to each other under applicable State law with respect to all
property subject to the Agreement is one of tenants in common, or undivided
interest owners and not members in or partners of a partnership; that the
liabilities of the Parties shall be several and not joint or collective; and
that each Party shall be responsible solely for its own obligations.

 

  1.3. Priority of Provisions of this Exhibit.

If there is a conflict or inconsistency, whether direct or indirect, actual or
apparent, between the terms and conditions of this Exhibit and the terms and
conditions of the Agreement, or any other exhibit or any part thereof, the terms
and conditions of this Exhibit shall govern and control.

 

  1.4. Survivorship.

1.4.1. Any termination of the Agreement shall not affect the continuing
application of the TPPs for the termination and liquidation of the Tax
Partnership.

 

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1.4.2. Any termination of the Agreement shall not affect the continuing
application of the TPPs for the resolution of all matters regarding Federal and
State income reporting.

1.4.3. These TPPs shall inure to the benefit of, and be binding upon, the
Parties hereto and their successors and assigns.

1.4.4. The effective date of the Agreement shall be the effective date of these
TPPs. The Tax Partnership shall continue in full force and effect from, and
after such date, until termination and liquidation pursuant to Sec. 7.1.

 

  2. Tax Reporting Partner

Encana Oil & Gas (USA) Inc. as the Tax Reporting Partner (“TRP”) is responsible
for compliance with all tax reporting obligations of the Tax Partnership, see
Sec. 3.1, below. In the event of any change in the TRP, the Party serving as TRP
at the beginning of a given taxable year shall continue as TRP with respect to
all matters concerning such year.

 

  3. Income Tax Compliance and Capital Accounts

 

  3.1. Tax Returns.

The TRP shall prepare and file all required Federal and State partnership income
tax returns. Not less than thirty (30) days prior to the return due date
(including extensions), the TRP shall submit to each Party for review a copy of
the return as proposed.

 

  3.2. Fair Market Value Capital Accounts.

The TRP shall establish and maintain for each Party a fair market value (“FMV”)
capital account and a tax basis capital account. Upon request, the TRP shall
submit to each Party along with a copy of any proposed partnership income tax
return an accounting of such Party’s FMV capital account as of the end of the
return period.

 

  3.3. Information Requests.

In addition to any obligation under Sec. 2, each Party agrees to furnish to the
TRP not later than sixty (90) days before the return due date (including
extensions) such information relating to the operations conducted under the
Agreement as may be required for the proper preparation of such returns.
Similarly, each Party agrees to furnish timely to the TRP, as requested, any
information and data necessary for the preparation and/or filing of other
required reports and notifications, and for the computation of the capital
accounts. As provided in Code §6050K(c), a Party transferring its interest must
notify the TRP to allow compliance with Code §6050K(a) (see also Sec. 8.1).

 

  3.4. Best Efforts Without Liability.

 

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The TRP and the other Party shall use their best efforts to comply with
responsibilities outlined in this Section, and with respect to the service as
TRP as outlined Sec. 2, and in doing so shall incur no liability to any other
Party.

 

  3.5. Tax Matters Partner

The provisions of this Section 3.5 shall be applicable only if the Tax
Partnership does not qualify for the “small partnership exception” from
Subchapter C of Chapter 63 of Subtitle A (the “TEFRA rules”) of the Internal
Revenue Code of 1986, as amended (the “Code”) or otherwise elects in Section 9.1
to be subject to the TEFRA Rules.

3.5.1 The TRP shall also be the Tax Matters Partner as defined in Code §6231(a)
(the “TMP”) and references to the TRP shall then include references to the TMP.

3.5.2 The TMP shall not be required to incur any expenses for the preparation
for, or pursuance of, administrative or judicial proceedings, unless the Parties
agree on a method for sharing such expenses.

3.5.3 The Parties shall furnish the TMP, within two weeks from the receipt of
the request, the information the TMP may reasonably request to comply with the
requirements on furnishing information to the Internal Revenue Service.

3.5.4 The TMP shall not agree to any extension of the statute of limitations for
making assessments on behalf of the Tax Partnership without first obtaining the
written consent of all Parties. The TMP shall not bind any other Party to a
settlement agreement in tax audits without obtaining the written concurrence of
any such Party.

3.5.5 Any Party who enters in a settlement agreement with the Secretary of the
Treasury with respect to any “partnership items,” as defined in Code
§6231(a)(3), shall notify the other Parties of the terms within ninety (90) days
from the date of such settlement.

3.5.6 If any Party intends to file a notice of inconsistent treatment under Code
§6222(b), such Party shall, prior to the filing of such notice, notify the TMP
of the (actual or potential) inconsistency of the Party’s intended treatment of
a partnership item with the treatment of that item by the Tax Partnership.
Within one week of receipt the TMP shall remit copies of such notification to
the other Parties. If an inconsistency notice is filed solely because a Party
has not received a Schedule K-1 in time for filing of its income tax return, the
TMP need not be notified.

3.5.7 No Party shall file pursuant to Code §6227 a request for an administrative
adjustment of partnership items (a “RFAA”) without first notifying all other
Parties. If all other Parties agree with the requested adjustment, the TMP shall
file the RFAA on behalf of the Tax Partnership. If unanimous consent is not
obtained within thirty (30) days from such notice, or within the period required
to timely file the RFAA, if shorter, any Party, including the TMP, may file a
RFAA on its own behalf.

 

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3.5.8 Any Party intending to file with respect to any partnership item, or any
other tax matter involving the Tax Partnership, a petition under Code § §6226,
6228, or any other provision, shall notify the other Parties prior to such
filing of the nature of the contemplated proceeding. If the TMP is the Party
intending to file such petition, such notice shall be given within a reasonable
time to allow the other Parties to participate in the choice of the forum for
such petition. If the Parties do not agree on the appropriate forum, then the
forum shall be chosen by majority vote. Each Party shall have a vote in
accordance with its percentage interest in the Tax Partnership for the year
under audit. If a majority cannot agree, the TMP shall choose the forum. If a
Party intends to seek review of any court decision rendered as a result of such
proceeding, the Party shall notify the other Parties prior to seeking such
review.

 

  4. Tax and FMV Capital Account Elections

 

  4.1. General Elections.

For both income tax return and capital account purposes, the Tax Partnership
shall elect:

4.1.1. to deduct when incurred intangible drilling and development costs
(“IDC”);

4.1.2. to use the maximum allowable accelerated tax method and the shortest
permissible tax life for depreciation;

4.1.3. the accrual method of accounting;

4.1.4. to report income on a calendar year basis;

and the Tax Partnership shall also make any elections as specially noted in Sec.
9.1, below.

 

  4.2. Depletion.

Solely for FMV capital account purposes, depletion shall be calculated by using
simulated cost depletion within the meaning of Treas.
Reg.§1.704-1(b)(2)(iv)(k)(2), unless the use of simulated percentage depletion
is elected in Sec. 9.1, below. The simulated cost depletion allowance shall be
determined under the principles of Code §612 and be based on the FMV capital
account basis of each property. Solely for purposes of this calculation,
remaining reserves shall be determined consistently by the TRP.

 

  4.3. Election Out Under Code §761(a).

4.3.1. The Parties agree not to elect to be excluded from the application of
Subchapter K of Chapter 1 of the Code. The TRP shall notify all Parties of an
intended election to be excluded from the application of Subchapter K of Chapter
1 of the Code not later than sixty (60) days prior to the filing date or the due
date (including extensions) for the Federal partnership income tax return,
whichever comes earlier. Even after an effective election-out, the TRP’s rights
and obligations, other than the relief from tax return filing obligations of the
Tax Partnership, shall continue.

 

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4.3.2. After an election-out, to avoid an unintended impairment of the
election-out: The Parties will avoid, without prior coordination, any
operational changes which would terminate the qualification for the election-out
status; all Parties will monitor the continuing qualification of the Tax
Partnership for the election-out status and will notify the other Parties if, in
their opinion, a change in operations will jeopardize the election-out; and, all
Parties will use, unless agreed to by them otherwise, the cumulative gas
balancing method as described in Treas. Reg. §1.761-2(d)(3).

 

  4.4. Consent Requirements For Subsequent Tax or FMV Capital Account Elections.

Future elections, in addition to or in amendment of those in this Exhibit, must
be approved by the affirmative consent of the Parties.

 

  5. Capital Contributions and FMV Capital Accounts

The provisions of this Sec. 5 and any other provisions of the TPPs relating to
the maintenance of the capital accounts are intended to comply with Treas. Reg.
§1.704-1(b) and shall be interpreted and applied in a manner consistent with
such regulations.

 

  5.1. Capital Contributions.

The respective capital contributions of each Party to the Tax Partnership shall
be (a) each Party’s interest in the oil and gas lease(s), including all
associated lease and well equipment, committed to the Tax Partnership, and
(b) all amounts of money paid by each Party in connection with the acquisition,
exploration, development, and operation of the lease(s), and all other costs
characterized as contributions or expenses borne by such Party under the
Agreement. The contribution of the leases and any other properties committed to
the Tax Partnership shall be made by each Party’s agreement to hold legal title
to its interest in such leases or other property as nominee of the Tax
Partnership.

 

  5.2. FMV Capital Accounts.

The FMV capital accounts shall be increased and decreased as follows:

5.2.1. The FMV capital account of a Party shall be increased by:

(i) the amount of money and the FMV (as of the date of contribution) of any
property contributed by such Party to the Tax Partnership (net of liabilities
assumed by the Tax Partnership or to which the contributed property is subject);

(ii) that Party’s share of Tax Partnership items of income or gain, allocated in
accordance with Sec. 6.1; and

 

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(iii) that Party’s share of any Code §705(a)(1)(B) item.

5.2.2. The FMV capital account of a Party shall be decreased by:

(i) the amount of money and the FMV of property distributed to a Party (net of
liabilities assumed by such Party or to which the property is subject);

(ii) that Party’s Sec. 6.1 allocated share of Tax Partnership loss and
deductions, or items thereof; and,

(iii) that Party’s share of any Code §705(a)(2)(B) item.

5.2.3. “FMV” when it applies to property contributed by a Party to the Tax
Partnership shall be assumed, for purposes of 5.2.1, to equal the adjusted tax
basis, as defined in Code §1011, of that property unless the Parties agree
otherwise as indicated in Sec. 9.1.

5.2.4. As provided in Treas. Reg. §1.704-1(b)(2)(iv)(e), upon distribution of
Tax Partnership property to a Party the capital accounts will be adjusted to
reflect the manner in which the unrealized income, gain, loss and deduction
inherent in distributed property (not previously reflected in the FMV capital
accounts) would be allocated among the Parties if there were a taxable
disposition of such property at its FMV as of the time of distribution.
Furthermore, if so agreed to in Sec. 9.1, pursuant to the rules of Treas. Reg. §
1.704-1(b)(2)(iv)(f), the FMV capital accounts shall be revalued at certain
times to reflect value changes of the Tax Partnership property.

 

  6. Partnership Allocations

 

  6.1. FMV Capital Account Allocations.

Each item of income, gain, loss, or deduction shall be allocated to each Party
as follows:

6.1.1. Actual or deemed income from the sale, exchange, distribution or other
disposition of production shall be allocated to the Party entitled to such
production or the proceeds from the sale of such production. The amount received
from the sale of production and the amount of the FMV of production taken in
kind by the Parties are deemed to be identical; accordingly, such items may be
omitted from the adjustments made to the Parties’ FMV capital accounts.

6.1.2. Exploration cost, IDC, operating and maintenance cost shall be allocated
to each Party in accordance with its respective contribution, or obligation to
contribute, to such cost.

6.1.3. Depreciation shall be allocated to each Party in accordance with its
contribution, or obligation to contribute, to the cost of the underlying asset.

 

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6.1.4. Simulated depletion shall be allocated to each Party in accordance with
its FMV capital account adjusted basis in each oil and gas property of the Tax
Partnership.

6.1.5. Loss (or simulated loss) upon the sale, exchange, distribution,
abandonment or other disposition of depreciable or depletable property shall be
allocated to the Parties in the ratio of their respective FMV capital account
adjusted bases in the depreciable or depletable property.

6.1.6. Gain (or simulated gain) upon the sale, exchange, distribution, or other
disposition of depreciable or depletable property shall be allocated to the
Parties so that the FMV capital account balances of the Parties will most
closely reflect their respective percentage or fractional interests in such
property under the Agreement.

6.1.7. Costs or expenses of any other kind shall be allocated to each Party in
accordance with its respective contribution, or obligation to contribute, to
such costs or expense.

6.1.8. Any other income item shall be allocated to the Parties in accordance
with the manner in which such income is realized by each Party.

 

  6.2. Tax Return and Tax Basis Capital Account Allocations.

6.2.1. Unless otherwise expressly provided in this Sec. 6.2, the allocations of
the Tax Partnership’s items of income, gain, loss, or deduction for tax return
and tax basis capital account purposes shall follow the principles of the
allocations under Sec. 6.1. However, the Tax Partnership’s gain or loss on the
taxable disposition of a Tax Partnership property in excess of the gain or loss
under Sec. 6.1, if any, is allocated to the contributing Party to the extent of
such Party’s pre-contribution gain or loss.

6.2.2. The Parties recognize that under Code §613A(c)(7)(D) the depletion
allowance is to be computed separately by each Party. For this purpose, each
Party’s share of the adjusted tax basis in each oil and gas property shall be
equal to its contribution to the adjusted tax basis of such property.

6.2.3. Under Code §613A(c)(7)(D) gain or loss on the disposition of an oil and
gas property is to be computed separately by each Party. Pursuant to Treas. Reg.
§1.704-1(b)(4)(v), the amount realized shall be allocated as follows: (i) an
amount that represents recovery of adjusted simulated depletion basis is
allocated (without being credited to the FMV capital accounts) to the Parties in
the same proportion as the aggregate simulated depletion basis was allocated to
such Parties under Sec. 5.2; and (ii) any remaining realization is allocated in
accordance with Sec. 6.1.6.

6.2.4. Depreciation shall be allocated to each Party in accordance with its
contribution to the adjusted tax basis of the depreciable asset.

 

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6.2.5. In accordance with Treas. Reg. §1.1245-1(e), depreciation recapture shall
be allocated, to the extent possible, among the Parties to reflect their prior
sharing of the depreciation deductions.

6.2.6. In accordance with the principles of Treas. Reg. §1.1254-5, any recapture
of IDC shall be determined and reported by each Party separately. Similarly, any
recapture of depletion shall be computed separately by each Party, in accordance
with its depletion allowance computed pursuant to Sec. 6.2.2.

6.2.7. For Tax Partnership properties with FMV capital account values different
from their adjusted tax bases the Parties intend that the allocations described
in this Section 6.2 constitute a “reasonable method” of allocating gain or loss
under Treas. Reg. §1.704-3(a)(1).

6.2.8. Take-in-kind.

If checked “Yes” in Sec. 9.1, below, each Party has the right to determine the
market for its proportionate share of production. All items of income,
deductions, and credits arising from such marketing of production shall be
recognized by the Tax Partnership and shall be allocated to the Party whose
production is so marketed.

 

  7. Termination and Liquidating Distribution

 

  7.1. Termination of the Tax Partnership.

The Tax Partnership shall terminate upon the first to occur of (a) a deemed
termination of the Tax Partnership pursuant to Section 708(b)(1)(A) of the Code,
(b) the effectiveness of an election by the Parties to be excluded from the
application of Subchapter K of Chapter 1 of the Code (if and when all the
Parties affirmatively agree to make such an election) or (c) the occurrence of
any other event which causes the Tax Partnership to terminate as a matter of
law.

7.1.1. Upon termination, as provided in Code §708(b)(1)(A), the business shall
be wound-up and concluded, and the assets shall be distributed to the Parties as
described below by the end of such calendar year (or, if later, within
ninety (90) days after the date of such termination). The assets shall be valued
and distributed to the Parties in the order provided in Secs. 7.1.2, 7.5, and
7.7

7.1.2. First, all cash representing unexpended contributions by any Party and
any property in which no interest has been earned by any other Party under the
Agreement shall be returned to the contributor.

 

  7.2. Balancing of FMV Capital Accounts.

Second, the FMV capital accounts of the Parties shall be determined as described
hereafter. The TRP shall take the actions specified under Secs. 7.2 through 7.5
in order to cause the Parties’ FMV capital accounts to reflect, to the maximum
extent possible, their interests under the

 

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Agreement. These actions are hereafter referred to as the “balancing of the FMV
capital accounts” and, when each Party’s FMV capital account balance is equal to
the fair market value of its interest under the Agreement, the FMV capital
accounts of the Parties shall be referred to as “balanced.”

 

  7.3. Deemed Sale Gain/Loss Charge Back.

The FMV of all Tax Partnership properties shall be determined and the gain or
loss for each property, which would have resulted if sold at such FMV, shall be
allocated in accordance with Secs. 6.1.5 and 6.1.6. If each Party’s FMV capital
account balance following such allocation does not correspond to the fair market
value of its respective interests under the Agreement, then income, gain, loss,
and deduction for the taxable year in which the liquidation occurs shall be
reallocated among the Parties to cause, to the maximum extent possible, the
ratio of their positive FMV capital account balances to equal the fair market
value of their respective interests under the Agreement.

 

  7.4. Deficit Make-Up Obligation and Balancing Cash Contributions.

If hereafter a Party has a negative FMV capital account balance, that is a
balance of less than zero, in accordance with Treas. Reg.
§1.704-1(b)(2)(ii)(b)(3), such Party is obligated to contribute by the end of
the taxable year or, if later, within 90 days from the Tax Partnership’s
liquidation, an amount of money to the Tax Partnership sufficient to achieve a
zero balance FMV capital account (the “Deficit Make-Up Obligation”). Moreover,
any Party may contribute an amount of cash to the Tax Partnership to facilitate
the balancing of the FMV capital accounts. If after these adjustments the FMV
capital accounts are not balanced, Sec. 7.5 shall apply.

 

  7.5. Distribution to Balance Capital Accounts.

7.5.1. If the FMV capital accounts of the Parties are not balanced after the
application of Sec. 7.3, (i) a Party may contribute cash in the amount required
to cause its FMV capital account to be balanced, and/or (ii) if all Parties
agree, any cash or an undivided interest in certain selected properties shall be
distributed to any Party whose FMV capital account balance exceeds its interest
in the fair market value of the Tax Partnership properties under the Agreement
as necessary to cause, following such distribution, all FMV capital accounts to
be balanced with respect to the remaining Tax Partnership properties.

7.5.2. Unless Sec.7.5.1 applies, an undivided interest in each and every
property shall be distributed to one or more Parties in accordance with their
FMV capital accounts.

 

  7.6. FMV Determination.

If a property is to be valued for purposes of balancing the capital accounts and
making a distribution under this Sec. 7, the Parties shall first attempt to
agree on the FMV of the property; failing such an agreement, the TRP shall cause
a nationally recognized independent engineering firm to prepare an appraisal of
the FMV of such property.

 

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  7.7. Final Distribution.

After the FMV capital accounts of the Parties have been adjusted pursuant to
Secs. 7.2 to 7.5, all remaining property and interests then held by the Tax
Partnership shall be distributed to the Parties in accordance with their
positive FMV capital account balances.

 

  8. Transfers, Indemnification, and Correspondence

 

  8.1. Transfer of Tax Partnership Interests.

Transfers of Tax Partnership interests shall be governed by the Agreement. A
Party transferring its interest, or any part thereof, shall notify the TRP in
writing within two (2) weeks after such transfer.

 

  8.2. Farmouts, Distributions and Contributions to Other Partnerships.

If any Party wishes to sell, farm out or exchange a portion of any property with
a third party or contribute its interest in a property to a partnership or tax
partnership with a third party to the extent allowed under the Agreement, the
other Parties shall not unreasonably withhold consent to distribute the property
from the Tax Partnership to each Party in proportion to its interest in such
property, and shall execute within 30 days such documents as are necessary to
effect the distribution; provided that the Party participating in such sale,
farm out, exchange or contribution shall fully compensate the other Party or
Parties for any accelerated recognition of gain to such Party or Parties
resulting from the distribution, including any gain recognized under Code
§704(c)(1)(B) and Code §737.

 

  8.3. Correspondence.

All correspondence relating to the preparation and filing of the Tax
Partnership’s income tax returns and capital accounts shall be sent to:

(Attach separate list, if necessary)

 

TRP

  “Att to:” reference

Encana Oil & Gas (USA) Inc.

370 17th Street, Suite 1700

Denver, CO 80202

  Tax Department

 

Nucor Energy Holdings Inc.

1915 Rexford Road

Charlotte, NC 28211

  Tax Department

 

  9. Elections and Changes to above Provisions

 

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  9.1. Special Tax Elections.

With respect to Sec. 4.1, the Parties agree (if not agreed, insert “No”):

 

a) that the Tax Partnership shall elect to account for dispositions of
depreciable assets under the general asset method to the extent permitted by
Code §168(i)(4);      No    b) that the Tax Partnership shall elect under Code
§754 to adjust the basis of Tax Partnership property, with the adjustments
provided in Code §734 for a distribution of property and in Code §743 for a
transfer of a partnership interest. In case of distribution of property the TRP
shall adjust all tax basis capital accounts. In the case of a transfer of a
partnership interest the acquiring party(ies) shall establish and maintain its
(their) tax basis capital account(s);      Yes    c) that the Tax Partnership
shall elect under Code §6231 to be subject to the TEFRA rules;      No    d)
that the Tax Partnership shall elect under Code §709 to amortize over the
shortest permissible period all deferred organizational expenses;      Yes    e)
that the Tax Partnership shall elect under Code §195 to amortize over the
shortest permissible period all deferred business start-up expenses;      Yes   

 

f) with respect to Sec. 4.2, Depletion, the Parties agree that the Tax
Partnership shall use simulated percentage depletion instead of simulated cost
depletion;      No    g) with respect to Sec.5.2.4, under the rules of Treas.
Reg. § 1.704-1(b)(2)(iv)(f) the Parties agree that the FMV capital accounts
shall be revalued to reflect value changes of the Tax Partnership property upon
the occurrence of the events specified in (5)(i) through (iii) of said
-1(b)(2)(iv)(f) regulations;      Yes    h) with respect to Sec. 6.2.8, the
income attributable to take-in-kind production will be reflected on the tax
return.      No   

With respect to Sec. 5.2.3, the FMV for the listed properties are determined on
Schedule 5.2.3, which shall describe each property that becomes subject to the
Agreement and the agreed fair market value of such property at the time it
becomes subject to the Agreement.

 

-12-

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EXHIBIT E

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012 by and between Encana Oil
&Gas (USA) Inc. and Nucor Energy Holdings Inc.

A.A.P.L. FORM 610—1989

MODEL FORM OPERATING AGREEMENT

OPERATING AGREEMENT

DATED EFFECTIVE

November 1, 2012

 

OPERATOR        

   Encana Oil & Gas (USA) Inc.

 

CONTRACT AREA        

   All Carry Wells and/or Head’s Up Wells drilled pursuant to the BJU Carry and
Earning Agreement between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings
Inc. executed October 31, 2012 but effective November 1, 2012.

29.1

 

 

COUNTY OR PARISH OF     Garfield and Rio Blanco                 , STATE OF
    Colorado            

 

 

 

   COPYRIGHT 1989 – ALL RIGHTS RESERVED
AMERICAN ASSOCIATION OF PETROLEUM
LANDMEN, 4100 FOSSIL CREEK  BLVD.
FORT WORTH, TEXAS, 76137, APPROVED FORM.

 

A.A.P.L. NO. 610 – 1989

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

TABLE OF CONTENTS

 

Article

 

Title

   Page   I.   DEFINITIONS      1    II.   EXHIBITS      2    III.   INTERESTS
OF PARTIES      3      A.  

OIL AND GAS INTERESTS:

     3      B.  

INTERESTS OF PARTIES IN COSTS AND PRODUCTION:

     3      C.  

SUBSEQUENTLY CREATED INTERESTS:

     3    IV.   TITLES      3      A.  

TITLE EXAMINATION:

     3      B.  

LOSS OR FAILURE OF TITLE:

     4       

1. Failure of Title

     4       

2. Loss by Non-Payment or Erroneous Payment of Amount Due

     5       

3. Other Losses

     5       

4. Curing Title

     5    V.   OPERATOR      5      A.  

DESIGNATION AND RESPONSIBILITIES OF OPERATOR:

     5      B.  

RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR:

     5       

1. Resignation or Removal of Operator

     6       

2. Selection of Successor Operator

     6       

3. Effect of Bankruptcy

     6      C.  

EMPLOYEES AND CONTRACTORS:

     6      D.  

RIGHTS AND DUTIES OF OPERATOR:

     6       

1. Competitive Rates and Use of Affiliates

     6       

2. Discharge of Joint Account Obligations

     7       

3. Protection from Liens

     7       

4. Custody of Funds

     7       

5. Access to Contract Area and Records

     7       

6. Filing and Furnishing Governmental Reports

     7       

7. Drilling and Testing Operations

     7       

8. Cost Estimates

     7       

9. Insurance

     7    VI.   DRILLING AND DEVELOPMENT      8      A.  

INITIAL WELL:

     8      B.  

SUBSEQUENT OPERATIONS:

     8       

1. Proposed Operations

     8       

2. Operations by Less Than All Parties

     8       

3. Stand-By Costs

     11       

4. Deepening

     11       

5. Sidetracking

     12       

6. Order of Preference of Operations

     12       

7. Conformity to Spacing Pattern

     12       

8. Paying Wells

     12      C.  

COMPLETION OF WELLS; REWORKING AND PLUGGING BACK:

     12       

1. Completion

     12       

2. Rework, Recomplete or Plug Back

     13      D.  

OTHER OPERATIONS:

     13      E.  

ABANDONMENT OF WELLS:

     13       

1. Abandonment of Dry Holes

     13       

2. Abandonment of Wells That Have Produced

     14       

3. Abandonment of Non-Consent Operations

     14      F.  

TERMINATION OF OPERATIONS:

     15      G.  

TAKING PRODUCTION IN KIND:

     15       

(Option 1) Gas Balancing Agreement

     15       

(Option 2) No Gas Balancing Agreement

     15    VII.   EXPENDITURES AND LIABILITY OF PARTIES      16      A.  

LIABILITY OF PARTIES:

     16      B.  

LIENS AND SECURITY INTERESTS:

     16      C.  

ADVANCES:

     17      D.  

DEFAULTS AND REMEDIES:

     18       

1. Suspension of Rights

     18       

2. Suit for Damages

     18       

3. Deemed Non-Consent

     18       

4. Advance Payment

     18       

5. Costs and Attorneys’ Fees

     19      E.  

RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES:

     19      F.  

TAXES:

     19    VIII.   ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST      19     
A.  

SURRENDER OF LEASES:

     19      B.  

RENEWAL OR EXTENSION OF LEASES:

     20      C.  

ACREAGE OR CASH CONTRIBUTIONS:

     20   

 

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

TABLE OF CONTENTS

 

  D.  

ASSIGNMENT; MAINTENANCE OF UNIFORM INTEREST:

     20      E.  

WAIVER OF RIGHTS TO PARTITION:

     21      F.  

PREFERENTIAL RIGHT TO PURCHASE

     21    IX.   INTERNAL REVENUE CODE ELECTION      21    X.   CLAIMS AND
LAWSUITS      22    XI.   FORCE MAJEURE      22    XII.   NOTICES      22   
XIII.   TERM OF AGREEMENT      22    XIV.   COMPLIANCE WITH LAWS AND REGULATIONS
     23      A.  

LAWS, REGULATIONS AND ORDERS:

     23      B.  

GOVERNING LAW:

     23      C.  

REGULATORY AGENCIES:

     23    XV.   MISCELLANEOUS      23      A.  

EXECUTION:

     23      B.  

SUCCESSORS AND ASSIGNS:

     24      C.  

COUNTERPARTS:

     24      D.  

SEVERABILITY

     24    XVI.   OTHER PROVISIONS      24   

 

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

OPERATING AGREEMENT

THIS AGREEMENT is entered into by and between Encana Oil & Gas (USA) Inc.
(“Encana”) and Nucor Energy Holdings Inc. (“Nucor”), with Encana being also
referred to as “Operator.” Nucor is the Non-operator herein. Encana and Nucor
may be referred to herein individually as a “party” and together as the
“parties.”

WITNESSETH:

WHEREAS, the parties to this agreement are owners of the Carry Wells and/or
Head’s Up Wells designated and drilled pursuant to the BJU Carry and Earning
Agreement executed October 31, 2012 but effective November 1, 2012 between the
parties and the parties hereto have reached an agreement regarding the
production of Oil and Gas from the Carry Wells and/or Head’s Up Wells as
hereinafter provided.

NOW, THEREFORE, it is agreed as follows:

ARTICLE I.

DEFINITIONS

As used in this agreement, the following words and terms shall have the meanings
here ascribed to them:

A. The term “AFE” shall mean an Authority for Expenditure prepared by a party to
this agreement for the purpose of estimating the costs to be incurred in
conducting an operation hereunder.

B. The term “Completion” or “Complete” shall mean a single operation intended to
complete a well as a producer of Oil and Gas in one or more Zones, including,
but not limited to, the setting of production casing, perforating, well
stimulation and production testing conducted in such operation.

C. The term “Contract Area” shall mean the area described in Exhibit “A”.

D. The term “Deepen” shall mean a single operation whereby a well is drilled to
an objective Zone below the deepest Zone in which the well was previously
drilled, or below the Deepest Zone proposed in the associated AFE, whichever is
the lesser.

E. The terms “Drilling Party” and “Consenting Party” shall mean a party who
agrees to join in and pay its share of the cost of any operation conducted under
the provisions of this agreement.

F. The term “Drilling Unit” shall mean the area fixed for the drilling of one
well by order or rule of any state or federal body having authority. If a
Drilling Unit is not fixed by any such rule or order, a Drilling Unit shall be
the drilling unit as established by the pattern of drilling in the Contract Area
unless fixed by express agreement of the Drilling Parties.

G. The term “Drillsite” shall mean the Oil and Gas Lease or Oil and Gas Interest
on which a Carry Well and/or Head’s Up Well is to be located

H. The term “Initial Well” shall mean the well required to be drilled by the
parties hereto as provided in Article VI.A.

I. The term “Non-Consent Well” shall mean a well in which less than all parties
have conducted an operation as provided in Article VI.B.2.

J. The terms “Non-Drilling Party” and “Non-Consenting Party” shall mean a party
who elects not to participate in a proposed operation.

K. The term “Oil and Gas” shall mean oil, gas, casinghead gas, gas condensate,
and/or all other liquid or gaseous hydrocarbons and other marketable substances
produced therewith, unless an intent to limit the inclusiveness of this term is
specifically stated.

L. The term “Oil and Gas Interests” or “Interests” shall mean unleased fee and
mineral interests in Oil and Gas in tracts of land lying within the Contract
Area which are owned by parties to this agreement.

M. The terms “Oil and Gas Lease,” “Lease” and “Leasehold” shall mean the oil and
gas leases or interests therein covering tracts of land lying within the
Contract Area which are owned by the parties to this agreement.

N. The term “Plug Back” shall mean a single operation whereby a deeper Zone is
abandoned in order to attempt a Completion in a shallower Zone.

O. The term “Recompletion” or “Recomplete” shall mean an operation whereby a
Completion in one Zone is abandoned in order to attempt a Completion in a
different Zone within the existing wellbore.

P. The term “Rework” shall mean an operation conducted in the wellbore of a well
after it is Completed to secure, restore, or improve production in a Zone which
is currently open to production in the wellbore. Such operations include, but
are not limited to, well stimulation operations but exclude any routine repair
or maintenance work or drilling, Sidetracking, Deepening, Completing,
Recompleting, or Plugging Back of a well.

Q. The term “Sidetrack” shall mean the directional control and intentional
deviation of a well from vertical so as to change the bottom hole location
unless done to straighten the hole or drill around junk in the hole to overcome
other mechanical difficulties.

R. The term “Zone” shall mean a stratum of earth containing or thought to
contain a common accumulation of Oil and Gas separately producible from any
other common accumulation of Oil and Gas.

S. “BJU Carry and Earning Agreement” shall mean that certain BJU Carry and
Earning Agreement made by and between Encana and Nucor, executed October 31,
2012 but effective November 1, 2012.

T. “Carry Wells” and/or “Head’s Up Wells” shall have the same meaning as
provided in the BJU Carry and Earning Agreement.

Unless the context otherwise clearly indicates, words used in the singular
include the plural, the word “person” includes natural and artificial persons,
the plural includes the singular, and any gender includes the masculine,
feminine, and neuter. Capitalized terms that are not otherwise defined herein
shall have the same meaning as in the BJU Carry and Earning Agreement.

 

1

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

ARTICLE II.

EXHIBITS

The following exhibits, as indicated below and attached hereto, are incorporated
in and made a part hereof:

 

    X      A. Exhibit “A” shall include the following information:

     (1) Description of Carry Wells and/or Head’s Up Wells subject to this
agreement,

     (2) Restrictions, if any, as to depths, formations, previously existing
wells, or substances,

     (3) Percentages or fractional interests of parties to this agreement

     (4) Leases, lands and agreements subject to this agreement, ,

     (5) Parties to agreement with addresses and telephone numbers for notice
purposes,

     (6) Burdens on production.

            B. Exhibit “B,” Form of Lease.

    X      C. Exhibit “C,” Accounting Procedure.

    X      D. Exhibit “D,” Insurance.

    X      E. Exhibit “E,” Gas Balancing Agreement.

    X      F. Exhibit “F,” Non-Discrimination and Certification of
Non-Segregated Facilities.

    X      G. Exhibit “G,” Tax Partnership.

    X      H. Exhibit “H” Nucor Well Information Requirements.

    X      I. Exhibit “I” Recording Supplement.

 

 

2

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

ARTICLE III.

INTERESTS OF PARTIES

A. Oil and Gas Interests:

If Encana owns an Oil and Gas Interest in the Contract Area that is not subject
to an Oil and Gas Lease, that Interest shall be subject to a royalty payable to
Encana of 16.67%.

B. Interests of Parties in Costs and Production:

Unless changed by other provisions, all costs and liabilities incurred in
operations under this agreement shall be borne and paid, and all equipment and
materials acquired in operations on the Contract Area shall be owned, by the
parties as their interests are set forth in Exhibit “A.” In the same manner, the
parties shall also own all production of Oil and Gas from the Contract Area
subject, however, to the payment of royalties and other burdens on production as
described hereafter.

Regardless of which party has contributed any Oil and Gas Lease or Oil and Gas
Interest on which royalty or other burdens may be payable and except as
otherwise expressly provided in this agreement, each party shall pay or deliver,
or cause to be paid or delivered, all burdens on its share of the production up
to, but not in excess of, of those burdens SEE ARTICLE XVI.D. and shall
indemnify, defend and hold the other parties free from any liability therefore.
Except as otherwise expressly provided in this agreement, if any party has
contributed hereto any Lease or Interest which is burdened with any royalty,
overriding royalty, production payment or other burden on production in excess
of the amounts stipulated above, such party so burdened shall assume and alone
bear all such excess obligations and shall indemnify, defend and hold the other
parties hereto harmless from any and all claims attributable to such excess
burden. However, so long as the Drilling Unit for the productive Zone(s) is
identical with the Contract Area, each party shall pay or deliver, or cause to
be paid or delivered, all burdens on production from the Contract Area due under
the terms of the Oil and Gas Lease(s) which such party has contributed to this
agreement, and shall indemnify, defend and hold the other parties free from any
liability therefore.

No party shall ever be responsible, on a price basis higher than the price
received by such party, to any other party’s lessor or royalty owner, and if
such other party’s lessor or royalty owner should demand and receive settlement
on a higher price basis, the party contributing the affected Lease shall bear
the additional royalty burden attributable to such higher price.

Nothing contained in this Article III.B. shall be deemed an assignment or
cross-assignment of interests covered hereby, and in the event two or more
parties contribute to this agreement jointly owned Leases, the parties’
undivided interests in said Leaseholds shall be deemed separate leasehold
interests for the purposes of this agreement.

C. Subsequently Created Interests:

If any party has contributed hereto a Lease or Interest that is burdened with an
assignment of production given as security for the payment of money, or if,
after the effective date of the BJU Carry and Earning Agreement, any party
creates an overriding royalty, production payment, net profits interest,
assignment of production or other burden payable out of production attributable
to its working interest hereunder, such burden shall be deemed a “Subsequently
Created Interest.” Further, regardless of the date such burden was created, any
overriding royalty, production payment, net profits interest, or other burden
payable out of production and owned by Operator or its Affiliates shall be
treated as a Subsequently Created Interest unless such burden is disclosed on
Schedule 5.2 to the BJU Carry and Earning Agreement. to the extent such burdens
causes the burdens on such party’s Lease or Interest to exceed the amount
stipulated in Article III.B. above.

The party whose interest is burdened with the Subsequently Created Interest (the
“Burdened Party”) shall assume and alone bear, pay and discharge the
Subsequently Created Interest and shall indemnify, defend and hold harmless the
other parties from and against any liability therefore. Further, if the Burdened
Party fails to pay, when due, its share of expenses chargeable hereunder, all
provisions of Article VII.B. shall be enforceable against the Subsequently
Created Interest in the same manner as they are enforceable against the working
interest of the Burdened Party. If the Burdened Party is required under this
agreement to assign or relinquish to any other party, or parties, all or a
portion of its working interest and/or the production attributable thereto, said
other party, or parties, shall receive said assignment and/or production free
and clear of said Subsequently Created Interest, and the Burdened Party shall
indemnify, defend and hold harmless said other party, or parties, from any and
all claims and demands for payment asserted by owners of the Subsequently
Created Interest.

ARTICLE IV.

TITLES

A. Title Examination:

 

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

Title examination shall be made on the Drillsite of any proposed well prior to
commencement of drilling operations and, if a majority in interest of the
Drilling Parties so request or Operator so elects, title examination shall be
made on the entire Drilling Unit, or maximum anticipated Drilling Unit, of the
well. The opinion will include the ownership of the working interest, minerals,
royalty, overriding royalty and production payments under the applicable Leases.
Each party contributing Leases and/or Oil and Gas Interests to be included in
the Drillsite or Drilling Unit, if appropriate, shall furnish to Operator all
abstracts (including federal lease status reports), title opinions, title papers
and curative material in its possession free of charge. All such information not
in the possession of or made available to Operator by the parties, but necessary
for the examination of the title, shall be obtained by Operator. Operator shall
cause title to be examined by attorneys on its staff or by outside attorneys.
Copies of all title opinions shall be furnished to each Drilling Party. Costs
incurred by Operator in procuring abstracts, fees paid outside attorneys for
title examination (including preliminary, supplemental, shut-in royalty opinions
and division order title opinions) and other direct charges as provided in
Exhibit “C” shall be borne by the Drilling Parties in the proportion that the
interest of each Drilling Party bears to the total interest of all Drilling
Parties as such interests appear in Exhibit “A.” Operator shall make no charge
for services rendered by its staff attorneys or other personnel in the
performance of the above functions.

Operator shall be responsible for using its reasonable efforts to secure
curative matter and pooling amendments or agreements required in connection with
Leases or Oil and Gas Interests contributed by such party. Operator shall be
responsible for the preparation and recording of pooling designations or
declarations and communitization agreements as well as the conduct of hearings
before governmental agencies for the securing of spacing or pooling orders or
any other orders necessary or appropriate to the conduct of operations
hereunder. This shall not prevent any party from appearing on its own behalf at
such hearings. Costs incurred by Operator, including fees paid to outside
attorneys, which are associated with hearings before governmental agencies, and
which costs are necessary and proper for the activities contemplated under this
agreement, shall be direct charges to the joint account and shall not be covered
by the administrative overhead charges as provided in Exhibit “C.”

Operator shall make no charge for services rendered by its staff attorneys or
other personnel in the performance of the above functions.

No well shall be drilled on the Contract Area until after (1) the title to the
Drillsite or Drilling Block, if appropriate, has been examined as above
provided, and (2) the title has been approved by the Operator, examining
attorney or title has been accepted by all of the Drilling Parties in such well.

B. Loss or Failure of Title:

1. Failure of Title: Should any Oil and Gas Interest or Oil and Gas Lease be
lost through failure of title, which results in a reduction of interest from
that shown on Exhibit “A” the party credited with contributing the affected
Lease or Interest (including, if applicable, a successor in interest to such
party) shall have ninety (90) days from final determination of title failure to
acquire a new lease or other instrument curing the entirety of the title
failure, which acquisition will not be subject to Article VIII.B., and failing
to do so, this agreement, nevertheless, shall continue in force as to all
remaining Oil and Gas Leases and Interests; and,

(a) The party credited with contributing the Oil and Gas Lease or Interest
affected by the title failure (including, if applicable, a successor in interest
to such party) shall bear alone the entire loss and it shall not be entitled to
recover from Operator or the other parties any development or operating costs
which it may have previously paid or incurred, but there shall be no additional
liability on its part to the other parties hereto by reason of such title
failure;

(b) There shall be no retroactive adjustment of expenses incurred or revenues
received from the operation of the Lease or Interest which has failed, but the
interests of the parties contained on Exhibit “A” shall be revised on an acreage
basis, as of the time it is determined finally that title failure has occurred,
so that the interest of the party whose Lease or Interest is affected by the
title failure will thereafter be reduced in the Contract Area by the amount of
the Lease or Interest failed;

(c) If the proportionate interest of the other parties hereto in any producing
well previously drilled on the Contract Area is increased by reason of the title
failure, the party who bore the costs incurred in connection with such well
attributable to the Lease or Interest which has failed shall receive the
proceeds attributable to the increase in such interest (less costs and burdens
attributable thereto) until it has been reimbursed for unrecovered costs paid by
it in connection with such well attributable to such failed Lease or Interest;

(d) Should any person not a party to this agreement, who is determined to be the
owner of any Lease or Interest which has failed, pay in any manner any part of
the cost of operation, development, or equipment, such amount shall be paid to
the party or parties who bore the costs which are so refunded;

(e) Any liability to account to a person not a party to this agreement for prior
production of Oil and Gas which arises by reason of title failure shall be borne
severally by each party (including a predecessor to a current party) who
received production for which such accounting is required based on the amount of
such production received, and each such party shall severally indemnify, defend
and hold harmless all other parties hereto for any such liability to account;

(f) No charge shall be made to the joint account for legal expenses, fees or
salaries in connection with the defense of the Lease or Interest claimed to have
failed, but if the party contributing such Lease or Interest hereto elects to
defend its title it shall bear all expenses in connection therewith; and

 

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

(g) If any party is given credit on Exhibit “A” to a Lease or Interest which is
limited solely to ownership of an interest in the wellbore of any well or wells
and the production therefrom, such party’s absence of interest in the remainder
of the Contract Area shall be considered a Failure of Title as to such remaining
Contract Area unless that absence of interest is reflected on Exhibit “A”.

2. Loss by Non-Payment or Erroneous Payment of Amount Due: If, through mistake
or oversight, any rental, shut-in well payment, minimum royalty or royalty
payment, or other payment necessary to maintain all or a portion of an Oil and
Gas Lease or interest is not paid or is erroneously paid, and as a result a
Lease or Interest terminates, there shall be no monetary liability against the
party who failed to make such payment. Unless the party who failed to make the
required payment secures a new Lease or Interest covering the same interest
within ninety (90) days from the discovery of the failure to make proper
payment, which acquisition will not be subject to Article VIII.B., the interests
of the parties reflected on Exhibit “A” shall be revised on an acreage basis,
effective as of the date of termination of the Lease or Interest involved, and
the party who failed to make proper payment will no longer be credited with an
interest in the Contract Area on account of ownership of the Lease or Interest
which has terminated. If the party who failed to make the required payment shall
not have been fully reimbursed, at the time of the loss, from the proceeds of
the sale of Oil and Gas attributable to the lost Lease or Interest, calculated
on an acreage basis, for the development and operating costs previously paid on
account of such Lease or Interest, it shall be reimbursed for unrecovered actual
costs previously paid by it (but not for its share of the cost of any dry hole
previously drilled or wells previously abandoned) from so much of the following
as is necessary to effect reimbursement:

(a) Proceeds of Oil and Gas produced prior to termination of the Lease or
Interest, less operating expenses and lease burdens chargeable hereunder to the
person who failed to make payment, previously accrued to the credit of the lost
Lease or Interest, on an acreage basis, up to the amount of unrecovered costs;

(b) Proceeds of Oil and Gas, less operating expenses and lease burdens
chargeable hereunder to the person who failed to make payment, up to the amount
of unrecovered costs attributable to that portion of Oil and Gas thereafter
produced and marketed (excluding production from any wells thereafter drilled)
which, in the absence of such Lease or Interest termination, would be
attributable to the lost Lease or Interest on an acreage basis and which as a
result of such Lease or Interest termination is credited to other parties, the
proceeds of said portion of the Oil and Gas to be contributed by the other
parties in proportion to their respective interests reflected on Exhibit “A”;
and,

(c) Any monies, up to the amount of unrecovered costs, that may be paid by any
party who is, or becomes, the owner \of the Lease or Interest lost, for the
privilege of participating in the Contract Area or becoming a party to this
agreement.

3. Other Losses: All losses of Leases or Interests committed to this agreement,
other than those set forth in Articles IV.B.1.and IV.B.2. above, shall be joint
losses and shall be borne by all parties in proportion to their interests shown
on Exhibit “A.” This shall include but not be limited to the loss of any Lease
or Interest through failure to develop or because express or implied covenants
have not been performed (other than performance which requires only the payment
of money), and the loss of any Lease by expiration at the end of its primary
term if it is not renewed or extended. There shall be no readjustment of
interests in the remaining portion of the Contract Area on account of any joint
loss.

4. Curing Title: In the event of a Failure of Title under Article IV.B.1. or a
loss of title under Article IV.B.2. above, any Lease or Interest acquired by any
party hereto (other than the party whose interest has failed or was lost) during
the ninety (90) day period provided by Article IV.B.1. and Article IV.B.2. above
covering all or a portion of the interest that has failed or was lost shall be
offered at cost to the party whose interest has failed or was lost, and the
provisions of Article VIII.B. shall not apply to such acquisition.

ARTICLE V.

OPERATOR

A. Designation and Responsibilities of Operator:

Encana shall be the Operator of the Contract Area and shall conduct and direct
and have full control of all operations in the Contract Area as permitted and
required by, and within the limits this agreement. In its performance of
services hereunder for the Non-Operators, Operator shall be an independent
contractor not subject to the control or direction of the Non-Operators except
as to the type of operation to be undertaken in accordance with the election
procedures contained in this agreement. Operator shall not be deemed, or hold
itself out as, the agent of the Non- Operators with authority to bind them to
any obligation or liability assumed or incurred by Operator as to any third
party. Operator shall conduct its activities under this agreement as a
reasonable prudent operator, in a good and workmanlike manner, with due
diligence and dispatch, in accordance with good oilfield practice, and in
compliance with applicable law and regulation, but in no event shall it have any
liability as Operator to the other parties for losses sustained or liabilities
incurred except such as may result from gross negligence or willful misconduct.

B. Resignation or Removal of Operator and Selection of Successor:

 

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

1. Resignation or Removal of Operator: Operator may resign at any time by giving
written notice thereof to Non-Operators. If Operator terminates its legal
existence, no longer owns an interest hereunder in the Contract Area, or is no
longer capable of serving as Operator, Operator shall be deemed to have resigned
without any action by Non-Operators, except the selection of a successor.
Operator may be removed only for good cause by the affirmative vote of
Non-Operators owning a majority interest based on ownership as shown on Exhibit
“A”, as appropriate in context, remaining after excluding the voting interest of
Operator; such vote shall not be deemed effective until a written notice has
been delivered to the Operator by a Non-Operator detailing the alleged default
and Operator has failed to cure the default within thirty (30) days from its
receipt of the notice or, if the default concerns an operation then being
conducted, within forty-eight (48) hours of its receipt of the notice. For
purposes hereof, “good cause” shall mean not only gross negligence or willful
misconduct but also the material breach of or inability to meet the standards of
operation contained in Article V.A. or material failure or inability to perform
its obligations under this agreement.

Subject to Article VII.D.1., such resignation or removal shall not become
effective until 7:00 o’clock A.M. on the first day of the calendar month
following the expiration of ninety (90) days after the giving of notice of
resignation by Operator or action by the Non-Operators to remove Operator,
unless a successor Operator has been selected and assumes the duties of Operator
at an earlier date. Operator, after effective date of resignation or removal,
shall be bound by the terms hereof as a Non-Operator. A change of a corporate
name or structure of Operator or transfer of Operator’s interest to any single
subsidiary, parent or successor corporation shall not be the basis for removal
of Operator.

2. Selection of Successor Operator: Upon the resignation or removal of Operator
under any provision of this agreement, a successor Operator shall be selected by
the parties. The successor Operator shall be selected from the parties owning an
interest in the Contract Area at the time such successor Operator is selected.
The successor Operator shall be selected by the affirmative vote of two (2) or
more parties owning a majority interest based on ownership as shown on Exhibit
“A” , as appropriate in context; provided, however, if an Operator which has
been removed or is deemed to have resigned fails to vote, or votes only to
succeed itself, the successor Operator shall be selected by the affirmative vote
of the party or parties owning a majority interest based on ownership as shown
on Exhibit “A” , as appropriate in context, remaining after excluding the voting
interest of the Operator that was removed or resigned. The former Operator shall
promptly deliver to the successor Operator all records and data relating to the
operations conducted by the former Operator to the extent such records and data
are not already in the possession of the successor operator. Any cost of
obtaining or copying the former Operator’s records and data shall be charged to
the joint account.

3. Effect of Bankruptcy: If Operator becomes insolvent, bankrupt or is placed in
receivership, it shall be deemed to have resigned without any action by
Non-Operators, except the selection of a successor. If a petition for relief
under the federal bankruptcy laws is filed by or against Operator, and the
removal of Operator is prevented by the federal bankruptcy court, all
Non-Operators and Operator shall comprise an interim operating committee to
serve until Operator has elected to reject or assume this agreement pursuant to
the Bankruptcy Code, and an election to reject this agreement by Operator as a
debtor in possession, or by a trustee in bankruptcy, shall be deemed a
resignation as Operator without any action by Non-Operators, except the
selection of a successor. During the period of time the operating committee
controls operations, all actions shall require the approval of two (2) or more
parties owning a majority interest based on ownership as shown on Exhibit “A.”

In the event there are only two (2) parties to this agreement, during the period
of time the operating committee controls operations, a third party acceptable to
Operator, Non-Operator and the federal bankruptcy court shall be selected as a
member of the operating committee, and all actions shall require the approval of
two (2) members of the operating committee without regard for their interest in
the Contract Area based on Exhibit “A” , as appropriate in context.

C. Employees and Contractors:

The number of employees or contractors used by Operator in conducting operations
hereunder, their selection, and the hours of labor and the compensation for
services performed shall be determined by Operator, and all such employees or
contractors shall be the employees or contractors of Operator.

D. Rights and Duties of Operator:

1. Competitive Rates and Use of Affiliates: All wells drilled on the Contract
Area shall be drilled on a competitive contract basis at the usual rates
prevailing in the area. If it so desires, Operator may employ its own tools and
equipment in the drilling of wells, but its charges therefor shall not exceed
the prevailing rates in the area and the rate of such charges shall be agreed
upon by the parties in writing before drilling operations are commenced, and
such work shall be performed by Operator under the same terms and conditions as
are customary and usual in the area in contracts of independent contractors who
are doing work of a similar nature. All work performed or materials supplied by
affiliates or related parties of Operator shall be performed or supplied at
competitive rates, pursuant to written agreement, and in accordance with customs
and standards prevailing in the industry.

 

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2. Discharge of Joint Account Obligations: Except as herein otherwise
specifically provided, Operator shall promptly pay and discharge expenses
incurred in the development and operation of the Contract Area pursuant to this
agreement and shall charge each of the parties hereto with their respective
proportionate shares upon the expense basis provided in Exhibit “C.” Operator
shall keep an accurate record of the joint account hereunder, showing expenses
incurred and charges and credits made and received.

3. Protection from Liens: Operator shall pay, or cause to be paid, as and when
they become due and payable, all accounts of contractors and suppliers and wages
and salaries for services rendered or performed, and for materials supplied on,
to or in respect of the Contract Area or any operations for the joint account
thereof, and shall keep the Contract Area free from liens and encumbrances
resulting therefrom except for those resulting from a bona fide dispute as to
services rendered or materials supplied.

4. Custody of Funds: Operator shall hold for the account of the Non-Operators
any funds of the Non-Operators advanced or paid to the Operator, either for the
conduct of operations hereunder or as a result of the sale of production from
the Contract Area, and such funds shall remain the funds of the Non-Operators on
whose account they are advanced or paid until used for their intended purpose or
otherwise delivered to the Non-Operators or applied toward the payment of debts
as provided in Article VII.B. Nothing in this paragraph shall be construed to
establish a fiduciary relationship between Operator and Non-Operators for any
purpose other than to account for Non-Operator funds as herein specifically
provided. Nothing in this paragraph shall require the maintenance by Operator of
separate accounts for the funds of Non-Operators unless the parties otherwise
specifically agree.

5. Access to Contract Area and Records: Operator shall, except as otherwise
provided herein, permit each Non-Operator or its duly authorized representative,
at the Non-Operator’s sole risk and cost, full and free access at all reasonable
times to all operations of every kind and character being conducted for the
joint account on the Contract Area and to the records of operations conducted
thereon or production therefrom, including Operator’s books and records relating
thereto. Such access rights shall not be exercised in a manner interfering with
Operator’s conduct of an operation hereunder and shall not obligate Operator to
furnish any geologic or geophysical data of an interpretive nature unless the
cost of preparation of such interpretive data was charged to the joint account.
Operator will furnish to each Non-Operator upon request copies of any and all
reports and information obtained by Operator in connection with production and
related items, including, without limitation, meter and chart reports,
production purchaser statements, run tickets and monthly gauge reports, but
excluding purchase contracts and pricing information to the extent not
applicable to the production of the Non-Operator seeking the information. Any
audit of Operator’s records relating to amounts expended and the appropriateness
of such expenditures shall be conducted in accordance with the audit protocol
specified in Exhibit “C.”

6. Filing and Furnishing Governmental Reports: Operator will file, and upon
written request promptly furnish copies to each requesting Non-Operator not in
default of its payment obligations, all operational notices, reports or
applications required to be filed by local, State, Federal or Indian agencies or
authorities having jurisdiction over operations hereunder. Each Non-Operator
shall provide to Operator on a timely basis all information necessary to
Operator to make such filings.

7. Drilling and Testing Operations: The following provisions shall apply to each
well drilled / completed, reworked, recompleted, sidetracked or plugged back
hereunder, including but not limited to the Initial Well:

(a) Operator will promptly advise Non-Operators of the date on which the well is
spudded, or the date on which drilling operations are commenced.

(b) Operator will send to Non-Operators such reports, test results and notices
regarding the progress of operations on the well as the Non-Operators shall
reasonably request, including, but not limited to, daily drilling reports,
completion reports, and well logs.

(c) Operator shall adequately test all Zones encountered which may reasonably be
expected to be capable of producing Oil and Gas in paying quantities as a result
of examination of the electric log or any other logs or cores or tests conducted
hereunder.

8. Cost Estimates: Upon request of any Consenting Party, Operator shall furnish
estimates of current and cumulative costs incurred for the joint account at
reasonable intervals during the conduct of any operation pursuant to this
agreement. Operator shall not be held liable for errors in such estimates so
long as the estimates are made in good faith.

9. Insurance: At all times while operations are conducted hereunder, Operator
shall comply with the workers compensation law of the state where the operations
are being conducted; provided, however, that Operator may be a self- insurer for
liability under said compensation laws in which event the only charge that shall
be made to the joint account shall be as provided in Exhibit “C.” Operator shall
also carry or provide insurance for the benefit of the joint account of the
parties as outlined in Exhibit “D” attached hereto and made a part hereof.
Operator shall require all contractors engaged in work on or for the Contract
Area to comply with the workers compensation law of the state where the
operations are being conducted and to maintain such other insurance as Operator
may require.

In the event automobile liability insurance is specified in said Exhibit “D,” or
subsequently receives the approval of the parties, no direct charge shall be
made by Operator for premiums paid for such insurance for Operator’s automotive
equipment.

 

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

ARTICLE VI.

DRILLING AND DEVELOPMENT

A. Initial Well:

On or before the              day of                          ,             ,
Operator shall commence the drilling of the Initial Well at the following
location:

NOT APPLICABLE.

and shall thereafter continue the drilling of the well with due diligence to

The drilling of the Initial Well and the Head’s Up therein by all parties is
obligatory, subject to Article VI.C.1. as to participation in Completion
operations and Article VI.F. as to termination of operations and Article XI as
to occurrence of force majeure.

B. Subsequent Operations:

1. Proposed Operations: If any party hereto should desire to drill a Head’s Up
well on the Contract Area, or if any party should desire to Rework, Sidetrack,
Deepen, Recomplete or Plug Back a dry hole or a well no longer capable of
producing in paying quantities (whether a Carry Well or a Head’s Up Well) in
which such party has not otherwise relinquished its interest in the proposed
objective Zone under this agreement, the party desiring to drill, Rework,
Sidetrack, Deepen, Recomplete or Plug Back such a well shall give written notice
of the proposed operation to the parties who have not otherwise relinquished
their interest in such objective Zone under this agreement and to all other
parties in the case of a proposal for Sidetracking or Deepening, specifying the
work to be performed, the location, proposed depth, objective Zone and the
estimated cost of the operation. The parties to whom such a notice is delivered
shall have thirty (30) days after receipt of the notice within which to notify
the party proposing to do the work whether they elect to participate in the cost
of the proposed operation. If a drilling rig is on location, notice of a
proposal to Rework, Sidetrack, Recomplete, Plug Back or Deepen may be given by
telephone and the response period shall be limited to forty- eight (48) hours,
exclusive of Saturday, Sunday and legal holidays. Failure of a party to whom
such notice is delivered to reply within the period above fixed shall constitute
an election by that party not to participate in the cost of the proposed
operation. Any proposal by a party to conduct an operation conflicting with the
operation initially proposed shall be delivered to all parties within the time
and in the manner provided in Article VI.B.6.

If all parties to whom such notice is delivered elect to participate in such a
proposed operation, the parties shall be contractually committed to participate
therein provided such operations are commenced within the time period hereafter
set forth, and Operator shall, no later than ninety (90) days after expiration
of the notice period of thirty (30) days (or as promptly as practicable after
the expiration of the forty-eight (48) hour period when a drilling rig is on
location, as the case may be), actually commence the proposed operation and
thereafter complete it with due diligence at the risk and expense of the parties
participating therein; provided, however, said commencement date may be extended
upon written notice of same by Operator to the other parties, for a period of up
to thirty (30) additional days if, in the sole opinion of Operator, such
additional time is reasonably necessary to obtain permits from governmental
authorities, surface rights (including rights-of- way) or appropriate drilling
equipment, or to complete title examination or curative matter required for
title approval or acceptance. If the actual operation has not been commenced
within the time provided (including any extension thereof as specifically
permitted herein or in the force majeure provisions of Article XI) and if any
party hereto still desires to conduct said operation, written notice proposing
same must be resubmitted to the other parties in accordance herewith as if no
prior proposal had been made. Those parties that did not participate in the
drilling of a well for which a proposal to Deepen or Sidetrack is made hereunder
shall, if such parties desire to participate in the proposed Deepening or
Sidetracking operation, reimburse the Drilling Parties in accordance with
Article VI.B.4. in the event of a Deepening operation and in accordance with
Article VI.B.5. in the event of a Sidetracking operation.

 

  2. Operations by Less Than All Parties:

(a) Determination of Participation. If any party to whom such notice is
delivered as provided in Article VI.B.1. or VI.C.1. (Option No. 2) elects not to
participate in the proposed operation, then, in order to be entitled to the
benefits of this Article, the party or parties giving the notice and such other
parties as shall elect to participate in the operation shall, no later than
ninety (90) days after the expiration of the notice period of thirty (30) days
(or as promptly as practicable after the expiration of the forty-eight (48) hour
period when a drilling rig is on location, as the case may be) actually commence
the proposed operation and complete it with due diligence. Operator shall
perform all work for the account of the Consenting Parties; provided, however,
if no drilling rig or other equipment is on location, and if Operator is a
Non-Consenting Party,

 

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the Consenting Parties shall either: (i) request Operator to perform the work
required by such proposed operation for the account of the Consenting Parties,
or (ii) designate one of the Consenting Parties as Operator to perform such work
provided however, Operator shall not be required to do so. The rights and duties
granted to and imposed upon the Operator under this agreement are granted to and
imposed upon the party designated as Operator for an operation in which the
original Operator is a Non-Consenting Party. Consenting Parties, when conducting
operations on the Contract Area pursuant to this Article VI.B.2., shall comply
with all terms and conditions of this agreement.

If less than all parties approve any proposed operation, the proposing party,
immediately after the expiration of the applicable notice period, shall advise
all Parties of the total interest of the parties approving such operation and
its recommendation as to whether the Consenting Parties should proceed with the
operation as proposed. Each Consenting Party, within forty-eight (48) hours
(exclusive of Saturday, Sunday, and legal holidays) after delivery of such
notice, shall advise the proposing party of its desire to (i) limit
participation to such party’s interest as shown on Exhibit “A” or (ii) carry
only its proportionate part (determined by dividing such party’s interest in the
Contract Area by the interests of all Consenting Parties in the Contract Area)
of Non-Consenting Parties’ interests, or (iii) carry its proportionate part
(determined as provided in (ii)) of Non-Consenting Parties’ interests together
with all or a portion of its proportionate part of any Non-Consenting Parties’
interests that any Consenting Party did not elect to take. Any interest of
Non-Consenting Parties that is not carried by a Consenting Party shall be deemed
to be carried by the party proposing the operation if such party does not
withdraw its proposal. Failure to advise the proposing party within the time
required shall be deemed an election under (i). In the event a drilling rig is
on location, notice may be given by telephone, and the time permitted for such a
response shall not exceed a total of forty-eight (48) hours (exclusive of
Saturday, Sunday and legal holidays). The proposing party, at its election, may
withdraw such proposal if there is less than 100% participation and shall notify
all parties of such decision within ten (10) days, or within twenty-four
(24) hours if a drilling rig is on location, following expiration of the
applicable response period. If 100% subscription to the proposed operation is
obtained, the proposing party shall promptly notify the Consenting Parties of
their proportionate interests in the operation and the party serving as Operator
shall commence such operation within the period provided in Article VI.B.1.,
subject to the same extension right as provided therein.

(b) Relinquishment of Interest for Non-Participation. The entire cost and risk
of conducting such operations shall be borne by the Consenting Parties in the
proportions they have elected to bear same under the terms of the preceding
paragraph. Consenting Parties shall keep the leasehold estates involved in such
operations free and clear of all liens and encumbrances of every kind created by
or arising from the operations of the Consenting Parties. If such an operation
results in a dry hole, then subject to Articles VI.B.6. and VI.E.3., the
Consenting Parties shall plug and abandon the well and restore the surface
location at their sole cost, risk and expense; provided, however, that those
Non-Consenting Parties that participated in the drilling, Deepening or
Sidetracking of the well shall remain liable for, and shall pay, their
proportionate shares of the cost of plugging and abandoning the well and
restoring the surface location insofar only as those costs were not increased by
the subsequent operations of the Consenting Parties. If any well drilled,
Reworked, Sidetracked, Deepened, Recompleted or Plugged Back under the
provisions of this Article results in a well capable of producing Oil and/or Gas
in paying quantities, the Operator shall Complete and equip the well on behalf
of the Consenting Parties to produce at their sole cost and risk, and shall be
operated by it at the expense and for the account of the Consenting Parties. In
the event Operator elects not to participate in a Head’s Up Well, Operator shall
be entitled to a 2.5% of 8/8ths carried working interest in such well,
proportionately reduced if the Parties own less than the full leasehold or
mineral interest in such well. Upon commencement of operations for the drilling,
Reworking, Sidetracking, Recompleting, Deepening or Plugging Back of any such
well by Consenting Parties in accordance with the provisions of this Article,
each Non-Consenting Party shall be deemed to have relinquished to Consenting
Parties, and the Consenting Parties shall own and be entitled to receive, in
proportion to their respective interests, all of such Non- Consenting Party’s
interest in the well and share of production therefrom or, in the case of a
Reworking, Sidetracking, Deepening, Recompleting or Plugging Back, or a
Completion pursuant to Article VI.C.1. Option No. 2, all of such Non- Consenting
Party’s interest in the production obtained from the operation in which the
Non-Consenting Party did not elect to participate. Such relinquishment shall be
effective until the proceeds of the sale of such share, calculated at the well,
or market value thereof if such share is not sold (after deducting applicable ad
valorem, production, severance, and excise taxes, royalty, overriding royalty
and other interests not excepted by Article III.C. payable out of or measured by
the production from such well accruing with respect to such interest until it
reverts), shall equal the total of the following:

(i) 100 % of each such Non-Consenting Party’s share of the cost of any newly
acquired surface equipment beyond the wellhead connections (including but not
limited to stock tanks, separators, treaters, pumping equipment and piping),
plus 100% of each such Non-Consenting Party’s share of the cost of operation of
the well commencing with first production and continuing until each such
Non-Consenting Party’s relinquished interest shall revert to it under other
provisions of this Article, it being agreed that each Non-Consenting Party’s
share of such costs and equipment will be that interest which would have been
chargeable to such Non-Consenting Party had it participated in the well from the
beginning of the operations; and

 

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(ii) 300 % of (a) that portion of the costs and expenses of drilling*,
Reworking, Sidetracking, Deepening, Plugging Back, testing, Completing, and
Recompleting, after deducting any cash contributions received under Article
VIII.C., and of (b) that portion of the cost of newly acquired equipment in the
well (to and including the wellhead connections), which would have been
chargeable to such Non-Consenting Party if it had participated therein.

Notwithstanding anything to the contrary in this Article VI.B., if the well does
not reach the deepest objective Zone described in the notice proposing the well
for reasons other than the encountering of granite or practically impenetrable
substance or other condition in the hole rendering further operations
impracticable, Operator shall give notice thereof to each Non-Consenting Party
who submitted or voted for an alternative proposal under Article VI.B.6. to
drill the well to a shallower Zone than the deepest objective Zone proposed in
the notice under which the well was drilled, and each such Non- Consenting Party
shall have the option to participate in the initial proposed Completion of the
well by paying its share of the cost of drilling the well to its actual depth,
calculated in the manner provided in Article VI.B.4. (a). If any such Non-
Consenting Party does not elect to participate in the first Completion proposed
for such well, the relinquishment provisions of this Article VI.B.2. (b) shall
apply to such party’s interest.

(c) Reworking, Recompleting or Plugging Back. An election not to participate in
the drilling*, Sidetracking or Deepening of a well shall be deemed an election
not to participate in any Reworking or Plugging Back operation proposed in such
a well, or portion thereof, to which the initial non-consent election applied
that is conducted at any time prior to full recovery by the Consenting Parties
of the Non-Consenting Party’s recoupment amount. Similarly, an election not to
participate in the Completing or Recompleting of a well shall be deemed an
election not to participate in any Reworking operation proposed in such a well,
or portion thereof, to which the initial non-consent election applied that is
conducted at any time prior to full recovery by the Consenting Parties of the
Non-Consenting Party’s recoupment amount. Any such Reworking, Recompleting or
Plugging Back operation conducted during the recoupment period shall be deemed
part of the cost of operation of said well and there shall be added to the sums
to be recouped by the Consenting Parties 400% of that portion of the costs of
the Reworking, Recompleting or Plugging Back operation which would have been
chargeable to such Non-Consenting Party had it participated therein. If such a
Reworking, Recompleting or Plugging Back operation is proposed during such
recoupment period, the provisions of this Article VI.B. shall be applicable as
between said Consenting Parties in said well.

(d) Recoupment Matters. During the period of time Consenting Parties are
entitled to receive Non-Consenting Party’s share of production, or the proceeds
therefrom, Consenting Parties shall be responsible for the payment of all ad
valorem, production, severance, excise, gathering and other taxes, and all
royalty, overriding royalty and other burdens applicable to Non-Consenting
Party’s share of production not excepted by Article III.C.

In the case of any Reworking, Sidetracking, Plugging Back, Recompleting or
Deepening operation, the Consenting Parties shall be permitted to use, free of
cost, all casing, tubing and other equipment in the well, but the ownership of
all such equipment shall remain unchanged; and upon abandonment of a well after
such Reworking, Sidetracking, Plugging Back, Recompleting or Deepening, the
Consenting Parties shall account for all such equipment to the owners thereof,
with each party receiving its proportionate part in kind or in value, less cost
of salvage.

Within ninety (90) days after the completion of any operation under this
Article, the party conducting the operations for the Consenting Parties shall
furnish each Non-Consenting Party with an inventory of the equipment in and
connected to the well, and an itemized statement of the cost of drilling*,
Sidetracking, Deepening, Plugging Back, testing, Completing, Recompleting, and
equipping the well for production; or, at its option, the operating party, in
lieu of an itemized statement of such costs of operation, may submit a detailed
statement of monthly billings. Each month thereafter, during the time the
Consenting Parties are being reimbursed as provided above, the party conducting
the operations for the Consenting Parties shall furnish the Non-Consenting
Parties with an itemized statement of all costs and liabilities incurred in the
operation of the well, together with a statement of the quantity of Oil and Gas
produced from it and the amount of proceeds realized from the sale of the well’s
working interest production during the preceding month. In determining the
quantity of Oil and Gas produced during any month, Consenting Parties shall use
industry accepted methods such as but not limited to metering or periodic well
tests. Any amount realized from the sale or other disposition of equipment newly
acquired in connection with any such operation which would have been owned by a
Non-Consenting Party had it participated therein shall be credited against the
total unreturned costs of the work done and of the equipment purchased in
determining when the interest of such Non-Consenting Party shall revert to it as
above provided; and if there is a credit balance, it shall be paid to such Non-
Consenting Party.

If and when the Consenting Parties recover from a Non-Consenting Party’s
relinquished interest the amounts provided for above, the relinquished interests
of such Non-Consenting Party shall automatically revert to it as of 7:00 a.m. on
the day following the day on which such recoupment occurs, and, from and after
such reversion, such Non-Consenting Party shall own the same interest in such
well, the material and equipment in or pertaining thereto, and the production
therefrom *excluding_Carry_Wells as

 

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such Non-Consenting Party would have been entitled to had it participated in the
drilling*, Sidetracking, Reworking, Deepening, Recompleting or Plugging Back of
said well. Thereafter, such Non-Consenting Party shall be charged with and shall
pay its proportionate part of the further costs of the operation of said well in
accordance with the terms of this agreement and Exhibit “C” attached hereto.

3. Stand-By Costs: When a well which has been drilled or Deepened has reached
its authorized depth and all tests have been completed and the results thereof
furnished to the parties, or when operations on the well have been otherwise
terminated pursuant to Article VI.F., stand-by costs incurred pending response
to a party’s notice proposing a Reworking, Sidetracking, Deepening,
Recompleting, Plugging Back or Completing operation in such a well (including
the period required under Article VI.B.6. to resolve competing proposals) shall
be charged and borne as part of the drilling or Deepening operation just
completed. Stand-by costs subsequent to all parties responding, or expiration of
the response time permitted, whichever first occurs, and prior to agreement as
to the participating interests of all Consenting Parties pursuant to the terms
of the second grammatical paragraph of Article VI.B.2. (a), shall be charged to
and borne as part of the proposed operation, but if the proposal is subsequently
withdrawn because of insufficient participation, such stand-by costs shall be
allocated between the Consenting Parties in the proportion each Consenting
Party’s interest as shown on Exhibit “A” bears to the total interest as shown on
Exhibit “A”, as appropriate in context, of all Consenting Parties.

In the event that notice for a Sidetracking operation is given while the
drilling rig to be utilized is on location, any party may request and receive up
to five (5) additional days after expiration of the forty-eight hour response
period specified in Article VI.B.1. within which to respond by paying for all
stand-by costs and other costs incurred during such extended response period;
Operator may require such party to pay the estimated stand-by time in advance as
a condition to extending the response period. If more than one party elects to
take such additional time to respond to the notice, standby costs shall be
allocated between the parties taking additional time to respond on a day-to-day
basis in the proportion each electing party’s interest as shown on Exhibit “A”
bears to the total interest as shown on Exhibit “A” , as appropriate in context,
of all the electing parties.

4. Deepening: If less than all parties elect to participate in a drilling*,
Sidetracking, or Deepening operation proposed pursuant to Article VI.B.1., the
interest relinquished by the Non-Consenting Parties to the Consenting Parties
under Article VI.B.2. shall relate only and be limited to the lesser of (i) the
total depth actually drilled or (ii) the objective depth or Zone of which the
parties were given notice under Article VI.B.1. (“Initial Objective”). Such well
shall not be Deepened beyond the Initial Objective without first complying with
this Article to afford the Non-Consenting Parties the opportunity to participate
in the Deepening operation.

In the event any Consenting Party desires to drill or Deepen a Non-Consent Well
to a depth below the Initial Objective, such party shall give notice thereof,
complying with the requirements of Article VI.B.1., to all parties (including
Non- Consenting Parties). Thereupon, Articles VI.B.1. and 2. shall apply and all
parties receiving such notice shall have the right to participate or not
participate in the Deepening of such well pursuant to said Articles VI.B.1. and
2. If a Deepening operation is approved pursuant to such provisions, and if any
Non-Consenting Party elects to participate in the Deepening operation, such
Non-Consenting party shall pay or make reimbursement (as the case may be) of the
following costs and expenses.

(a) If the proposal to Deepen is made prior to the Completion of such well as a
well capable of producing in paying quantities, such Non-Consenting Party shall
pay (or reimburse Consenting Parties for, as the case may be) that share of
costs and expenses incurred in connection with the drilling of said well from
the surface to the Initial Objective which Non- Consenting Party would have paid
had such Non-Consenting Party agreed to participate therein, plus the
Non-Consenting Party’s share of the cost of Deepening and of participating in
any further operations on the well in accordance with the other provisions of
this Agreement; provided, however, all costs for testing and Completion or
attempted Completion of the well incurred by Consenting Parties prior to the
point of actual operations to Deepen beyond the Initial Objective shall be for
the sole account of Consenting Parties.

(b) If the proposal is made for a Non-Consent Well that has been previously
Completed as a well capable of producing in paying quantities, but is no longer
capable of producing in paying quantities, such Non-Consenting Party shall pay
(or reimburse Consenting Parties for, as the case may be) its proportionate
share of all costs of drilling, Completing, and equipping said well from the
surface to the Initial Objective, calculated in the manner provided in paragraph
(a) above, less those costs recouped by the Consenting Parties from the sale of
production from the well. The Non-Consenting Party shall also pay its
proportionate share of all costs of re-entering said well. The Non-Consenting
Parties’ proportionate part (based on the percentage of such well Non-Consenting
Party would have owned had it previously participated in such Non-Consent Well)
of the costs of salvable materials and equipment remaining in the hole and
salvable surface equipment used in connection with such well shall be determined
in accordance with Exhibit “C.” If the Consenting Parties have recouped the cost
of drilling, Completing, and equipping the well at the time such Deepening
operation is conducted, then a Non- Consenting Party may participate in the
Deepening of the well with no payment for costs incurred prior to re-entering
the well for Deepening.

 

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The foregoing shall not imply a right of any Consenting Party to propose any
Deepening for a Non-Consent Well prior to the drilling of such well to its
Initial Objective without the consent of the other Consenting Parties as
provided in Article VI.F.

5. Sidetracking: Any party having the right to participate in a proposed
Sidetracking operation that does not own an interest in the affected wellbore at
the time of the notice shall, upon electing to participate, tender to the
wellbore owners its proportionate share (equal to its interest in the
Sidetracking operation) of the value of that portion of the existing wellbore to
be utilized as follows:

(a) If the proposal is for Sidetracking an existing dry hole, reimbursement
shall be on the basis of the actual costs incurred in the initial drilling of
the well down to the depth at which the Sidetracking operation is initiated.

(b) If the proposal is for Sidetracking a well which has previously produced,
reimbursement shall be on the basis of such party’s proportionate share of
drilling and equipping costs incurred in the initial drilling of the well down
to the depth at which the Sidetracking operation is conducted, calculated in the
manner described in Article VI.B.4(b) above. Such party’s proportionate share of
the cost of the well’s salvable materials and equipment down to the depth at
which the Sidetracking operation is initiated shall be determined in accordance
with the provisions of Exhibit “C.”

* excluding Carry Wells

6. Order of Preference of Operations. Except as otherwise specifically provided
in this agreement, if any party desires to propose the conduct of an operation
that conflicts with a proposal that has been made by a party under this Article
VI, such party shall have fifteen (15) days from delivery of the initial
proposal, in the case of a proposal to drill a well or to perform an operation
on a well where no drilling rig is on location, or twenty-four (24) hours,
exclusive of Saturday, Sunday and legal holidays, from delivery of the initial
proposal, if a drilling rig is on location for the well on which such operation
is to be conducted, to deliver to all parties entitled to participate in the
proposed operation such party’s alternative proposal, such alternate proposal to
contain the same information required to be included in the initial proposal.
Each party receiving such proposals shall elect by delivery of notice to
Operator within five (5) days after expiration of the proposal period, or within
twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) if a
drilling rig is on location for the well that is the subject of the proposals,
to participate in one of the competing proposals. Any party not electing within
the time required shall be deemed not to have voted. The proposal receiving the
vote of parties owning the largest aggregate percentage interest of the parties
voting shall have priority over all other competing proposals; in the case of a
tie vote, the initial proposal shall prevail. Operator shall deliver notice of
such result to all parties entitled to participate in the operation within five
(5) days after expiration of the election period (or within twenty-four
(24) hours, exclusive of Saturday, Sunday and legal holidays, if a drilling rig
is on location). Each party shall then have two (2) days (or twenty-four
(24) hours if a rig is on location) from receipt of such notice to elect by
delivery of notice to Operator to participate in such operation or to relinquish
interest in the affected well pursuant to the provisions of Article VI.B.2.;
failure by a party to deliver notice within such period shall be deemed an
election not to participate in the prevailing proposal.

7. Conformity to Spacing Pattern. Notwithstanding the provisions of this Article
VI.B.2., it is agreed that no wells shall be proposed to be drilled to or
Completed in or produced from a Zone from which a well located elsewhere on the
Contract Area is producing, unless such well conforms to the then-existing well
spacing pattern or an approved exception thereto for such Zone.

8. Paying Wells. No party shall conduct any Reworking, Deepening, Plugging Back,
Completion, Recompletion, or Sidetracking operation under this agreement with
respect to any well then capable of producing in paying quantities except with
the consent of all parties that have not relinquished interests in the well at
the time of such operation.

C. Completion of Wells; Reworking and Plugging Back:

1. Completion: Without the consent of all parties, no well shall be drilled,
Deepened or Sidetracked, except any well Drilled, Deepened or Sidetracked
pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the
drilling*,

Deepening or Sidetracking shall include:

 

  þ Option No. 1: All necessary expenditures for the drilling, Deepening or
Sidetracking, testing, Completing and equipping of the well, including necessary
tankage and/or surface facilities.

 

  ¨

Option No. 2: All necessary expenditures for the drilling, Deepening or
Sidetracking and testing of the well. When such well has reached its authorized
depth, and all logs, cores and other tests have been completed, and the results
thereof furnished to the parties, Operator shall give immediate notice to the
Non-Operators having the right to participate in a Completion attempt whether or
not Operator recommends attempting to Complete the well, together with
Operator’s AFE for Completion costs if not previously provided. The parties
receiving such notice shall have forty-eight (48) hours (exclusive of Saturday,
Sunday and legal holidays) in which to elect by delivery of notice to Operator
to participate in a recommended Completion attempt or to make a Completion
proposal with an accompanying AFE. Operator shall deliver any such Completion
proposal, or any Completion proposal conflicting

 

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  with Operator’s proposal, to the other parties entitled to participate in such
Completion in accordance with the procedures specified in Article VI.B.6.
Election to participate in a Completion attempt shall include consent to all
necessary expenditures for the Completing and equipping of such well, including
necessary tankage and/or surface facilities but excluding any stimulation
operation not contained on the Completion AFE. Failure of any party receiving
such notice to reply within the period above fixed shall constitute an election
by that party not to participate in the cost of the Completion attempt;
provided, that Article VI.B.6. shall control in the case of conflicting
Completion proposals. If one or more, but less than all of the parties, elect to
attempt a Completion, the provision of Article VI.B.2. hereof (the phrase
“Reworking, Sidetracking, Deepening, Recompleting or Plugging Back” as contained
in Article VI.B.2. shall be deemed to include “Completing”) shall apply to the
operations thereafter conducted by less than all parties; provided, however,
that Article VI.B.2. shall apply separately to each separate Completion or
Recompletion attempt undertaken hereunder, and an election to become a
Non-Consenting Party as to one Completion or Recompletion attempt shall not
prevent a party from becoming a Consenting Party in subsequent Completion or
Recompletion attempts regardless whether the Consenting Parties as to earlier
Completions or Recompletion have recouped their costs pursuant to Article
VI.B.2.; provided further, that any recoupment of costs by a Consenting Party
shall be made solely from the production attributable to the Zone in which the
Completion attempt is made. Election by a previous Non-Consenting party to
participate in a subsequent Completion or Recompletion attempt shall require
such party to pay its proportionate share of the cost of salvable materials and
equipment installed in the well pursuant to the previous Completion or
Recompletion attempt, insofar and only insofar as such materials and equipment
benefit the Zone in which such party participates in a Completion attempt.

2. Rework, Recomplete or Plug Back: No well shall be Reworked, Recompleted or
Plugged Back except a well Reworked, Recompleted, or Plugged Back pursuant to
the provisions of Article VI.B.2. of this agreement. Consent to the Reworking,
Recompleting or Plugging Back of a well shall include all necessary expenditures
in conducting such operations and Completing and equipping of said well,
including necessary tankage and/or surface facilities.

D. Other Operations:

Operator shall not undertake any single project reasonably estimated to require
an expenditure in excess of Fifty Thousand Dollars ($50,000.00) except in
connection with the drilling, Sidetracking, Reworking, Deepening, Completing,
Recompleting or Plugging Back of a well that has been previously authorized by
or pursuant to this agreement; provided, however, that, in case of explosion,
fire, flood or other sudden emergency, whether of the same or different nature,
Operator may take such steps and incur such expenses as in its opinion are
required to deal with the emergency to safeguard life and property but Operator,
as promptly as possible, shall report the emergency to the other parties. If
Operator prepares an AFE for its own use, Operator shall furnish any
Non-Operator so requesting an information copy thereof for any single project
costing in excess of Fifty Thousand Dollars ($50,000.00). Any party who has not
relinquished its interest in a well shall have the right to propose that *
excluding Carry Wells

Operator perform repair work or undertake the installation of artificial lift
equipment or ancillary production facilities such as salt water disposal wells
or to conduct additional work with respect to a well drilled hereunder or other
similar project (but not including the installation of gathering lines or other
transportation or marketing facilities, the installation of which shall be
governed by separate agreement between the parties) reasonably estimated to
require an expenditure in excess of the amount first set forth above in this
Article VI.D. (except in connection with an operation required to be proposed
under Articles VI.B.1. or VI.C.1. Option No. 2, which shall be governed
exclusively be those Articles). Operator shall deliver such proposal to all
parties entitled to participate therein. If within thirty (30) days thereof
Operator secures the written consent of any party or parties owning at least 50%
of the interests of the parties entitled to participate in such operation, each
party having the right to participate in such project shall be bound by the
terms of such proposal and shall be obligated to pay its proportionate share of
the costs of the proposed project as if it had consented to such project
pursuant to the terms of the proposal.

E. Abandonment of Wells:

1. Abandonment of Dry Holes: Except for any well drilled or Deepened pursuant to
Article VI.B.2., Any well which has been drilled or Deepened under the terms of
this agreement and is proposed to be completed as a dry hole shall not be
plugged and abandoned without the consent of all parties. Should Operator, after
diligent effort, be unable to contact any party, or should any party fail to
reply within forty-eight (48) hours (exclusive of Saturday, Sunday and legal
holidays) after delivery of notice of the proposal to plug and abandon such
well, such party shall be deemed to have consented to the proposed abandonment.
All such wells shall be plugged and abandoned in accordance with applicable
regulations and at the

 

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

cost, risk and expense of the parties who participated in the cost of drilling
or Deepening such well. Any party who objects to plugging and abandoning such
well by notice delivered to Operator within forty-eight (48) hours (exclusive of
Saturday, Sunday and legal holidays) after delivery of notice of the proposed
plugging shall take over the well as of the end of such forty-eight (48) hour
notice period and conduct further operations in search of Oil and/or Gas subject
to the provisions of Article VI.B.; failure of such party to provide proof
reasonably satisfactory to Operator of its financial capability to conduct such
operations or to take over the well within such period or thereafter to conduct
operations on such well or plug and abandon such well shall entitle Operator to
retain or take possession of the well and plug and abandon the well. The party
taking over the well shall indemnify Operator (if Operator is an abandoning
party) and the other abandoning parties against liability for any further
operations conducted on such well except for the costs of plugging and
abandoning the well and restoring the surface, for which the abandoning parties
shall remain proportionately liable.

2. Abandonment of Wells That Have Produced: Except for any well in which a
Non-Consent operation has been conducted hereunder for which the Consenting
Parties have not been fully reimbursed as herein provided, any well which has
been completed as a producer shall not be plugged and abandoned without the
consent of all parties. If all parties consent to such abandonment, the well
shall be plugged and abandoned in accordance with applicable regulations and at
the cost, risk and expense of all the parties hereto. Failure of a party to
reply within sixty (60) days of delivery of notice of proposed abandonment shall
be deemed an election to consent to the proposal. If, within sixty (60) days
after delivery of notice of the proposed abandonment of any well, all parties do
not agree to the abandonment of such well, those wishing to continue its
operation from the Zone then open to production shall be obligated to take over
the well as of the expiration of the applicable notice period and shall
indemnify Operator (if Operator is an abandoning party) and the other abandoning
parties against liability for any further operations on the well conducted by
such parties. Failure of such party or parties to provide proof reasonably
satisfactory to Operator of their financial capability to conduct such
operations or to take over the well within the required period or thereafter to
conduct operations on such well, shall entitle operator to retain or take
possession of such well and plug and abandon the well.

Parties taking over a well as provided herein shall tender to each of the other
parties its proportionate share of the value of the well’s salvable material and
equipment, determined in accordance with the provisions of Exhibit “C,” less the
estimated cost of salvaging and the estimated cost of plugging and abandoning
and restoring the surface; provided, however, that in the event the estimated
plugging and abandoning and surface restoration costs and the estimated cost of
salvaging are higher than the value of the well’s salvable material and
equipment, each of the abandoning parties shall tender to the parties continuing
operations their proportionate shares of the estimated excess cost. Each
abandoning party shall assign to the non-abandoning parties, without warranty,
express or implied, as to title or as to quantity, or fitness for use of the
equipment and material, all of its interest in the wellbore of the well and
related equipment, together with its interest in the Leasehold insofar and only
insofar as such Leasehold covers the right to obtain production from that
wellbore in the Zone then open to production. If the interest of the abandoning
party is or includes an Oil and Gas Interest, such party shall execute and
deliver to the non- abandoning party or parties an oil and gas lease, limited to
the wellbore and the Zone then open to production, for a term of one (1) year
and so long thereafter as Oil and/or Gas is produced from the Zone covered
thereby, such lease to be on the form mutually acceptable to the parties and
provide for a 16.67% royalty. attached as Exhibit “B.” The assignments or leases
so limited shall encompass the Drilling Unit upon which the well is located. The
payments by, and the assignments or leases to, the assignees shall be in a ratio
based upon the relationship of their respective percentage of participation in
the Contract Area to the aggregate of the percentages of participation in the
Contract Area of all assignees. There shall be no readjustment of interests in
the remaining portions of the Contract Area.

Thereafter, abandoning parties shall have no further responsibility, liability,
or interest in the operation of or production from the well in the Zone then
open other than the royalties retained in any lease made under the terms of this
Article. Upon request, Operator shall continue to operate the assigned well for
the account of the non-abandoning parties at the rates and charges contemplated
by this agreement, plus any additional cost and charges which may arise as the
result of the separate ownership of the assigned well. Upon proposed abandonment
of the producing Zone assigned or leased, the assignor or lessor shall then have
the option to repurchase its prior interest in the well (using the same
valuation formula) and participate in further operations therein subject to the
provisions hereof.

3. Abandonment of Non-Consent Operations: The provisions of Article VI.E.1. or
VI.E.2. above shall be applicable as between Consenting Parties in the event of
the proposed abandonment of any well excepted from said Articles; provided,
however, no well shall be permanently plugged and abandoned unless and until all
parties having the right to conduct further operations therein have been
notified of the proposed abandonment and afforded the opportunity to elect to
take over the well in accordance with the provisions of this Article VI.E.; and
provided further, that Non-Consenting Parties who own an interest in a portion
of the well shall pay their proportionate shares of abandonment and surface
restoration cost for such well as provided in Article VI.B.2.(b).

 

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F. Termination of Operations:

Upon the commencement of an operation for the drilling, Reworking, Sidetracking,
Plugging Back, Deepening, testing, Completion or plugging of a well, including
but not limited to the Initial Well, such operation shall not be terminated
without consent of a party or parties bearing 50% of the costs of such
operation; provided, however, that in the event granite or other practically
impenetrable substance or condition in the hole is encountered which renders
further operations impractical, Operator may discontinue operations and give
notice of such condition in the manner provided in Article VI.B.1, and the
provisions of Article VI.B. or VI.E. shall thereafter apply to such operation,
as appropriate.

G. Taking Production in Kind:

þ Option No. 1: Gas Balancing Agreement Attached

Each party shall take in kind or separately dispose of its proportionate share
of all Oil and Gas produced from the Contract Area, exclusive of production
which may be used in development and producing operations and in preparing and
treating Oil and Gas for marketing purposes and production unavoidably lost. Any
extra expenditure incurred in the taking in kind or separate disposition by any
party of its proportionate share of the production shall be borne by such party.
Any party taking its share of production in kind shall be required to pay for
only its proportionate share of such part of Operator’s surface facilities which
it uses.

Each party shall execute such division orders and contracts as may be necessary
for the sale of its interest in production from the Contract Area, and, except
as provided in Article VII.B., shall be entitled to receive payment directly
from the purchaser thereof for its share of all production.

If any party fails to make the arrangements necessary to take in kind or
separately dispose of its proportionate share of the Oil and/ or Gas produced
from the Contract Area, Operator shall have the right, subject to the revocation
at will by the party owning it, but not the obligation, to purchase such Oil
and/ or Gas or sell it to others at any time and from time to time, for the
account of the non-taking party. Any such purchase or sale by Operator may be
terminated by Operator upon at least ten (10) days written notice to the owner
of said production and shall be subject always to the right of the owner of the
production upon at least ten (10) days written notice to Operator to exercise at
any time its right to take in kind, or separately dispose of, its share of all
Oil and/ or Gas not previously delivered to a purchaser, provided, however, that
the effective date of any such revocation may be deferred at Operator’s election
for a period not to exceed ninety (90) days if Operator has committed such
production to a purchase contract having a term extending beyond such ten
(10) day period.

Any purchase or sale by Operator of any other party’s share of Oil shall be only
for such reasonable periods of time as are consistent with the minimum needs of
the industry under the particular circumstances, but in no event for a period in
excess of one (1) year.

Any such sale by Operator shall be in a manner commercially reasonable under the
circumstances but Operator shall have no duty to share any existing market or to
obtain a price equal to that received under any existing market. The sale or
delivery by Operator of a non-taking party’s share of Oil and/ or Gas under the
terms of any existing contract of Operator shall not give the non-taking party
any interest in or make the non-taking party a party to said contract. No
purchase shall be made by Operator without first giving the non-taking party at
least ten (10) days written notice of such intended purchase or sale and the
price to be paid or the pricing basis to be used.

All parties shall give timely written notice to Operator of their Gas marketing
arrangements for the following month, excluding price, and shall notify Operator
immediately in the event of a change in such arrangements. Operator shall
maintain records of all marketing arrangements, and of volumes actually sold or
transported, which records shall be made available to Non-Operators upon
reasonable request.

In the event one or more parties’ separate disposition of its share of the Gas
causes split-stream deliveries to separate pipelines and/or deliveries which on
a day-to-day basis for any reason are not exactly equal to a party’s respective
proportion- ate share of total Gas sales to be allocated to it, the balancing or
accounting between the parties shall be in accordance with any Gas balancing
agreement between the parties hereto, whether such an agreement is attached as
Exhibit “E” or is a separate agreement. Operator shall give notice to all
parties of the first sales of Gas from any well under this agreement.

 

¨ Option No. 2: No Gas Balancing Agreement:

Each party shall take in kind or separately dispose of its proportionate share
of all Oil and Gas produced from the Contract Area, exclusive of production
which may be used in development and producing operations and in preparing and
treating Oil and Gas for marketing purposes and production unavoidably lost. Any
extra expenditures incurred in the taking in kind or separate disposition by any
party of its proportionate share of the production shall be borne by such party.
Any party taking its share of production in kind shall be required to pay for
only its proportionate share of such part of Operator’s surface facilities which
it uses.

 

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Each party shall execute such division orders and contracts as may be necessary
for the sale of its interest in production from the Contract Area, and, except
as provided in Article VII.B., shall be entitled to receive payment directly
from the purchaser thereof for its share of all production.

If any party fails to make the arrangements necessary to take in kind or
separately dispose of its proportionate share of the Oil and/or Gas produced
from the Contract Area, Operator shall have the right, subject to the revocation
at will by the party owning it, but not the obligation, to purchase such Oil
and/or Gas or sell it to others at any time and from time to time, for the
account of the non-taking party. Any such purchase or sale by Operator may be
terminated by Operator upon at least ten (10) days written notice to the owner
of said production and shall be subject always to the right of the owner of the
production upon at least ten (10) days written notice to Operator to exercise
its right to take in kind, or separately dispose of, its share of all Oil and/or
Gas not previously delivered to a purchaser; provided, however, that the
effective date of any such revocation may be deferred at Operator’s election for
a period not to exceed ninety (90) days if Operator has committed such
production to a purchase contract having a term extending beyond such ten
(10) -day period. Any purchase or sale by Operator of any other party’s share of
Oil and/or Gas shall be only for such reasonable periods of time as are
consistent with the minimum needs of the industry under the particular
circumstances, but in no event for a period in excess of one (1) year.

Any such sale by Operator shall be in a manner commercially reasonable under the
circumstances, but Operator shall have no duty to share any existing market or
transportation arrangement or to obtain a price or transportation fee equal to
that received under any existing market or transportation arrangement. The sale
or delivery by Operator of a non-taking party’s share of production under the
terms of any existing contract of Operator shall not give the non-taking party
any interest in or make the non-taking party a party to said contract. No
purchase of Oil and Gas and no sale of Gas shall be made by Operator without
first giving the non-taking party ten days written notice of such intended
purchase or sale and the price to be paid or the pricing basis to be used.
Operator shall give notice to all parties of the first sale of Gas from any well
under this Agreement.

All parties shall give timely written notice to Operator of their Gas marketing
arrangements for the following month, excluding price, and shall notify Operator
immediately in the event of a change in such arrangements. Operator shall
maintain records of all marketing arrangements, and of volumes actually sold or
transported, which records shall be made available to Non-Operators upon
reasonable request.

ARTICLE VII.

EXPENDITURES AND LIABILITY OF PARTIES

A. Liability of Parties:

The liability of the parties shall be several, not joint or collective. Each
party shall be responsible only for its obligations, and shall be liable only
for its proportionate share of the costs of developing the operating the
Contract Area commensurate with a party’s interests reflected in Exhibit “A”.
Accordingly, the liens granted among the parties in Article VII.B. are given to
secure only the debts of each severally, and no party shall have any liability
to third parties hereunder to satisfy the default of any other party in the
payment of any expense or obligation hereunder. It is not the intention of the
parties to create, nor shall this agreement be construed as creating, a mining
or other partnership, joint venture, agency relationship or association, or to
render the parties liable as partners, co- venturers, or principals. In their
relations with each other under this agreement, the parties shall not be
considered fiduciaries or to have established a confidential relationship but
rather shall be free to act on an arm’s-length basis in accordance with their
own respective self-interest, subject, however, to the obligation of the parties
to act in good faith in their dealings with each other with respect to
activities hereunder.

B. Liens and Security Interests:

Each party grants to the other parties hereto a lien upon any interest it now
owns or hereafter acquires in a Carry and/or Head’s Up Well, and a security
interest and/or purchase money security interest in any interest it now owns or
hereafter acquires in the personal property and fixtures on or used or obtained
for use in connection therewith, to secure performance of all of its obligations
under this agreement and/or the BJU Carry and Earning Agreement, including but
not limited to payment of expense, interest and fees, the proper disbursement of
all monies paid hereunder, the assignment or relinquishment of interest in Carry
and/or Head’s Up Wells required hereunder, and the proper performance of
operations hereunder. Such lien and security interest granted by each party
hereto shall include such party’s working interests in the Carry and/or Head’s
Up Wells now owned or hereafter acquired, the Oil and Gas when extracted
therefrom and equipment situated thereon or used or obtained for use in
connection therewith (including, without limitation, all wells, tools, and
tubular goods), and accounts (including, without limitation, accounts arising
from gas imbalances or from the sale of Oil and/or Gas at the wellhead),
contract rights, inventory and general intangibles relating thereto or arising
therefrom, and all proceeds and products of the foregoing.

 

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To perfect the lien and security agreement provided herein, each party hereto
shall execute and acknowledge the recording supplement and/or any financing
statement prepared and submitted by any party hereto in conjunction herewith or
at any time following execution hereof, and Operator is authorized to file this
agreement or the recording supplement executed herewith as a lien or mortgage in
the applicable real estate records and as a financing statement with the proper
officer under the Uniform Commercial Code in the state in which the Contract
Area is situated and such other states as Operator shall deem appropriate to
perfect the security interest granted hereunder. Any party may file this
agreement, the recording supplement executed herewith, or such other documents
as it deems necessary as a lien or mortgage in the applicable real estate
records and/or a financing statement with the proper officer under the Uniform
Commercial Code.

Each party represents and warrants to the other parties hereto that the lien and
security interest granted by such party to the other parties shall be a first
and prior lien, and each party hereby agrees to maintain the priority of said
lien and security interest against all persons acquiring an interest in the
Carry and/or Head’s Up Wells covered by this agreement and/or the BJU Carry &
Earning Agreement by, through or under such party. All parties acquiring an
interest in the Carry and/or Head’s Up Wells Covered_by_this_agreement, whether
by assignment, merger, mortgage, operation of law, or otherwise, shall be deemed
to have_taken_subject to the lien and security interest granted by this Article
VII.B. as to all obligations attributable to such interest hereunder whether or
not such obligations arise before or after such interest is acquired.

To the extent that parties have a security interest under the Uniform Commercial
Code of the state in which the Contract Area is situated, they shall be entitled
to exercise the rights and remedies of a secured party under the Code. The
bringing of a suit and the obtaining of judgment by a party for the secured
indebtedness shall not be deemed an election of remedies or otherwise affect the
lien rights or security interest as security for the payment thereof. In
addition, upon default by any party in the payment of its share of expenses,
interests or fees, or upon the improper use of funds by the Operator, or upon
default by any party in the payment of amounts due pursuant to, or performance
under, the provisions of this agreement and/or the BJU Carry and Earning
Agreement, the other parties shall have the right, without prejudice to other
rights or remedies, to collect from the purchaser the proceeds from the sale of
such defaulting party’s share of Oil and Gas until the amount owed by such
party, plus interest as provided in “Exhibit C,” has been received, and shall
have the right to offset the amount owed against the proceeds from the sale of
such defaulting party’s share of Oil and Gas. All purchasers of production may
rely on a notification of default from the non-defaulting party or parties
stating the amount due as a result of the default, and all parties waive any
recourse available against purchasers for releasing production proceeds as
provided in this paragraph.

If any party fails to pay its share of cost within one hundred twenty (120) days
after rendition of a statement therefor by Operator, the non-defaulting parties,
including Operator, shall upon request by Operator, pay the unpaid amount in the
proportion that the interest of each such party bears to the interest of all
such parties. The amount paid by each party so paying its share of the unpaid
amount shall be secured by the liens and security rights described in Article
VII.B., and each paying party may independently pursue any remedy available
hereunder or otherwise.

If any party does not perform all of its obligations under this agreement and/or
the BJU Carry and Earning Agreement, and the failure to perform subjects such
party to foreclosure or execution proceedings pursuant to the provisions of this
agreement and/or the BJU Carry and Earning Agreement, to the extent allowed by
governing law, the defaulting party waives any available right of redemption
from and after the date of judgment, any required valuation or appraisement of
the mortgaged or secured property prior to sale, any available right to stay
execution or to require a marshaling of assets and any required bond in the
event a receiver is appointed. In addition, to the extent permitted by
applicable law, each party hereby grants to the other parties a power of sale as
to any property that is subject to the lien and security rights granted
hereunder, such power to be exercised in the manner provided by applicable law
or otherwise in a commercially reasonable manner and upon reasonable notice.

Each party agrees that the other parties shall be entitled to utilize the
provisions of Oil and Gas lien law or other lien law of any state in which the
Contract Area is situated to enforce the obligations of each party hereunder.
Without limiting the generality of the foregoing, to the extent permitted by
applicable law, Non-Operators agree that Operator may invoke or utilize the
mechanics’ or materialmen’s lien law of the state in which the Contract Area is
situated in order to secure the payment to Operator of any sum due hereunder for
services performed or materials supplied by Operator.

C. Advances:

Operator, at its election, shall have the right from time to time to demand and
receive from one or more of the other parties payment in advance of their
respective shares of the estimated amount of the expense to be incurred in
operations hereunder during the next succeeding month, which right may be
exercised only by submission to each such party of an itemized statement of such
estimated expense, together with an invoice for its share thereof. Each such
statement and invoice

 

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for the payment in advance of estimated expense shall be submitted on or before
the 20th day of the next preceding month. Each party shall pay to Operator its
proportionate share of such estimate within fifteen (15) days after such
estimate and invoice is received. If any party fails to pay its share of said
estimate within said time, the amount due shall bear interest as provided in
Exhibit “C” until paid. Proper adjustment shall be made monthly between advances
and actual expense to the end that each party shall bear and pay its
proportionate share of actual expenses incurred, and no more.

D. Defaults and Remedies:

If any party fails to discharge any financial obligation under the BJU Carry and
Earning Agreement or this agreement, including without limitation the failure to
make any advance under the preceding Article VII.C. or any other provision of
this agreement, within the period required for such payment thereunder or
hereunder, then in addition to the remedies provided in Article VII.B. or
elsewhere in this agreement or in the BJU Carry and Earning Agreement, the
remedies specified below shall be applicable. For purposes of this Article
VII.D., all notices and elections shall be delivered only by Operator, except
that Operator shall deliver any such notice and election requested by a
non-defaulting Non-Operator, and when Operator is the party in default, the
applicable notices and elections can be delivered by any Non-Operator. Election
of any one or more of the following remedies shall not preclude the subsequent
use of any other remedy specified below or otherwise available to a
non-defaulting party.

1. Suspension of Rights: Any party may deliver to the party in default a Notice
of Default, which shall specify the default, specify the action to be taken to
cure the default, and specify that failure to take such action will result in
the exercise of one or more of the remedies provided in this Article. If the
default is not cured within thirty (30) days of the delivery of such Notice of
Default, all of the rights of the defaulting party granted by this agreement may
upon notice be suspended until the default is cured, without prejudice to the
right of the non-defaulting party or parties to continue to enforce the
obligations of the defaulting party previously accrued or thereafter accruing
under this agreement. If Operator is the party in default, the Non-Operators
shall have in addition the right, by vote of Non-Operators owning a majority in
interest in the Contract Area after excluding the voting interest of Operator,
to appoint a new Operator effective immediately. The rights of a defaulting
party that may be suspended hereunder at the election of the non-defaulting
parties shall include, without limitation, the right to receive information as
to any operation conducted hereunder during the period of such default, the
right to elect to participate in an operation proposed under Article VI.B. of
this agreement, the right to participate in an operation being conducted under
this agreement even if the party has previously elected to participate in such
operation, and the right to receive proceeds of production from any well subject
to this agreement.

2. Suit for Damages: Non-defaulting parties or Operator for the benefit of
non-defaulting parties may sue (at joint account expense) to collect the amounts
in default, plus interest accruing on the amounts recovered from the date of
default \until the date of collection at the rate specified in Exhibit “C”
attached hereto. Nothing herein shall prevent any party from suing any
defaulting party to collect consequential damages accruing to such party as a
result of the default.

3. Deemed Non-Consent: The non-defaulting party may deliver a written Notice of
Non-Consent Election to the defaulting party at any time after the expiration of
the thirty-day cure period following delivery of the Notice of Default, in which
event if the billing is for the drilling a new well or the Plugging Back,
Sidetracking, Reworking or Deepening of a well which is to be or has been
plugged as a dry hole, or for the Completion or Recompletion of any well, the
defaulting party will be conclusively deemed to have elected not to participate
in the operation and to be a Non-Consenting Party with respect thereto under
Article VI.B. or VI.C., as the case may be, to the extent of the costs unpaid by
such party, notwithstanding any election to participate theretofore made. If
election is made to proceed under this provision, then the non-defaulting
parties may not elect to sue for the unpaid amount pursuant to Article VII.D.2.

Until the delivery of such Notice of Non-Consent Election to the defaulting
party, such party shall have the right to cure its default by paying its unpaid
share of costs plus interest at the rate set forth in Exhibit “C,” provided,
however, such payment shall not prejudice the rights of the non-defaulting
parties to pursue remedies for damages incurred by the non- defaulting parties
as a result of the default. Any interest relinquished pursuant to this Article
VII.D.3. shall be offered to the non-defaulting parties in proportion to their
interests, and the non-defaulting parties electing to participate in the
ownership of such interest shall be required to contribute their shares of the
defaulted amount upon their election to participate therein.

4. Advance Payment: If a default is not cured within thirty (30) days of the
delivery of a Notice of Default, Operator, or Non-Operators if Operator is the
defaulting party, may thereafter require advance payment from the defaulting
party of such defaulting party’s anticipated share of any item of expense for
which Operator, or Non-Operators, as the case may be, would be entitled to
reimbursement under any provision of this agreement, whether or not such expense
was the subject of the previous default. Such right includes, but is not limited
to, the right to require advance payment for the estimated costs of drilling a
well or Completion of a well as to which an election to participate in drilling
or Completion has been made. If the defaulting party fails to pay the required
advance payment, the non-defaulting parties may pursue any of the remedies
provided in the Article VII.D. or any other default remedy provided elsewhere in
this agreement. Any excess of funds advanced remaining when the operation is
completed and all costs have been paid shall be promptly returned to the
advancing party.

 

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5. Costs and Attorneys’ Fees: In the event any party is required to bring legal
proceedings to enforce any financial obligation of a party hereunder, the
prevailing party in such action shall be entitled to recover all court costs,
costs of collection, and a reasonable attorney’s fee, which the lien provided
for herein shall also secure.

E. Rentals, Shut-in Well Payments and Minimum Royalties:

Rentals, shut-in well payments and minimum royalties which may be required under
the terms of any lease shall be paid by the Operator for the joint account of
the parties. Any party may request, and shall be entitled to receive, proper
evidence of all such payments. In the event of failure to make proper payment of
any rental, shut-in well payment or minimum royalty through mistake or oversight
where such payment is required to continue the lease in force, any loss which
results from such non-payment shall be borne in accordance with the provisions
of Article IV.B.2.

Operator shall notify Non-Operators of the anticipated completion of a shut-in
well, or the shutting in or return to production of a producing well, at least
five (5) days (excluding Saturday, Sunday, and legal holidays) prior to taking
such action, or at the earliest opportunity permitted by circumstances, but
assumes no liability for failure to do so. In the event of failure by Operator
to so notify Non-Operators, the loss of any lease contributed hereto by
Non-Operators for failure to make timely payments of any shut-in well payment
shall be borne jointly by the parties hereto under the provisions of Article
IV.B.3.

F. Taxes:

Beginning with the first calendar year after the effective date hereof, Operator
shall render for ad valorem taxation all property subject to this agreement
which by law should be rendered for such taxes, and it shall pay all such taxes
assessed thereon before they become delinquent. Prior to the rendition date,
each Non-Operator shall furnish Operator information as to burdens (to include,
but not be limited to, royalties, overriding royalties and production payments)
on Leases and Oil and Gas Interests contributed by such Non-Operator. If the
assessed valuation of any Lease is reduced by reason of its being subject to
outstanding excess royalties, overriding royalties or production payments, the
reduction in ad valorem taxes resulting therefrom shall inure to the benefit of
the owner or owners of such Lease, and Operator shall adjust the charge to such
owner or owners so as to reflect the benefit of such reduction. If the ad
valorem taxes are based in whole or in part upon separate valuations of each
party’s working interest, then notwithstanding anything to the contrary herein,
charges to the joint account shall be made and paid by the parties hereto in
accordance with the tax value generated by each party’s working interest.
Operator shall bill the other parties for their proportionate shares of all tax
payments in the manner provided in Exhibit “C.”

If Operator considers any tax assessment improper, Operator may, at its
discretion, protest within the time and manner prescribed by law, and prosecute
the protest to a final determination, unless all parties agree to abandon the
protest prior to final determination. During the pendency of administrative or
judicial proceedings, Operator may elect to pay, under protest, all such taxes
and any interest and penalty. When any such protested assessment shall have been
finally determined, Operator shall pay the tax for the joint account, together
with any interest and penalty accrued, and the total cost shall then be assessed
against the parties, and be paid by them, as provided in Exhibit “C.”

Each party shall pay or cause to be paid all production, severance, excise,
gathering and other taxes imposed upon or with respect to the production or
handling of such party’s share of Oil and Gas produced under the terms of this
agreement.

ARTICLE VIII.

ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST

A. Surrender of Leases:

The Leases covered by this agreement, insofar as they embrace acreage in the
Contract Area, shall not be surrendered in whole or in part unless all parties
consent thereto.

However, should any party desire to surrender its interest in any Lease or in
any portion thereof, such party shall give written notice of the proposed
surrender to all parties, and the parties to whom such notice is delivered shall
have thirty (30) days after delivery of the notice within which to notify the
party proposing the surrender whether they elect to consent thereto. Failure of
a party to whom such notice is delivered to reply within said 30-day period
shall constitute a consent to the surrender of the Leases described in the
notice. If all parties do not agree or consent thereto, the party desiring to
surrender shall assign, without express or implied warranty of title, all of its
interest in such Lease, or portion thereof, and any well, material and equipment
which may be located thereon and any rights in production thereafter secured, to
the parties not consenting to such surrender. If the interest of the assigning
party is or includes an Oil and Gas Interest, the assigning party shall execute
and deliver to the party or parties not consenting to such surrender an oil and
gas lease covering such Oil and Gas Interest for a term of one (1) year and so
long thereafter as Oil and/or Gas is produced from the land covered thereby.,
such lease to be on the form attached hereto as Exhibit “B.”

 

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Upon such assignment or lease, the assigning party shall be relieved from all
obligations thereafter accruing, but not theretofore accrued, with respect to
the interest assigned or leased and the operation of any well attributable
thereto, and the assigning party shall have no further interest in the assigned
or leased premises and its equipment and production. other than the royalties
retained in any lease made under the terms of this Article. The party assignee
or lessee shall pay to the party assignor or lessor the reasonable salvage value
of the latter’s interest in any well’s salvable materials and equipment
attributable to the assigned or leased acreage. The value of all salvable
materials and equipment shall be determined in accordance with the provisions of
Exhibit “C,” less the estimated cost of salvaging and the estimated cost of
plugging and abandoning and restoring the surface. If such value is less than
such costs, then the party assignor or lessor shall pay to the party assignee or
lessee the amount of such deficit. If the assignment or lease is in favor of
more than one party, the interest shall be shared by such parties in the
proportions that the interest of each bears to the total interest of all such
parties. If the interest of the parties to whom the assignment is to be made
varies according to depth, then the interest assigned shall similarly reflect
such variances.

Any assignment, lease or surrender made under this provision shall not reduce or
change the assignor’s, lessor’s or surrendering party’s interest as it was
immediately before the assignment, lease or surrender in the balance of the
Contract Area; and the acreage assigned, leased or surrendered, and subsequent
operations thereon, shall not thereafter be subject to the terms and provisions
of this agreement but shall be deemed subject to an Operating Agreement in the
form of this agreement.

B. Renewal or Extension of Leases:

If any party secures a renewal or replacement of an Oil and Gas Lease or
Interest subject to this agreement, then all other parties shall be notified
promptly upon such acquisition or, in the case of a replacement Lease taken
before expiration of an existing Lease, promptly upon expiration of the existing
Lease. The parties notified shall have the right for a period of thirty
(30) days following delivery of such notice in which to elect to participate in
the ownership of the renewal or replacement Lease, insofar as such Lease affects
lands within the Contract Area, by paying to the party who acquired it their
proportionate shares of the acquisition cost allocated to that part of such
Lease within the Contract Area, which shall be in proportion to the interest
held at that time by the parties in the Contract Area. Each party who
participates in the purchase of a renewal or replacement Lease shall be given an
assignment of its proportionate interest therein by the acquiring party. If
some, but less than all, of the parties elect to participate in the purchase of
a renewal or replacement Lease, it shall be owned by the parties who elect to
participate therein, in a ratio based upon the relationship of their respective
percentage of participation in leases described in Exhibit “A” to the aggregate
of the percentages of participation in the Contract Area of all parties
participating in the purchase of such renewal or replacement Lease. (Not
applicable to the Encana Contract Area.) The acquisition of a renewal or
replacement Lease by any or all of the parties hereto shall not cause a
readjustment of the interests of the parties stated in Exhibit “A” but any
renewal or replacement Lease in which less than all parties elect to participate
shall not be subject to this agreement but shall be deemed subject to a separate
Operating Agreement in the form of this agreement.

If the interests of the parties in the Contract Area vary according to depth,
then their right to participate proportionately in renewal or replacement Leases
and their right to receive an assignment of interest shall also reflect such
depth variances.

The provisions of this Article shall apply to renewal or replacement Leases
whether they are for the entire interest covered by the expiring Lease or cover
only a portion of its area or an interest therein. Any renewal or replacement
Lease taken before the or nominated for sale expiration of its predecessor
Lease, or taken or contracted for or becoming effective / within six (6) months
after the expiration of the existing Lease, shall be subject to this provision
so long as this agreement is in effect at the time of such acquisition or at the
time or nominated for sale the renewal or replacement Lease becomes effective;
but any Lease taken or contracted for / more than six (6) months after the
expiration of an existing Lease shall not be deemed a renewal or replacement
Lease and shall not be subject to the provisions of this agreement.

The provisions in this Article shall also be applicable to extensions of Oil and
Gas Leases.

C. Acreage or Cash Contributions:

 

While this agreement is in force, if any party contracts for a contribution of
cash towards the drilling of a well or any other operation on the Contract Area,
such contribution shall be paid to the party who conducted the drilling or other
operation and shall be applied by it against the cost of such drilling or other
operation. If the contribution be in the form of acreage, the party to whom the
contribution is made shall promptly tender an assignment of the acreage, without
warranty of title, to the Drilling Parties in the proportions said Drilling
Parties shared the cost of drilling the well. Such acreage shall become a
separate Contract Area and, to the extent possible, be governed by provisions
identical to this agreement. Each party shall promptly notify all other parties
of any acreage or cash contributions it may obtain in support of any well or any
other operation on the Contract Area. The above provisions shall also be
applicable to optional rights to earn acreage outside the Contract Area which
are in support of well drilled inside Contract Area.

D. Assignment; Maintenance of Uniform Interest:

 

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For the purpose of maintaining uniformity of ownership in the Contract Area in
the Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production
covered by this agreement no party shall sell, encumber, transfer or make other
disposition of its interest in the Oil and Gas Leases and Oil and Gas Interests
embraced within the Contract Area or in wells, equipment and production unless
such disposition covers either:

1. the entire interest of the party in all Oil and Gas Leases, Oil and Gas
Interests, wells, equipment and production; or

2. an equal undivided percent of the party’s present interest in all Oil and Gas
Leases, Oil and Gas Interests, wells, equipment and production in the Contract
Area.

Every sale, encumbrance, transfer or other disposition made by any party shall
be made expressly subject to this agreement and the BJU Carry and Earning
Agreement and shall be made without prejudice to the right of the other parties,
and any transferee of an ownership interest in any Carry and/or Head’s Up Well
shall be deemed a party to this agreement as to the interest conveyed from and
after the effective date of the transfer of ownership; provided, however, that
the other parties shall not be required to recognize any such sale, encumbrance,
transfer or other disposition for any purpose hereunder until thirty (30) days
after they have received a copy of the instrument of transfer or other
satisfactory evidence thereof in writing from the transferor or transferee. No
assignment or other disposition of an interest in a Carry and/or Head’s Up Well
by a party shall relieve such party of obligations previously incurred by such
party hereunder with respect to the interest transferred, including without
limitation the obligation of a party to pay all costs attributable to an
operation conducted hereunder in which such party has agreed to participate
prior to making such assignment, and the lien and security interest granted by
Article VII.B. shall continue to burden the interest transferred to secure
payment of any such obligations.

Every sale, encumbrance, transfer or other disposition by any party of any Carry
and/or Head’s Up Well covered by this agreement shall be made expressly subject
to this agreement and to the provisions of Exhibit G hereto, and shall be made
without prejudice to the rights of the other parties, and any transferee of any
Carry and/or Head’s Up Well shall be deemed a party to this agreement as to the
interest conveyed from and after the effective date of the transfer of
ownership; provided, however that the other parties shall not be required to
recognize any such sale, encumbrance, transfer or other disposition for any
purpose hereunder, and no such transfer shall be deemed effective for any
purpose, until thirty (30) days after the other parties have received a copy of
the instrument of transfer or other satisfactory evidence thereof from the
transferor or transferee and an executed copy of an undertaking by the
transferee to abide and be bound by the terms of this agreement and Exhibit G
hereto.

If, at any time the interest of any party is divided among and owned by two four
or more co-owners, Operator, at its discretion, may require such co-owners to
appoint a single trustee or agent with full authority to receive notices,
approve expenditures, receive billings for and approve and pay such party’s
share of the joint expenses, and to deal generally with, and with power to bind,
the co-owners of such party’s interest within the scope of the operations
embraced in this agreement and/or the BJU Carry and Earning Agreement; however,
all such co- owners shall have the right to enter into and execute all contracts
or agreements for the disposition of their respective shares of the Oil and Gas
produced from the Carry and/or Head’s Up Wells and they shall have the right to
receive, separately, payment of the sale proceeds thereof.

E. Waiver of Rights to Partition:

If permitted by the laws of the state or states in which the property covered
hereby is located, each party hereto owning an undivided interest in the
Contract Area waives any and all rights it may have to partition and have set
aside to it in severalty its undivided interest therein.

Preferential Right to Purchase: NOT APPLICABLE

ARTICLE IX.

INTERNAL REVENUE CODE ELECTION

This Agreement is not intended to create, and shall not be construed to create,
an association for profit, a trust, a joint venture, a mining partnership or
other relationship of partnership, or entity of any kind between the Parties.
Notwithstanding anything to the contrary contained herein, the Parties
understand and agree that the arrangement and undertakings evidenced by this
Agreement, taken together, result in a partnership for purposes of federal
income taxation and for purposes of certain state income tax laws which
incorporate or follow federal income tax principles as to tax partnerships. For
these purposes, the Parties agree to be governed by the tax partnership
provisions attached as Exhibit “G” which are incorporated herein and made a part
of this Agreement by this reference. For every purpose other than the
above-described income tax purposes, however, the Parties understand and agree
that the liabilities of the Parties shall be several, not joint or collective,
and that each Party shall be solely responsible for its own obligations. In the
event of any conflict or inconsistency between the terms and conditions of
Exhibit “G” and the terms and conditions of this Agreement or any attachment or
exhibit hereto (other than Exhibit “G”) the terms and conditions of Exhibit “G”
shall govern and control.

 

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ARTICLE X.

CLAIMS AND LAWSUITS

Operator may settle any single uninsured third party damage claim or suit
arising from operations hereunder if the expenditure does not exceed Fifty
Thousand Dollars ($50,000.00) and if the payment is in complete settlement of
such claim or suit. If the amount required for settlement exceeds the above
amount, the parties hereto shall assume and take over the further handling of
the claim or suit, unless such authority is delegated to Operator. All costs and
expenses of handling settling, or otherwise discharging such claim or suit shall
be a the joint expense of the parties participating in the operation from which
the claim or suit arises. If a claim is made against any party or if any party
is sued on account of any matter arising from operations hereunder over which
such individual has no control because of the rights given Operator by this
agreement, such party shall immediately notify all other parties, and the claim
or suit shall be treated as any other claim or suit involving operations
hereunder.

ARTICLE XI.

FORCE MAJEURE

29.2 If a Party is rendered unable, wholly or in part, by a force majeure event
to carry out its obligations under this Agreement, other than the obligations to
make money payments and to deliver Wellbore Assignments of interests in the
Carry and/or Head’s Up Wells, the affected Party shall give the other Party
prompt written notice describing the force majeure event in reasonable detail.
Thereupon, the obligations of the Party giving notice, so far as it is affected
by the force majeure event, shall be suspended and any time periods provided for
in this Agreement shall be extended for a period equal to the period of the
continuance of the force majeure event. The affected Party shall use all
reasonable diligence to remove the force majeure event as quickly as
practicable. The requirement that any force majeure event be remedied with all
reasonable dispatch shall not require the settlement of strikes, lockouts or
other labor difficulty by the Party affected, contrary to its wishes, and
settlement or resolution of such matters shall be within the discretion of the
affected Party. The term “force majeure event” as used herein, shall mean an act
of God, act of terrorism, strike, lockout, or other industrial disturbance, act
of the public enemy, war, blockade, public riot, lightning, fire, storm, flood,
explosion, the actions of Governmental Authority, restraint or inaction, the
interruption or suspension of the receipt or delivery of natural gas (or any of
its constituants) or water due to the inability or failure of any Third Party
who is not a party to this Agreement (other than an Affiliate of either Party
hereto), to receive or deliver such gas or water, unavailability of equipment,
inability to gain access, ingress or egress to conduct operations (including
without limitation delays in or inability to obtain permits, approvals or
clearances from governmental bodies).

ARTICLE XII.

NOTICES

All notices authorized or required between the parties by any of the provisions
of this agreement, unless otherwise specifically provided, shall be in writing
and delivered in person or by United States mail, courier service, email or
other electronic means, telecopier or any other form of facsimile, postage or
charges prepaid, and addressed to such parties at the addresses listed on
Exhibit “A.” All telephone, email or oral notices permitted by this agreement
shall be confirmed immediately thereafter by written notice. The originating
notice given under any provision hereof shall be deemed delivered only when
received by the party to whom such notice is directed, and the time for such
party to deliver any notice in response thereto shall run from the date the
originating notice is received. “Receipt” for purposes of this agreement with
respect to written notice delivered hereunder shall be actual delivery of the
notice to the address of the party to be notified specified in accordance with
this agreement, or to the telecopy, facsimile or telex machine of such party.
The second or any responsive notice shall be deemed delivered when deposited in
the United States mail or at the office of the courier or telegraph service, or
upon transmittal by telex, telecopy or facsimile, or when personally delivered
to the party to be notified, provided, that when response is required within 24
or 48 hours, such response shall be given orally or by telephone, telex,
telecopy or other facsimile within such period. Each party shall have the right
to change its address at any time, and from time to time, by giving written
notice thereof to all other parties. If a party is not available to receive
notice orally or by telephone when a party attempts to deliver a notice required
to be delivered within 24 or 48 hours, the notice may be delivered in writing by
any other method specified herein and shall be deemed delivered in the same
manner provided above for any responsive notice.

ARTICLE XIII.

TERM OF AGREEMENT

This agreement shall remain in full force and effect until one year after there
are no longer any producing Carry and/or Head’s Up Wells in which Nucor or its
successors or assigns holds an interest, or until all Carry and/or Head’s Up
Wells have been plugged and abandoned, whichever is later.

 

     Option No. 1: So long as any of the lands and associated Oil and Gas Leases
and Oil and Gas Interests subject to this agreement remain or are continued in
force as to any part of the Contract Area, whether by production, extension,
renewal or otherwise.

 

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¨ Option No. 2: In the event the well described in Article VI.A., or any
subsequent well drilled under any provision of this agreement, results in the
Completion of a well as a well capable of production of Oil and/or Gas in paying
quantities, this agreement shall continue in force so long as any such well is
capable of production, and for an additional period of              days
thereafter; provided, however, if, prior to the expiration of such additional
period, one or more of the parties hereto are engaged in drilling, Reworking,
Deepening, Sidetracking, Plugging Back, testing or attempting to Complete or
Re-complete a well or wells hereunder, this agreement shall continue in force
until such operations have been completed and if production results therefrom,
this agreement shall continue in force as provided herein. In the event the well
described in Article VI.A., or any subsequent well drilled hereunder, results in
a dry hole, and no other well is capable of producing Oil and/or Gas from the
Contract Area, this agreement shall terminate unless drilling, Deepening,
Sidetracking, Completing, Re- completing, Plugging Back or Reworking operations
are commenced within              days from the date of abandonment of said
well. “Abandonment” for such purposes shall mean either (i) a decision by all
parties not to conduct any further operations on the well or (ii) the elapse of
180 days from the conduct of any operations on the well, whichever first occurs.

The termination of this agreement shall not relieve any party hereto from any
expense, liability or other obligation or any remedy therefor which has accrued
or attached prior to the date of such termination.

Upon termination of this agreement and the satisfaction of all obligations
hereunder, in the event a memorandum of this Operating Agreement has been filed
of record, Operator is authorized to file of record in all necessary recording
offices a notice of termination, and each party hereto agrees to execute such a
notice of termination as to Operator’s interest, upon request of Operator, if
Operator has satisfied all its financial obligations.

ARTICLE XIV.

COMPLIANCE WITH LAWS AND REGULATIONS

A. Laws, Regulations and Orders:

This agreement shall be subject to the applicable laws of the state in which the
Contract Area is located, to the valid rules, regulations, and orders of any
duly constituted regulatory body of said state; and to all other applicable
federal, state, and local laws, ordinances, rules, regulations and orders.

B. Governing Law:

This agreement and all matters pertaining hereto, including but not limited to
matters of performance, non- performance, breach, remedies, procedures, rights,
duties, and interpretation or construction, shall be governed and determined by
the law of the state in which the Contract Area is located. If the Contract Area
is in two or more states, the law of the state of                          shall
govern.

C. Regulatory Agencies:

Nothing herein contained shall grant, or be construed to grant, Operator the
right or authority to waive or release any rights, privileges, or obligations
which Non-Operators may have under federal or state laws or under rules,
regulations or orders promulgated under such laws in reference to oil, gas and
mineral operations, including the location, operation, or production of wells,
on tracts offsetting or adjacent to the Contract Area.

With respect to the operations hereunder, Non-Operators agree to release
Operator from any and all losses, damages, injuries, claims and causes of action
arising out of, incident to or resulting directly or indirectly from Operator’s
interpretation or application of rules, rulings, regulations or orders of the
Department of Energy or Federal Energy Regulatory Commission or predecessor or
successor agencies to the extent such interpretation or application was made in
good faith and does not constitute gross negligence. Each Non-Operator further
agrees to reimburse Operator for such Non-Operator’s share of production or any
refund, fine, levy or other governmental sanction that Operator may be required
to pay as a result of such an incorrect interpretation or application, together
with interest and penalties thereon owing by Operator as a result of such
incorrect interpretation or application.

ARTICLE XV.

MISCELLANEOUS

A. Execution:

This agreement shall be binding upon each Non-Operator when this agreement or a
counterpart thereof has been executed by such Non-Operator and Operator
notwithstanding that this agreement is not then or thereafter executed by all of
the parties to which it is tendered or which are listed on Exhibit “A” as owning
an interest in the Contract Area or which own, in fact, an interest in the
Contract Area.

 

23

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

B. Successors and Assigns:

This agreement shall be binding upon and shall inure to the benefit of the
parties hereto and their respective heirs, devisees, legal representatives,
successors and assigns, and the terms hereof shall be deemed to run with the
Interests in the Carry and/or Head’s Up Wells included within the Contract Area.

C. Counterparts:

This instrument may be executed in any number of counterparts, each of which
shall be considered an original for all purposes.

D. Severability:

For the purposes of assuming or rejecting this agreement as an executory
contract pursuant to federal bankruptcy laws, this agreement shall not be
severable, but rather must be assumed or rejected in its entirety, and the
failure of any party to this agreement to comply with all of its financial
obligations provided herein shall be a material default.

ARTICLE XVI.

OTHER PROVISIONS

SEE PAGES 20-22 FOR OTHER PROVISIONS.

IN WITNESS WHEREOF, this agreement shall be effective as of the 1st day of
November, 2012.

 

ATTEST OR WITNESS:    

ENCANA OIL & GAS (USA) INC.

OPERATOR

      By             Ricardo D. Gallegos             VP, Bus. Dev. –
Negotiations         & Lead Rockies & Intl. Land       Date    

 

ATTEST OR WITNESS:    

NUCOR ENERGY HOLDINGS INC.

NON-OPERATOR

      By             Joseph Strateman             President       Date    

 

Acknowledgment in representative capacity:

State of Colorado                     )

                                                 ) ss.

 

24

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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989

 

City and County of Denver )

This instrument was acknowledged before me on                         , 2012 by
Ricardo D. Gallegos, VP, Bus. Dev. – Negotiations & Lead Rockies & Intl. Land of
Encana Oil & Gas (USA) Inc.

 

(Seal, if any)               Notary Public      
My commission expires:                        
                                   

Acknowledgment in representative capacity:

State of                                    )

                                                 ) ss.

County of                                 )

This instrument was acknowledged before me on                         , 2012 by
Joe Stratman, President of Nucor Energy Holdings Inc.

 

(Seal, if any)               Notary Public      
My commission expires:                        
                                   

 

25

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EXHIBIT A

Attached to and made a part of that certain Operating Agreement executed
October 31, 2012 but effective as of November 1, 2012 by and between Encana Oil
&Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

I.   DESCRIPTION OF LANDS SUBJECT TO THIS AGREEMENT

The Lands subject to this Agreement are set out on the attached plat (Exhibit
A-1), pursuant to the BJU Carry and Earning Agreement dated effective
November 1, 2012 between the Parties.

 

II.   RESTRICTIONS AS TO DEPTHS, FORMATIONS, PREVIOUSLY EXISTING WELLS AND
SUBSTANCES

Wellbore interest only in Carry Wells and/or Head’s Up Wells designated and
drilled pursuant to the BJU Carry and Earning Agreement executed October 31,
2012 but effective November 1, 2012 between the Parties. All interests are
limited in depth to the depth drilled in the applicable well, but not below the
base of the Formation as defined in the BJU Carry and Earning Agreement, subject
to Section 2.1 I of such agreement.

 

III.   PARTIES TO THE AGREEMENT AND PERCENTAGE PARTICIPATION

A. Drilling costs, Completion costs, and Equipping costs for Carry Wells shall
be borne as set forth in the BJU Carry and Earning Agreement executed
October 31, 2012 but dated effective November 1, 2012 between the Parties as
follows:

 

     Cost Share   WI Share

Encana Oil & Gas (USA) Inc.

       [ ***]%       50.00 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

Nucor Energy Holdings Inc.

       [ ***]%       50.00 %

1915 Rexford Road

        

Charlotte, NC 28211

        

Working Interest ownership in Carry Wells after Drilling, Completing and
Equipping:

 

     Cost Share   WI Share

Encana Oil & Gas (USA) Inc.

       50.00 %       50.00 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

Nucor Energy Holdings Inc.

       50.00 %       50.00 %

1915 Rexford Road

        

Charlotte, NC 28211

        

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

--------------------------------------------------------------------------------

B. Drilling Costs, Completion Costs and Equipping Costs for Head’s Up Wells in
which all Parties elect to participate shall be borne as set forth in the BJU
Carry and Earning Agreement executed October 31, 2012 but dated effective
November 1, 2012 between the Parties as follows:

 

     Cost Share   WI Share

Encana Oil & Gas (USA) Inc.

       50.00 %       50.00 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

Nucor Energy Holdings Inc.

       50.00 %       50.00 %

1915 Rexford Road

        

Charlotte, NC 28211

        

Working Interest Ownership in Head’s-Up Well in which all Parties elect to
participate after Drilling, Completing and Equipping:

 

     Cost Share   WI Share

Encana Oil & Gas (USA) Inc.

       50.00 %       50.00 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

Nucor Energy Holdings Inc.

       50.00 %       50.00 %

1915 Rexford Road

        

Charlotte, NC 28211

        

C. Drilling Costs, Completion Costs and Equipping Costs for Head’s Up Wells in
which Nucor elects not to participate shall be borne as set forth in the BJU
Carry and Earning Agreement executed October 31, 2012 but dated effective
November 1, 2012 between the Parties as follows:

 

     Cost Share   WI Share

Encana Oil & Gas (USA) Inc.

       100.00 %       100.00 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

Nucor Energy Holdings Inc.

       0.00 %       0.00 %

1915 Rexford Road

        

Charlotte, NC 28211

        

Working Interest Ownership in Head’s-Up Wells in which Nucor elects not to
participate after Drilling, Completing and Equipping:

 

     Cost Share   WI Share

Encana Oil & Gas (USA) Inc.

       100.00 %       100.00 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

Nucor Energy Holdings Inc.

       0.00 %       0.00 %

1915 Rexford Road

        

Charlotte, NC 28211

        

 

2

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D. Drilling Costs, Completion Costs and Equipping Costs for Head’s Up Wells in
which Encana elects not to participate shall be borne as set forth in the BJU
Carry and Earning Agreement executed October 31, 2012 but dated effective
November 1, 2012 between the Parties as follows:

 

     Cost Share   WI Share

Nucor Energy Holdings Inc.

       100.00 %       97.5 %

1915 Rexford Road

        

Charlotte, NC 28211

        

Encana Oil & Gas (USA) Inc.

       0.00 %       2.5 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

Working Interest Ownership in a Head’s-Up Well in which Encana elects not to
participate after Drilling, Completing and Equipping:

 

     Cost Share   WI Share

Nucor Energy Holdings Inc.

       97.5 %       97.5 %

1915 Rexford Road

        

Charlotte, NC 28211

        

Encana Oil & Gas (USA) Inc.

       2.5 %       2.5 %

370 17th Street, Suite 1700

        

Denver, Colorado 80202

        

 

IV.   LEASES, LANDS AND AGREEMENTS SUBJECT TO THIS AGREEMENT

See I. above

 

V.   NOTICE ADDRESSES FOR THE PARTIES

Encana Oil & Gas (USA) Inc.

370 17th Street, Suite 1700

Denver, Colorado 80202

Phone: 303-623-2300

Fax: 303-623-2400

Attention: Team Lead Land, South Rockies Business Unit

Nucor Energy Holdings Inc.

1915 Rexford Road

Charlotte, NC 28211

Phone: 704-365-1921

Fax: 704-362-4208

Attention: Chief Financial Officer

 

3

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EXHIBIT B

(Lease Form)

Attached to and made a part of that certain Operating Agreement executed
October 31, 2012 but effective as of November 1, 2012 by and between Encana Oil
&Gas (USA) Inc. and Nucor Energy Holdings Inc.

There is no Exhibit B to this Agreement.

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COPAS 2005 Accounting Procedure

Recommended by COPAS, Inc.

EXHIBIT C

ACCOUNTING PROCEDURE

JOINT OPERATIONS

Attached to and made part of that certain Operating Agreement executed
October 31, 2012 but effective November 1, 2012 , by and between Encana Oil &
Gas (USA) Inc and Nucor Energy Holdings Inc..

I. GENERAL PROVISIONS

IF THE PARTIES FAIL TO SELECT EITHER ONE OF COMPETING “ALTERNATIVE” PROVISIONS,
OR SELECT ALL THE COMPETING “ALTERNATIVE” PROVISIONS, ALTERNATIVE 1 IN EACH SUCH
INSTANCE SHALL BE DEEMED TO HAVE BEEN ADOPTED BY THE PARTIES AS A RESULT OF ANY
SUCH OMISSION OR DUPLICATE NOTATION.

IN THE EVENT THAT ANY “OPTIONAL” PROVISION OF THIS ACCOUNTING PROCEDURE IS NOT
ADOPTED BY THE PARTIES TO THE AGREEMENT BY A TYPED, PRINTED OR HANDWRITTEN
INDICATION, SUCH PROVISION SHALL NOT FORM A PART OF THIS ACCOUNTING PROCEDURE,
AND NO INFERENCE SHALL BE MADE CONCERNING THE INTENT OF THE PARTIES IN SUCH
EVENT.

 

1.   DEFINITIONS

All terms used in this Accounting Procedure shall have the following meaning,
unless otherwise expressly defined in the Agreement:

“Affiliate” means for a person, another person that controls, is controlled by,
or is under common control with that person. In this definition, (a) control
means the ownership by one person, directly or indirectly, of more than fifty
percent (50%) of the voting securities of a corporation or, for other persons,
the equivalent ownership interest (such as partnership interests), and
(b) “person” means an individual, corporation, partnership, trust, estate,
unincorporated organization, association, or other legal entity.

“Agreement” means the operating agreement, farmout agreement, or other contract
between the Parties to which this Accounting Procedure is attached.

“Controllable Material” means Material that, at the time of acquisition or
disposition by the Joint Account, as applicable, is so classified in the
Material Classification Manual most recently recommended by the Council of
Petroleum Accountants Societies (COPAS).

“Equalized Freight” means the procedure of charging transportation cost to the
Joint Account based upon the distance from the nearest Railway Receiving Point
to the property.

“Excluded Amount” means a specified excluded trucking amount most recently
recommended by COPAS.

“Field Office” means a structure, or portion of a structure, whether a temporary
or permanent installation, the primary function of which is to directly serve
daily operation and maintenance activities of the Joint Property and which
serves as a staging area for directly chargeable field personnel.

“First Level Supervision” means those employees whose primary function in Joint
Operations is the direct oversight of the Operator’s field employees and/or
contract labor directly employed On-site in a field operating capacity. First
Level Supervision functions may include, but are not limited to:

 

  •  

Responsibility for field employees and contract labor engaged in activities that
can include field operations, maintenance, construction, well remedial work,
equipment movement and drilling

 

  •  

Responsibility for day-to-day direct oversight of rig operations

 

  •  

Responsibility for day-to-day direct oversight of construction operations

 

  •  

Coordination of job priorities and approval of work procedures

 

  •  

Responsibility for optimal resource utilization (equipment, Materials,
personnel)

 

  •  

Responsibility for meeting production and field operating expense targets

 

  •  

Representation of the Parties in local matters involving community, vendors,
regulatory agents and landowners, as an incidental part of the supervisor’s
operating responsibilities

 

  •  

Responsibility for all emergency responses with field staff

 

  •  

Responsibility for implementing safety and environmental practices

 

  •  

Responsibility for field adherence to company policy

 

  •  

Responsibility for employment decisions and performance appraisals for field
personnel

 

  •  

Oversight of sub-groups for field functions such as electrical, safety,
environmental, telecommunications, which may have group or team leaders.

“Joint Account” means the account showing the charges paid and credits received
in the conduct of the Joint Operations that are to be shared by the Parties, but
does not include proceeds attributable to hydrocarbons and by-products produced
under the Agreement.

“Joint Operations” means all operations necessary or proper for the exploration,
appraisal, development, production, protection, maintenance, repair,
abandonment, and restoration of the Joint Property.

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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COPAS 2005 Accounting Procedure

Recommended by COPAS, Inc.

 

“Joint Property” means the real and personal property subject to the Agreement.

“Laws” means any laws, rules, regulations, decrees, and orders of the United
States of America or any state thereof and all other

governmental bodies, agencies, and other authorities having jurisdiction over or
affecting the provisions contained in or the transactions contemplated by the
Agreement or the Parties and their operations, whether such laws now exist or
are hereafter amended, enacted, promulgated or issued.

“Material” means personal property, equipment, supplies, or consumables acquired
or held for use by the Joint Property.

“Non-Operators” means the Parties to the Agreement other than the Operator.

“Offshore Facilities” means platforms, surface and subsea development and
production systems, and other support systems such as oil and gas handling
facilities, living quarters, offices, shops, cranes, electrical supply equipment
and systems, fuel and water storage and piping, heliport, marine docking
installations, communication facilities, navigation aids, and other similar
facilities necessary in the conduct of offshore operations, all of which are
located offshore.

“Off-site” means any location that is not considered On-site as defined in this
Accounting Procedure.

“On-site” means on the Joint Property when in direct conduct of Joint
Operations. The term “On-site” shall also include that portion of Offshore
Facilities, Shore Base Facilities, fabrication yards, and staging areas from
which Joint Operations are conducted, or other facilities that directly control
equipment on the Joint Property, regardless of whether such facilities are owned
by the Joint Account.

“Operator” means the Party designated pursuant to the Agreement to conduct the
Joint Operations.

“Parties” means legal entities signatory to the Agreement or their successors
and assigns. Parties shall be referred to individually as “Party.”

“Participating Interest” means the percentage of the costs and risks of
conducting an operation under the Agreement that a Party agrees, or is otherwise
obligated, to pay and bear.

“Participating Party” means a Party that approves a proposed operation or
otherwise agrees, or becomes liable, to pay and bear a share of the costs and
risks of conducting an operation under the Agreement.

“Personal Expenses” means reimbursed costs for travel and temporary living
expenses.

“Railway Receiving Point” means the railhead nearest the Joint Property for
which freight rates are published, even though an actual railhead may not exist.

“Shore Base Facilities” means onshore support facilities that during Joint
Operations provide such services to the Joint Property as a receiving and
transshipment point for Materials; debarkation point for drilling and production
personnel and services; communication, scheduling and dispatching center; and
other associated functions serving the Joint Property.

“Supply Store” means a recognized source or common stock point for a given
Material item.

“Technical Services” means services providing specific engineering, geoscience,
or other professional skills, such as those performed by engineers, geologists,
geophysicists, and technicians, required to handle specific operating conditions
and problems for the benefit of Joint Operations; provided, however, Technical
Services shall not include those functions specifically identified as overhead
under the second paragraph of the introduction of Section III (Overhead).
Technical Services may be provided by the Operator, Operator’s Affiliate,
Non-Operator, Non-Operator Affiliates, and/or third parties.

 

2.   STATEMENTS AND BILLINGS

The Operator shall bill Non-Operators on or before the last day of the month for
their proportionate share of the Joint Account for the preceding month. Such
bills shall be accompanied by statements that identify the AFE (authority for
expenditure), lease or facility, and all charges and credits summarized by
appropriate categories of investment and expense. Controllable Material shall be
separately identified and fully described in detail, or at the Operator’s
option, Controllable Material may be summarized by major Material
classifications. Intangible drilling costs, audit adjustments, and unusual
charges and credits shall be separately and clearly identified.

The Operator may make available to Non-Operators any statements and bills
required under Section I.2 and/or Section I.3.A (Advances and Payments by the
Parties) via email, electronic data interchange, internet websites or other
equivalent electronic media in lieu of paper copies. The Operator shall provide
the Non-Operators instructions and any necessary information to access and
receive the statements and bills within the timeframes specified herein. A
statement or billing shall be deemed as delivered twenty-four (24) hours
(exclusive of weekends and holidays) after the Operator notifies the
Non-Operator that the statement or billing is available on the website and/or
sent via email or electronic data interchange transmission. Each Non-Operator
individually shall elect to receive statements and billings electronically, if
available from the Operator, or request paper copies. Such election may be
changed upon thirty (30) days prior written notice to the Operator.

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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COPAS 2005 Accounting Procedure

Recommended by COPAS, Inc.

 

3.   ADVANCES AND PAYMENTS BY THE PARTIES

 

  A. Unless otherwise provided for in the Agreement, the Operator may require
the Non-Operators to advance their share of the estimated cash outlay for the
succeeding month’s operations within fifteen (15) days after receipt of the
advance request. The Operator shall adjust each monthly billing to reflect
advances received from the Non-Operators for such month. If a refund is due, the
Operator shall apply the amount to be refunded to the subsequent month’s billing
or advance, unless the Non-Operator sends the Operator a written request for a
cash refund. The Operator shall remit the refund to the Non-Operator within
fifteen (15) days of receipt of such written request.

 

  B. Except as provided below, each Party shall pay its proportionate share of
all bills in full within fifteen (15) days of receipt date. If payment is not
made or a credit is not applied within such time, the unpaid balance shall bear
interest compounded monthly at the prime rate published by the Wall Street
Journal on the first day of each month the payment is delinquent, plus three
percent (3%), per annum, or the maximum contract rate permitted by the
applicable usury Laws governing the Joint Property, whichever is the lesser,
plus attorney’s fees, court costs, and other costs in connection with the
collection of unpaid amounts. If the Wall Street Journal ceases to be published
or discontinues publishing a prime rate, the unpaid balance shall bear interest
compounded monthly at the prime rate published by the Federal Reserve plus three
percent (3%), per annum. Interest shall begin accruing on the first day of the
month in which the payment was due. Payment shall not be reduced or delayed as a
result of inquiries or anticipated credits unless the Operator has agreed.
Notwithstanding the foregoing, the Non-Operator may reduce payment, provided it
furnishes documentation and explanation to the Operator at the time payment is
made, to the extent such reduction is caused by:

 

  (1) being billed at an incorrect working interest or Participating Interest
that is higher than such Non-Operator’s actual working interest or Participating
Interest, as applicable; or

 

  (2) being billed for a project or AFE requiring approval of the Parties under
the Agreement that the Non-Operator has not approved or is not otherwise
obligated to pay under the Agreement; or

 

  (3) being billed for a property in which the Non-Operator no longer owns a
working interest, provided the Non-Operator has furnished the Operator a copy of
the recorded assignment or letter in-lieu. Notwithstanding the foregoing, the
Non-Operator shall remain responsible for paying bills attributable to the
interest it sold or transferred for any bills rendered during the thirty (30)
day period following the Operator’s receipt of such written notice; or

 

  (4) charges outside the adjustment period, as provided in Section I.4
(Adjustments).

 

4.   ADJUSTMENTS

 

  A. Payment of any such bills shall not prejudice the right of any Party to
protest or question the correctness thereof; however, all bills and statements,
including payout statements, rendered during any calendar year shall
conclusively be presumed to be true and correct, with respect only to
expenditures, after twenty-four (24) months following the end of any such
calendar year, unless within said period a Party takes specific detailed written
exception thereto making a claim for adjustment. The Operator shall provide a
response to all written exceptions, whether or not contained in an audit report,
within the time periods prescribed in Section I.5 (Expenditure Audits).

 

  B. All adjustments initiated by the Operator, except those described in items
(1) through (4) of this Section I.4.B, are limited to the twenty-four (24) month
period following the end of the calendar year in which the original charge
appeared or should have appeared on the Operator’s Joint Account statement or
payout statement. Adjustments that may be made beyond the twenty-four (24) month
period are limited to adjustments resulting from the following:

 

  (1) a physical inventory of Controllable Material as provided for in Section V
(Inventories of Controllable Material), or

 

  (2) an offsetting entry (whether in whole or in part) that is the direct
result of a specific joint interest audit exception granted by the Operator
relating to another property, or

 

  (3) a government/regulatory audit, or

 

  (4) a working interest ownership or Participating Interest adjustment.

 

5.   EXPENDITURE AUDITS

 

  A. A Non-Operator, upon written notice to the Operator and all other
Non-Operators, shall have the right to audit the Operator’s accounts and records
relating to the Joint Account or the Carry and Earning Agreement within the
twenty-four (24) month period following the end of such calendar year in which
such bill was rendered; however, conducting an audit shall not extend the time
for the taking of written exception to and the adjustment of accounts as
provided for in Section I.4 (Adjustments). Any Party that is subject to payout
accounting under the Agreement shall have the right to audit the accounts and
records of the Party responsible for preparing the payout statements, or of the
Party furnishing information to the Party responsible for preparing payout
statements. Audits of payout accounts may include the volumes of hydrocarbons
produced and saved and proceeds received for such hydrocarbons as they pertain
to payout accounting required under the Agreement. Unless otherwise provided in
the Agreement, audits of a payout account shall be conducted within the
twenty-four (24) month period following the end of the calendar year in which
the payout statement was rendered.

Where there are two or more Non-Operators, the Non-Operators shall make every
reasonable effort to conduct a joint audit in a manner that will result in a
minimum of inconvenience to the Operator. The Operator shall bear no portion of
the Non-Operators’ audit cost incurred under this paragraph unless agreed to by
the Operator. The audits shall not be conducted more than once each year without
prior approval of the Operator, except upon the resignation or removal of the
Operator, and shall be made at the expense of those Non-Operators approving such
audit.

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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COPAS 2005 Accounting Procedure

Recommended by COPAS, Inc.

 

The Non-Operator leading the audit (hereinafter “lead audit company”) shall
issue the audit report within ninety (90) days after completion of the audit
testing and analysis; however, the ninety (90) day time period shall not extend
the twenty-four (24) month requirement for taking specific detailed written
exception as required in Section I.4.A (Adjustments) above. All claims shall be
supported with sufficient documentation.

A timely filed written exception or audit report containing written exceptions
(hereinafter “written exceptions”) shall, with respect to the claims made
therein, preclude the Operator from asserting a statute of limitations defense
against such claims, and the Operator hereby waives its right to assert any
statute of limitations defense against such claims for so long as any
Non-Operator continues to comply with the deadlines for resolving exceptions
provided in this Accounting Procedure. If the Non-Operators fail to comply with
the additional deadlines in Section I.5.B or I.5.C, the Operator’s waiver of its
rights to assert a statute of limitations defense against the claims brought by
the Non-Operators shall lapse, and such claims shall then be subject to the
applicable statute of limitations, provided that such waiver shall not lapse in
the event that the Operator has failed to comply with the deadlines in Section
I.5.B or I.5.C.

 

  B. The Operator shall provide a written response to all exceptions in an audit
report within one hundred eighty (180) days after Operator receives such report.
Denied exceptions should be accompanied by a substantive response. If the
Operator fails to provide substantive response to an exception within this one
hundred eighty (180) day period, the Operator will owe interest on that
exception or portion thereof, if ultimately granted, from the date it received
the audit report. Interest shall be calculated using the rate set forth in
Section I.3.B (Advances and Payments by the Parties).

 

  C. The lead audit company shall reply to the Operator’s response to an audit
report within ninety (90) days of receipt, and the Operator shall reply to the
lead audit company’s follow-up response within ninety (90) days of receipt;
provided, however, each Non-Operator shall have the right to represent itself if
it disagrees with the lead audit company’s position or believes the lead audit
company is not adequately fulfilling its duties. Unless otherwise provided for
in Section I.5.E, if the Operator fails to provide substantive response to an
exception within this ninety (90) day period, the Operator will owe interest on
that exception or portion thereof, if ultimately granted, from the date it
received the audit report. Interest shall be calculated using the rate set forth
in Section I.3.B (Advances and Payments by the Parties).

 

  D. If any Party fails to meet the deadlines in Sections I.5.B or I.5.C or if
any audit issues are outstanding fifteen (15) months after Operator receives the
audit report, the Operator or any Non-Operator participating in the audit has
the right to call a resolution meeting, as set forth in this Section I.5.D or it
may invoke the dispute resolution procedures included in the Agreement, if
applicable. The meeting will require one month’s written notice to the Operator
and all Non-Operators participating in the audit. The meeting shall be held at
the Operator’s office or mutually agreed location, and shall be attended by
representatives of the Parties with authority to resolve such outstanding
issues. Any Party who fails to attend the resolution meeting shall be bound by
any resolution reached at the meeting. The lead audit company will make good
faith efforts to coordinate the response and positions of the Non-Operator
participants throughout the resolution process; however, each Non-Operator shall
have the right to represent itself. Attendees will make good faith efforts to
resolve outstanding issues, and each Party will be required to present
substantive information supporting its position. A resolution meeting may be
held as often as agreed to by the Parties. Issues unresolved at one meeting may
be discussed at subsequent meetings until each such issue is resolved.

If the Agreement contains no dispute resolution procedures and the audit issues
cannot be resolved by negotiation, the dispute shall be submitted to mediation.
In such event, promptly following one Party’s written request for mediation, the
Parties to the dispute shall choose a mutually acceptable mediator and share the
costs of mediation services equally. The Parties shall each have present at the
mediation at least one individual who has the authority to settle the dispute.
The Parties shall make reasonable efforts to ensure that the mediation commences
within sixty (60) days of the date of the mediation request. Notwithstanding the
above, any Party may file a lawsuit or complaint (1) if the Parties are unable
after reasonable efforts, to commence mediation within sixty (60) days of the
date of the mediation request, (2) for statute of limitations reasons, or (3) to
seek a preliminary injunction or other provisional judicial relief, if in its
sole judgment an injunction or other provisional relief is necessary to avoid
irreparable damage or to preserve the status quo. Despite such action, the
Parties shall continue to try to resolve the dispute by mediation.

 

  E. ¨ (Optional Provision – Forfeiture Penalties)

If the Non-Operators fail to meet the deadline in Section I.5.C, any unresolved
exceptions that were not addressed by the Non- Operators within one (1) year
following receipt of the last substantive response of the Operator shall be
deemed to have been withdrawn by the Non-Operators. If the Operator fails to
meet the deadlines in Section I.5.B or I.5.C, any unresolved exceptions that
were not addressed by the Operator within one (1) year following receipt of the
audit report or receipt of the last substantive response of the Non-Operators,
whichever is later, shall be deemed to have been granted by the Operator and
adjustments shall be made, without interest, to the Joint Account.

 

6.   APPROVAL BY PARTIES

 

  A. GENERAL MATTERS

Where an approval or other agreement of the Parties or Non-Operators is
expressly required under other Sections of this Accounting Procedure and if the
Agreement to which this Accounting Procedure is attached contains no contrary
provisions in regard thereto, the Operator shall notify all Non-Operators of the
Operator’s proposal and the agreement or approval of a majority in interest of
the Non-Operators shall be controlling on all Non-Operators.

 

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This Section I.6.A applies to specific situations of limited duration where a
Party proposes to change the accounting for charges from that prescribed in this
Accounting Procedure. This provision does not apply to amendments to this
Accounting Procedure, which are covered by Section I.6.B.

 

  B. AMENDMENTS

If the Agreement to which this Accounting Procedure is attached contains no
contrary provisions in regard thereto, this Accounting Procedure can be amended
by an affirmative vote of ALL (         ) or more Parties, one of which is the
Operator, having a combined working interest of at least 100 percent ( 100%),
which approval shall be binding on all Parties, provided, however, approval of
at least one (1) Non-Operator shall be required.

 

  C. AFFILIATES

For the purpose of administering the voting procedures of Sections I.6.A and
I.6.B, if Parties to this Agreement are Affiliates of each other, then such
Affiliates shall be combined and treated as a single Party having the combined
working interest or Participating Interest of such Affiliates.

For the purposes of administering the voting procedures in Section I.6.A, if a
Non-Operator is an Affiliate of the Operator, votes under Section I.6.A shall
require the majority in interest of the Non-Operator(s) after excluding the
interest of the Operator’s Affiliate.

II. DIRECT CHARGES

The Operator shall charge the Joint Account with the following items, to the
extent that a reasonable and prudent operator would typically charge such items
to the Joing Account:

 

1.   RENTALS AND ROYALTIES

Lease rentals and royalties paid by the Operator, on behalf of all Parties, for
the Joint Operations.

 

2.   LABOR

 

  A. Salaries and wages, including incentive compensation programs as set forth
in COPAS MFI-37 (“Chargeability of Incentive Compensation Programs”), for:

 

  (1) Operator’s field employees directly employed On-site in the conduct of
Joint Operations,

 

  (2) Operator’s employees directly employed on Shore Base Facilities, Offshore
Facilities, or other facilities serving the Joint Property if such costs are not
charged under Section II.6 (Equipment and Facilities Furnished by Operator) or
are not a function covered under Section III (Overhead),

 

  (3) Operator’s employees providing First Level Supervision,

 

  (4) Operator’s employees providing On-site Technical Services for the Joint
Property if such charges are excluded from the overhead rates in Section III
(Overhead),

 

  (5) Operator’s employees providing Off-site Technical Services for the Joint
Property if such charges are excluded from the overhead rates in Section III
(Overhead).

Charges for the Operator’s employees identified in Section II.2.A may be made
based on the employee’s actual salaries and wages, or in lieu thereof, a day
rate representing the Operator’s average salaries and wages of the employee’s
specific job category.

Charges for personnel chargeable under this Section II.2.A who are foreign
nationals shall not exceed comparable compensation paid to an equivalent U.S.
employee pursuant to this Section II.2, unless otherwise approved by the Parties
pursuant to Section I.6.A (General Matters).

 

  B. Operator’s cost of holiday, vacation, sickness, and disability benefits,
and other customary allowances paid to employees whose salaries and wages are
chargeable to the Joint Account under Section II.2.A, excluding severance
payments or other termination allowances. Such costs under this Section II.2.B
may be charged on a “when and as-paid basis” or by “percentage assessment” on
the amount of salaries and wages chargeable to the Joint Account under Section
II.2.A. If percentage assessment is used, the rate shall be based on the
Operator’s cost experience.

 

  C. Expenditures or contributions made pursuant to assessments imposed by
governmental authority that are applicable to costs chargeable to the Joint
Account under Sections II.2.A and B.

 

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  D. Personal Expenses of personnel whose salaries and wages are chargeable to
the Joint Account under Section II.2.A when the expenses are incurred in
connection with directly chargeable activities.

 

  E. Reasonable relocation costs incurred in transferring to the Joint Property
personnel whose salaries and wages are chargeable to the Joint Account under
Section II.2.A. Notwithstanding the foregoing, relocation costs that result from
reorganization or merger of a Party, or that are for the primary benefit of the
Operator, shall not be chargeable to the Joint Account. Extraordinary relocation
costs, such as those incurred as a result of transfers from remote locations,
such as Alaska or overseas, shall not be charged to the Joint Account unless
approved by the Parties pursuant to Section I.6.A (General Matters).

 

  F. Training costs as specified in COPAS MFI-35 (“Charging of Training Costs to
the Joint Account”) for personnel whose salaries and wages are chargeable under
Section II.2.A. This training charge shall include the wages, salaries, training
course cost, and Personal Expenses incurred during the training session. The
training cost shall be charged or allocated to the property or properties
directly benefiting from the training. The cost of the training course shall not
exceed prevailing commercial rates, where such rates are available.

 

  G. Operator’s current cost of established plans for employee benefits, as
described in COPAS MFI-27 (“Employee Benefits Chargeable to Joint Operations and
Subject to Percentage Limitation”), applicable to the Operator’s labor costs
chargeable to the Joint Account under Sections II.2.A and B based on the
Operator’s actual cost not to exceed the employee benefits limitation percentage
most recently recommended by COPAS.

 

  H. Award payments to employees, in accordance with COPAS MFI-49 (“Awards to
Employees and Contractors”) for personnel whose salaries and wages are
chargeable under Section II.2.A.

 

3.   MATERIAL

Material purchased or furnished by the Operator for use on the Joint Property in
the conduct of Joint Operations as provided under Section IV (Material
Purchases, Transfers, and Dispositions). Only such Material shall be purchased
for or transferred to the Joint Property as may be required for immediate use or
is reasonably practical and consistent with efficient and economical operations.
The accumulation of surplus stocks shall be avoided.

 

4.   TRANSPORTATION

 

  A. Transportation of the Operator’s, Operator’s Affiliate’s, or contractor’s
personnel necessary for Joint Operations.

 

  B. Transportation of Material between the Joint Property and another property,
or from the Operator’s warehouse or other storage point to the Joint Property,
shall be charged to the receiving property using one of the methods listed
below. Transportation of Material from the Joint Property to the Operator’s
warehouse or other storage point shall be paid for by the Joint Property using
one of the methods listed below:

 

  (1) If the actual trucking charge is less than or equal to the Excluded Amount
the Operator may charge actual trucking cost or a theoretical charge from the
Railway Receiving Point to the Joint Property. The basis for the theoretical
charge is the per hundred weight charge plus fuel surcharges from the Railway
Receiving Point to the Joint Property. The Operator shall consistently apply the
selected alternative.

 

  (2) If the actual trucking charge is greater than the Excluded Amount, the
Operator shall charge Equalized Freight. Accessorial charges such as loading and
unloading costs, split pick-up costs, detention, call out charges, and permit
fees shall be charged directly to the Joint Property and shall not be included
when calculating the Equalized Freight.

 

5.   SERVICES

The cost of contract services, equipment, and utilities used in the conduct of
Joint Operations, except for contract services, equipment, and utilities covered
by Section III (Overhead), or Section II.7 (Affiliates), or excluded under
Section II.9 (Legal Expense). Awards paid to contractors shall be chargeable
pursuant to COPAS MFI-49 (“Awards to Employees and Contractors”).

The costs of third party Technical Services are chargeable to the extent
excluded from the overhead rates under Section III (Overhead).

 

6.   EQUIPMENT AND FACILITIES FURNISHED BY OPERATOR

In the absence of a separately negotiated agreement, equipment and facilities
furnished by the Operator will be charged as follows:

 

  A. The Operator shall charge the Joint Account for use of Operator-owned
equipment and facilities, including but not limited to production facilities,
Shore Base Facilities, Offshore Facilities, and Field Offices, at rates
commensurate with the costs of ownership and operation. The cost of Field
Offices shall be chargeable to the extent the Field Offices provide direct
service to personnel who are chargeable pursuant to Section II.2.A (Labor). Such
rates may include labor, maintenance, repairs, other operating expense,
insurance, taxes, depreciation using straight line depreciation method, and
interest on gross investment less accumulated depreciation not to exceed twelve
percent ( 12%) per annum; provided, however, depreciation shall not be charged
when the equipment and facilities investment have been fully depreciated. The
rate may include an element of the estimated cost for abandonment, reclamation,
and dismantlement. Such rates shall not exceed the average commercial rates
currently prevailing in the immediate area of the Joint Property.

 

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  B. In lieu of charges in Section II.6.A above, the Operator may elect to use
average commercial rates prevailing in the immediate area of the Joint Property,
less twenty percent (20%). If equipment and facilities are charged under this
Section II.6.B, the Operator shall adequately document and support commercial
rates and shall periodically review and update the rate and the supporting
documentation. For automotive equipment, the Operator may elect to use rates
published by the Petroleum Motor Transport Association (PMTA) or such other
organization recognized by COPAS as the official source of rates.

 

7.   AFFILIATES

Charges for services furnished by an Affiliate shall be charged in the same
manner as Operator employees, pursuant to Section II.2. Charges for goods
furnished by an Affiliate shall be charged in the same manner as charges for
equipment and facilities furnished by Operator, pursuant to Section II.6.

 

  A. Charges for an Affiliate’s goods and/or services used in operations
requiring an AFE or other authorization from the Non-Operators may be made
without the approval of the Parties provided (i) the Affiliate is identified and
the Affiliate goods and services are specifically detailed in the approved AFE
or other authorization, and (ii) the total costs for such Affiliate’s goods and
services billed to such individual project do not exceed $ N/A If the total
costs for an Affiliate’s goods and services charged to such individual project
are not specifically detailed in the approved AFE or authorization or exceed
such amount, charges for such Affiliate shall require approval of the Parties,
pursuant to Section I.6.A (General Matters).

 

  B. For an Affiliate’s goods and/or services used in operations not requiring
an AFE or other authorization from the Non-Operators, charges for such
Affiliate’s goods and services shall require approval of the Parties, pursuant
to Section I.6.A (General Matters), if the charges exceed $ N/A in a given
calendar year.

 

  C. The cost of the Affiliate’s services shall not exceed average commercial
rates prevailing in the area of the Joint Property, unless the Operator obtains
the Non-Operators’ approval of such rates. The Operator shall adequately
document and support commercial rates and shall periodically review and update
the rate and the supporting documentation; provided, however, documentation of
commercial rates shall not be required if the Operator obtains Non-Operator
approval of its Affiliate’s rates or charges prior to billing Non-Operators for
such Affiliate’s goods and services. Notwithstanding the foregoing, direct
charges for Affiliate-owned communication facilities or systems shall be made
pursuant to Section II.12 (Communications).

If the Parties fail to designate an amount in Sections II.7.A or II.7.B, in each
instance the amount deemed adopted by the Parties as a result of such omission
shall be the amount established as the Operator’s expenditure limitation in the
Agreement. If the Agreement does not contain an Operator’s expenditure
limitation, the amount deemed adopted by the Parties as a result of such
omission shall be zero dollars ($ 0.00).

 

8.   DAMAGES AND LOSSES TO JOINT PROPERTY

All costs or expenses necessary for the repair or replacement of Joint Property
resulting from damages or losses incurred, except to the extent such damages or
losses result from a Party’s or Parties’ gross negligence or willful misconduct,
in which case such Party or Parties shall be solely liable.

The Operator shall furnish the Non-Operator written notice of damages or losses
incurred as soon as practicable after a report has been received by the
Operator.

 

9.   LEGAL EXPENSE

Recording fees and costs of handling, settling, or otherwise discharging
litigation, claims, and liens incurred in or resulting from

operations under the Agreement, or necessary to protect or recover the Joint
Property, to the extent permitted under the Agreement. Costs of the Operator’s
or Affiliate’s legal staff or outside attorneys, including fees and expenses,
are not chargeable unless approved by the Parties pursuant to Section I.6.A
(General Matters) or otherwise provided for in the Agreement.

Notwithstanding the foregoing paragraph, costs for procuring abstracts, fees
paid to outside attorneys for title examinations (including preliminary,
supplemental, shut-in royalty opinions, division order title opinions), and
curative work shall be chargeable to the extent permitted as a direct charge in
the Agreement.

 

10.   TAXES AND PERMITS

All taxes and permitting fees of every kind and nature, assessed or levied upon
or in connection with the Joint Property, or the production therefrom, and which
have been paid by the Operator for the benefit of the Parties, including
penalties and interest, except to the extent the penalties and interest result
from the Operator’s gross negligence or willful misconduct.

If ad valorem taxes paid by the Operator are based in whole or in part upon
separate valuations of each Party’s working interest, then notwithstanding any
contrary provisions, the charges to the Parties will be made in accordance with
the tax value generated by each Party’s working interest.

 

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Costs of tax consultants or advisors, the Operator’s employees, or Operator’s
Affiliate employees in matters regarding ad valorem or other tax matters, are
not permitted as direct charges unless approved by the Parties pursuant to
Section I.6.A (General Matters).

Charges to the Joint Account resulting from sales/use tax audits, including
extrapolated amounts and penalties and interest, are permitted, provided the
Non-Operator shall be allowed to review the invoices and other underlying source
documents which served as the basis for tax charges and to determine that the
correct amount of taxes were charged to the Joint Account. If the Non-Operator
is not permitted to review such documentation, the sales/use tax amount shall
not be directly charged unless the Operator can conclusively document the amount
owed by the Joint Account.

 

11.   INSURANCE

Net premiums paid for insurance required to be carried for Joint Operations for
the protection of the Parties. If Joint Operations are conducted at locations
where the Operator acts as self-insurer in regard to its worker’s compensation
and employer’s liability insurance obligation, the Operator shall charge the
Joint Account manual rates for the risk assumed in its self-insurance program as
regulated by the jurisdiction governing the Joint Property. In the case of
offshore operations in federal waters, the manual rates of the adjacent state
shall be used for personnel performing work On-site, and such rates shall be
adjusted for offshore operations by the U.S. Longshoreman and Harbor Workers
(USL&H) or Jones Act surcharge, as appropriate.

 

12.   COMMUNICATIONS

Costs of acquiring, leasing, installing, operating, repairing, and maintaining
communication facilities or systems, including satellite, radio and microwave
facilities, between the Joint Property and the Operator’s office(s) directly
responsible for field operations in accordance with the provisions of COPAS
MFI-44 (“Field Computer and Communication Systems”). If the communications
facilities or systems serving the Joint Property are Operator-owned, charges to
the Joint Account shall be made as provided in Section II.6 (Equipment and
Facilities Furnished by Operator). If the communication facilities or systems
serving the Joint Property are owned by the Operator’s Affiliate, charges to the
Joint Account shall not exceed average commercial rates prevailing in the area
of the Joint Property. The Operator shall adequately document and support
commercial rates and shall periodically review and update the rate and the
supporting documentation.

 

13.   ECOLOGICAL, ENVIRONMENTAL, AND SAFETY

Costs incurred for Technical Services and drafting to comply with ecological,
environmental and safety Laws or standards recommended by Occupational Safety
and Health Administration (OSHA) or other regulatory authorities. All other
labor and functions incurred for ecological, environmental and safety matters,
including management, administration, and permitting, shall be covered by
Sections II.2 (Labor), II.5 (Services), or Section III (Overhead), as
applicable.

Costs to provide or have available pollution containment and removal equipment
plus actual costs of control and cleanup and resulting responsibilities of oil
and other spills as well as discharges from permitted outfalls as required by
applicable Laws, or other pollution containment and removal equipment deemed
appropriate by the Operator for prudent operations, are directly chargeable.

 

14.   ABANDONMENT AND RECLAMATION

Costs incurred for abandonment and reclamation of the Joint Property, including
costs required by lease agreements or by Laws.

 

15.   OTHER EXPENDITURES

Any other expenditure not covered or dealt with in the foregoing provisions of
this Section II (Direct Charges), or in Section III (Overhead) and which is of
direct benefit to the Joint Property and is incurred by the Operator in the
necessary and proper conduct of the Joint Operations. Charges made under this
Section II.15 shall require approval of the Parties, pursuant to Section I.6.A
(General Matters).

III. OVERHEAD

As compensation for costs not specifically identified as chargeable to the Joint
Account pursuant to Section II (Direct Charges), the Operator shall charge the
Joint Account in accordance with this Section III.

Functions included in the overhead rates regardless of whether performed by the
Operator, Operator’s Affiliates or third parties and regardless of location,
shall include, but not be limited to, costs and expenses of:

 

  •  

warehousing, other than for warehouses that are jointly owned under this
Agreement

 

  •  

design and drafting (except when allowed as a direct charge under Sections
II.13, III.1.A(ii), and III.2, Option B)

 

  •  

inventory costs not chargeable under Section V (Inventories of Controllable
Material)

 

  •  

procurement

 

  •  

administration

 

  •  

accounting and auditing

 

  •  

gas dispatching and gas chart integration

 

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  •  

human resources

 

  •  

management

 

  •  

supervision not directly charged under Section II.2 (Labor)

 

  •  

legal services not directly chargeable under Section II.9 (Legal Expense)

 

  •  

taxation, other than those costs identified as directly chargeable under Section
II.10 (Taxes and Permits)

 

  •  

preparation and monitoring of permits and certifications; preparing regulatory
reports; appearances before or meetings with governmental agencies or other
authorities having jurisdiction over the Joint Property, other than On-site
inspections; reviewing, interpreting, or submitting comments on or lobbying with
respect to Laws or proposed Laws.

Overhead charges shall include the salaries or wages plus applicable payroll
burdens, benefits, and Personal Expenses of personnel performing overhead
functions, as well as office and other related expenses of overhead functions.

 

1.   OVERHEAD—DRILLING AND PRODUCING OPERATIONS

As compensation for costs incurred but not chargeable under Section II (Direct
Charges) and not covered by other provisions of this Section III, the Operator
shall charge on either:

 

  þ (Alternative 1) Fixed Rate Basis, Section III.1.B.

 

  ¨ (Alternative 2) Percentage Basis, Section III.1.C.

 

  A. TECHNICAL SERVICES

 

  (i) Except as otherwise provided in Section II.13 (Ecological Environmental,
and Safety) and Section III.2 (Overhead – Major Construction and Catastrophe),
or by approval of the Parties pursuant to Section I.6.A (General Matters), the
salaries, wages, related payroll burdens and benefits, and Personal Expenses for
On-site Technical Services, including third party Technical Services:

 

  þ (Alternative 1 – Direct) shall be charged direct to the Joint Account.

 

  ¨ (Alternative 2 – Overhead) shall be covered by the overhead rates.

 

  (ii) Except as otherwise provided in Section II.13 (Ecological, Environmental,
and Safety) and Section III.2 (Overhead – Major Construction and Catastrophe),
or by approval of the Parties pursuant to Section I.6.A (General Matters), the
salaries, wages, related payroll burdens and benefits, and Personal Expenses for
Off-site Technical Services, including third party Technical Services:

 

  þ (Alternative 1 – All Overhead) shall be covered by the overhead rates.

 

  ¨ (Alternative 2 – All Direct) shall be charged direct to the Joint Account.

 

  ¨ (Alternative 3 – Drilling Direct) shall be charged direct to the Joint
Account, only to the extent such Technical Services are directly attributable to
drilling, redrilling, deepening, or sidetracking operations, through completion,
temporary abandonment, or abandonment if a dry hole. Off-site Technical Services
for all other operations, including workover, recompletion, abandonment of
producing wells, and the construction or expansion of fixed assets not covered
by Section III.2 (Overhead – Major Construction and Catastrophe) shall be
covered by the overhead rates.

Notwithstanding anything to the contrary in this Section III, Technical Services
provided by Operator’s Affiliates are subject to limitations set forth in
Section II.7 (Affiliates). Charges for Technical personnel performing
non-technical work shall not be governed by this Section III.1.A, but instead
governed by other provisions of this Accounting Procedure relating to the type
of work being performed.

 

  B. OVERHEAD—FIXED RATE BASIS

 

  (1) The Operator shall charge the Joint Account at the following rates per
well per month:

Drilling Well Rate per month $6,000 (prorated for less than a full month)

Producing Well Rate per month $ 600

 

  (2) Application of Overhead—Drilling Well Rate shall be as follows:

 

  (a) Charges for onshore drilling wells shall begin on the spud date and
terminate on the date the drilling and/or completion equipment used on the well
is released, whichever occurs later. Charges for offshore and inland waters
drilling wells shall begin on the date the drilling or completion equipment
arrives on location and terminate on the date the drilling or completion
equipment moves off location, or is released, whichever occurs first. No charge
shall be made during suspension of drilling and/or completion operations for
fifteen (15) or more consecutive calendar days.

 

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  (b) Charges for any well undergoing any type of workover, recompletion, and/or
abandonment for a period of five (5) or more consecutive work–days shall be made
at the Drilling Well Rate. Such charges shall be applied for the period from
date operations, with rig or other units used in operations, commence through
date of rig or other unit release, except that no charges shall be made during
suspension of operations for fifteen (15) or more consecutive calendar days.

 

  (3) Application of Overhead—Producing Well Rate shall be as follows:

 

  (a) An active well that is produced, injected into for recovery or disposal,
or used to obtain water supply to support operations for any portion of the
month shall be considered as a one-well charge for the entire month.

 

  (b) Each active completion in a multi-completed well shall be considered as a
one-well charge provided each completion is considered a separate well by the
governing regulatory authority.

 

  (c) A one-well charge shall be made for the month in which plugging and
abandonment operations are completed on any well, unless the Drilling Well Rate
applies, as provided in Sections III.1.B.(2)(a) or (b). This one-well charge
shall be made whether or not the well has produced.

 

  (d) An active gas well shut in because of overproduction or failure of a
purchaser, processor, or transporter to take production shall be considered as a
one-well charge provided the gas well is directly connected to a permanent sales
outlet.

 

  (e) Any well not meeting the criteria set forth in Sections III.1.B.(3) (a),
(b), (c), or (d) shall not qualify for a producing overhead charge.

 

  (4) The well rates shall be adjusted on the first day of April each year
following the effective date of the Agreement; provided, however, if this
Accounting Procedure is attached to or otherwise governing the payout accounting
under a farmout agreement, the rates shall be adjusted on the first day of April
each year following the effective date of such farmout agreement. The adjustment
shall be computed by applying the adjustment factor most recently published by
COPAS. The adjusted rates shall be the initial or amended rates agreed to by the
Parties increased or decreased by the adjustment factor described herein, for
each year from the effective date of such rates, in accordance with COPAS MFI-47
(“Adjustment of Overhead Rates”).

 

  C. OVERHEAD—PERCENTAGE BASIS

 

  (1) Operator shall charge the Joint Account at the following rates:

 

  (a) Development Rate          percent (        )% of the cost of development
of the Joint Property, exclusive of costs provided under Section II.9 (Legal
Expense) and all Material salvage credits.

 

  (b) Operating Rate          percent (        %) of the cost of operating the
Joint Property, exclusive of costs provided under Sections II.1 (Rentals and
Royalties) and II.9 (Legal Expense); all Material salvage credits; the value of
substances purchased for enhanced recovery; all property and ad valorem taxes,
and any other taxes and assessments that are levied, assessed, and paid upon the
mineral interest in and to the Joint Property.

 

  (2) Application of Overhead—Percentage Basis shall be as follows:

 

  (a) The Development Rate shall be applied to all costs in connection with:

 

  [i] drilling, redrilling, sidetracking, or deepening of a well

 

  [ii] a well undergoing plugback or workover operations for a period of five
(5) or more consecutive work–days

 

  [iii] preliminary expenditures necessary in preparation for drilling

 

  [iv] expenditures incurred in abandoning when the well is not completed as a
producer

 

  [v] construction or installation of fixed assets, the expansion of fixed
assets and any other project clearly discernible as a fixed asset, other than
Major Construction or Catastrophe as defined in Section III.2 (Overhead-Major
Construction and Catastrophe).

 

  (b) The Operating Rate shall be applied to all other costs in connection with
Joint Operations, except those subject to Section III.2 (Overhead-Major
Construction and Catastrophe).

 

2.   OVERHEAD—MAJOR CONSTRUCTION AND CATASTROPHE

To compensate the Operator for overhead costs incurred in connection with a
Major Construction project or Catastrophe, the Operator shall either negotiate a
rate prior to the beginning of the project, or shall charge the Joint Account
for overhead based on the following rates for any Major Construction project in
excess of the Operator’s expenditure limit under the Agreement, or for any
Catastrophe regardless of the amount. If the Agreement to which this Accounting
Procedure is attached does not contain an expenditure limit, Major Construction
Overhead shall be assessed for any single Major Construction project costing in
excess of $100,000 gross.

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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Major Construction shall mean the construction and installation of fixed assets,
the expansion of fixed assets, and any other project clearly discernible as a
fixed asset required for the development and operation of the Joint Property, or
in the dismantlement, abandonment, removal, and restoration of platforms,
production equipment, and other operating facilities.

Catastrophe is defined as a sudden calamitous event bringing damage, loss, or
destruction to property or the environment, such as an oil spill, blowout,
explosion, fire, storm, hurricane, or other disaster. The overhead rate shall be
applied to those costs necessary to restore the Joint Property to the equivalent
condition that existed prior to the event.

 

  A. If the Operator absorbs the engineering, design and drafting costs related
to the project:

 

  (1) 6% of total costs if such costs are less than $100,000; plus

 

  (2) 4% of total costs in excess of $100,000 but less than $1,000,000; plus

 

  (3) 3% of total costs in excess of $1,000,000.

 

  B. If the Operator charges engineering, design and drafting costs related to
the project directly to the Joint Account:

 

  (1) 5% of total costs if such costs are less than $100,000; plus

 

  (2) 3% of total costs in excess of $100,000 but less than $1,000,000; plus

 

  (3) 2% of total costs in excess of $1,000,000.

Total cost shall mean the gross cost of any one project. For the purpose of this
paragraph, the component parts of a single Major

Construction project shall not be treated separately, and the cost of drilling
and workover wells and purchasing and installing pumping units and downhole
artificial lift equipment shall be excluded. For Catastrophes, the rates shall
be applied to all costs associated with each single occurrence or event.

On each project, the Operator shall advise the Non-Operator(s) in advance which
of the above options shall apply.

For the purposes of calculating Catastrophe Overhead, the cost of drilling
relief wells, substitute wells, or conducting other well operations directly
resulting from the catastrophic event shall be included. Expenditures to which
these rates apply shall not be reduced by salvage or insurance recoveries.
Expenditures that qualify for Major Construction or Catastrophe Overhead shall
not qualify for overhead under any other overhead provisions.

In the event of any conflict between the provisions of this Section III.2 and
the provisions of Sections II.2 (Labor), II.5 (Services), or II.7 (Affiliates),
the provisions of this Section III.2 shall govern.

 

3.   AMENDMENT OF OVERHEAD RATES

The overhead rates provided for in this Section III may be amended from time to
time if, in practice, the rates are found to be insufficient or excessive, in
accordance with the provisions of Section I.6.B (Amendments).

IV. MATERIAL PURCHASES, TRANSFERS, AND DISPOSITIONS

The Operator is responsible for Joint Account Material and shall make proper and
timely charges and credits for direct purchases, transfers, and dispositions.
The Operator shall provide all Material for use in the conduct of Joint
Operations; however, Material may be supplied by the Non- Operators, at the
Operator’s option. Material furnished by any Party shall be furnished without
any express or implied warranties as to quality, fitness for use, or any other
matter.

 

1.   DIRECT PURCHASES

Direct purchases shall be charged to the Joint Account at the price paid by the
Operator after deduction of all discounts received. The Operator shall make good
faith efforts to take discounts offered by suppliers, but shall not be liable
for failure to take discounts except to the extent such failure was the result
of the Operator’s gross negligence or willful misconduct. A direct purchase
shall be deemed to occur when an agreement is made between an Operator and a
third party for the acquisition of Material for a specific well site or
location. Material provided by the Operator under “vendor stocking programs,”
where the initial use is for a Joint Property and title of the Material does not
pass from the manufacturer, distributor, or agent until usage, is considered a
direct purchase. If Material is found to be defective or is returned to the
manufacturer, distributor, or agent for any other reason, credit shall be passed
to the Joint Account within sixty (60) days after the Operator has received
adjustment from the manufacturer, distributor, or agent.

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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2.   TRANSFERS

A transfer is determined to occur when the Operator (i) furnishes Material from
a storage facility or from another operated property, (ii) has assumed liability
for the storage costs and changes in value, and (iii) has previously secured and
held title to the transferred Material. Similarly, the removal of Material from
the Joint Property to a storage facility or to another operated property is also
considered a transfer; provided, however, Material that is moved from the Joint
Property to a storage location for safe-keeping pending disposition may remain
charged to the Joint Account and is not considered a transfer. Material shall be
disposed of in accordance with Section IV.3 (Disposition of Surplus) and the
Agreement to which this Accounting Procedure is attached.

 

  A. PRICING

The value of Material transferred to/from the Joint Property should generally
reflect the market value on the date of physical transfer. Regardless of the
pricing method used, the Operator shall make available to the Non-Operators
sufficient documentation to verify the Material valuation. When higher than
specification grade or size tubulars are used in the conduct of Joint
Operations, the Operator shall charge the Joint Account at the equivalent price
for well design specification tubulars, unless such higher specification grade
or sized tubulars are approved by the Parties pursuant to Section I.6.A (General
Matters). Transfers of new Material will be priced using one of the following
pricing methods; provided, however, the Operator shall use consistent pricing
methods, and not alternate between methods for the purpose of choosing the
method most favorable to the Operator for a specific transfer:

 

  (1) Using published prices in effect on date of movement as adjusted by the
appropriate COPAS Historical Price Multiplier (HPM) or prices provided by the
COPAS Computerized Equipment Pricing System (CEPS).

 

  (a) For oil country tubulars and line pipe, the published price shall be based
upon eastern mill carload base prices (Houston, Texas, for special end) adjusted
as of date of movement, plus transportation cost as defined in Section IV.2.B
(Freight).

 

  (b) For other Material, the published price shall be the published list price
in effect at date of movement, as listed by a Supply Store nearest the Joint
Property where like Material is normally available, or point of manufacture plus
transportation costs as defined in Section IV.2.B (Freight).

 

  (2) Based on a price quotation from a vendor that reflects a current realistic
acquisition cost.

 

  (3) Based on the amount paid by the Operator for like Material in the vicinity
of the Joint Property within the previous twelve (12) months from the date of
physical transfer.

 

  (4) As agreed to by the Participating Parties for Material being transferred
to the Joint Property, and by the Parties owning the Material for Material being
transferred from the Joint Property.

 

  B. FREIGHT

Transportation costs shall be added to the Material transfer price using the
method prescribed by the COPAS Computerized

Equipment Pricing System (CEPS). If not using CEPS, transportation costs shall
be calculated as follows:

 

  (1) Transportation costs for oil country tubulars and line pipe shall be
calculated using the distance from eastern mill to the Railway Receiving Point
based on the carload weight basis as recommended by the COPAS MFI-38 (“Material
Pricing Manual”) and other COPAS MFIs in effect at the time of the transfer.

 

  (2) Transportation costs for special mill items shall be calculated from that
mill’s shipping point to the Railway Receiving Point. For transportation costs
from other than eastern mills, the 30,000-pound interstate truck rate shall be
used. Transportation costs for macaroni tubing shall be calculated based on the
interstate truck rate per weight of tubing transferred to the Railway Receiving
Point.

 

  (3) Transportation costs for special end tubular goods shall be calculated
using the interstate truck rate from Houston, Texas, to the Railway Receiving
Point.

 

  (4) Transportation costs for Material other than that described in Sections
IV.2.B.(1) through (3), shall be calculated from the Supply Store or point of
manufacture, whichever is appropriate, to the Railway Receiving Point

Regardless of whether using CEPS or manually calculating transportation costs,
transportation costs from the Railway Receiving Point to the Joint Property are
in addition to the foregoing, and may be charged to the Joint Account based on
actual costs incurred. All transportation costs are subject to Equalized Freight
as provided in Section II.4 (Transportation) of this Accounting Procedure.

 

  C. TAXES

Sales and use taxes shall be added to the Material transfer price using either
the method contained in the COPAS Computerized Equipment Pricing System (CEPS)
or the applicable tax rate in effect for the Joint Property at the time and
place of transfer. In either case, the Joint Account shall be charged or
credited at the rate that would have governed had the Material been a direct
purchase.

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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  D. CONDITION

 

  (1) Condition “A” – New and unused Material in sound and serviceable condition
shall be charged at one hundred percent (100%) of the price as determined in
Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes). Material
transferred from the Joint Property that was not placed in service shall be
credited as charged without gain or loss; provided, however, any unused Material
that was charged to the Joint Account through a direct purchase will be credited
to the Joint Account at the original cost paid less restocking fees charged by
the vendor. New and unused Material transferred from the Joint Property may be
credited at a price other than the price originally charged to the Joint Account
provided such price is approved by the Parties owning such Material, pursuant to
Section I.6.A (General Matters). All refurbishing costs required or necessary to
return the Material to original condition or to correct handling,
transportation, or other damages will be borne by the divesting property. The
Joint Account is responsible for Material preparation, handling, and
transportation costs for new and unused Material charged to the Joint Property
either through a direct purchase or transfer. Any preparation costs incurred,
including any internal or external coating and wrapping, will be credited on new
Material provided these services were not repeated for such Material for the
receiving property.

 

  (2) Condition “B” – Used Material in sound and serviceable condition and
suitable for reuse without reconditioning shall be priced by multiplying the
price determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C
(Taxes) by seventy-five percent (75%).

Except as provided in Section IV.2.D(3), all reconditioning costs required to
return the Material to Condition “B” or to correct handling, transportation or
other damages will be borne by the divesting property.

If the Material was originally charged to the Joint Account as used Material and
placed in service for the Joint Property, the Material will be credited at the
price determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C
(Taxes) multiplied by sixty-five percent (65%).

Unless otherwise agreed to by the Parties that paid for such Material, used
Material transferred from the Joint Property that was not placed in service on
the property shall be credited as charged without gain or loss.

 

  (3) Condition “C” – Material that is not in sound and serviceable condition
and not suitable for its original function until after reconditioning shall be
priced by multiplying the price determined in Sections IV.2.A (Pricing), IV.2.B
(Freight), and IV.2.C (Taxes) by fifty percent (50%).

The cost of reconditioning may be charged to the receiving property to the
extent Condition “C” value, plus cost of reconditioning, does not exceed
Condition “B” value.

 

  (4) Condition “D” – Material that (i) is no longer suitable for its original
purpose but useable for some other purpose, (ii) is obsolete, or (iii) does not
meet original specifications but still has value and can be used in other
applications as a substitute for items with different specifications, is
considered Condition “D” Material. Casing, tubing, or drill pipe used as line
pipe shall be priced as Grade A and B seamless line pipe of comparable size and
weight. Used casing, tubing, or drill pipe utilized as line pipe shall be priced
at used line pipe prices. Casing, tubing, or drill pipe used as higher pressure
service lines than standard line pipe, e.g., power oil lines, shall be priced
under normal pricing procedures for casing, tubing, or drill pipe. Upset tubular
goods shall be priced on a non-upset basis. For other items, the price used
should result in the Joint Account being charged or credited with the value of
the service rendered or use of the Material, or as agreed to by the Parties
pursuant to Section 1.6.A (General Matters).

 

  (5) Condition “E” – Junk shall be priced at prevailing scrap value prices.

 

  E. OTHER PRICING PROVISIONS

 

  (1) Preparation Costs

Subject to Section II (Direct Charges) and Section III (Overhead) of this
Accounting Procedure, costs incurred by the Operator in making Material
serviceable including inspection, third party surveillance services, and other
similar services will be charged to the Joint Account at prices which reflect
the Operator’s actual costs of the services. Documentation must be provided to
the Non-Operators upon request to support the cost of service. New coating
and/or wrapping shall be considered a component of the Materials and priced in
accordance with Sections IV.1 (Direct Purchases) or IV.2.A (Pricing), as
applicable. No charges or credits shall be made for used coating or wrapping.
Charges and credits for inspections shall be made in accordance with COPAS
MFI-38 (“Material Pricing Manual”).

 

  (2) Loading and Unloading Costs

Loading and unloading costs related to the movement of the Material to the Joint
Property shall be charged in accordance with the methods specified in COPAS
MFI-38 (“Material Pricing Manual”).

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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3.   DISPOSITION OF SURPLUS

Surplus Material is that Material, whether new or used, that is no longer
required for Joint Operations. The Operator may purchase, but shall be under no
obligation to purchase, the interest of the Non-Operators in surplus Material.

Dispositions for the purpose of this procedure are considered to be the
relinquishment of title of the Material from the Joint Property to either a
third party, a Non-Operator, or to the Operator. To avoid the accumulation of
surplus Material, the Operator should make good faith efforts to dispose of
surplus within twelve (12) months through buy/sale agreements, trade, sale to a
third party, division in kind, or other dispositions as agreed to by the
Parties.

Disposal of surplus Materials shall be made in accordance with the terms of the
Agreement to which this Accounting Procedure is attached. If the Agreement
contains no provisions governing disposal of surplus Material, the following
terms shall apply:

 

  •  

The Operator may, through a sale to an unrelated third party or entity, dispose
of surplus Material having a gross sale value that is less than or equal to the
Operator’s expenditure limit as set forth in the Agreement to which this
Accounting Procedure is attached without the prior approval of the Parties
owning such Material.

 

  •  

If the gross sale value exceeds the Agreement expenditure limit, the disposal
must be agreed to by the Parties owning such Material.

 

  •  

Operator may purchase surplus Condition “A” or “B” Material without approval of
the Parties owning such Material, based on the pricing methods set forth in
Section IV.2 (Transfers).

 

  •  

Operator may purchase Condition “C” Material without prior approval of the
Parties owning such Material if the value of the Materials, based on the pricing
methods set forth in Section IV.2 (Transfers), is less than or equal to the
Operator’s expenditure limitation set forth in the Agreement. The Operator shall
provide documentation supporting the classification of the Material as Condition
C.

 

  •  

Operator may dispose of Condition “D” or “E” Material under procedures normally
utilized by Operator without prior approval of the Parties owning such Material.

 

4.   SPECIAL PRICING PROVISIONS

 

  A. PREMIUM PRICING

Whenever Material is available only at inflated prices due to national
emergencies, strikes, government imposed foreign trade restrictions, or other
unusual causes over which the Operator has no control, for direct purchase the
Operator may charge the Joint Account for the required Material at the
Operator’s actual cost incurred in providing such Material, making it suitable
for use, and moving it to the Joint Property. Material transferred or disposed
of during premium pricing situations shall be valued in accordance with Section
IV.2 (Transfers) or Section IV.3 (Disposition of Surplus), as applicable.

 

  B. SHOP-MADE ITEMS

Items fabricated by the Operator’s employees, or by contract laborers under the
direction of the Operator, shall be priced using the value of the Material used
to construct the item plus the cost of labor to fabricate the item. If the
Material is from the Operator’s scrap or junk account, the Material shall be
priced at either twenty-five percent (25%) of the current price as determined in
Section IV.2.A (Pricing) or scrap value, whichever is higher. In no event shall
the amount charged exceed the value of the item commensurate with its use.

 

  C. MILL REJECTS

Mill rejects purchased as “limited service” casing or tubing shall be priced at
eighty percent (80%) of K-55/J-55 price as determined in Section IV.2
(Transfers). Line pipe converted to casing or tubing with casing or tubing
couplings attached shall be priced as K-55/J-55 casing or tubing at the nearest
size and weight.

V. INVENTORIES OF CONTROLLABLE MATERIAL

The Operator shall maintain records of Controllable Material charged to the
Joint Account, with sufficient detail to perform physical inventories.

Adjustments to the Joint Account by the Operator resulting from a physical
inventory of Controllable Material shall be made within twelve (12) months
following the taking of the inventory or receipt of Non-Operator inventory
report. Charges and credits for overages or shortages will be valued for the
Joint Account in accordance with Section IV.2 (Transfers) and shall be based on
the Condition “B” prices in effect on the date of physical inventory unless the
inventorying Parties can provide sufficient evidence another Material condition
applies.

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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1.   DIRECTED INVENTORIES

Physical inventories shall be performed by the Operator upon written request of
a majority in working interests of the Non-Operators (hereinafter, “directed
inventory”); provided, however, the Operator shall not be required to perform
directed inventories more frequently than once every five (5) years. Directed
inventories shall be commenced within one hundred eighty (180) days after the
Operator receives written notice that a majority in interest of the
Non-Operators has requested the inventory. All Parties shall be governed by the
results of any directed inventory.

Expenses of directed inventories will be borne by the Joint Account; provided,
however, costs associated with any post-report follow-up work in settling the
inventory will be absorbed by the Party incurring such costs. The Operator is
expected to exercise judgment in keeping expenses within reasonable limits. Any
anticipated disproportionate or extraordinary costs should be discussed and
agreed upon prior to commencement of the inventory. Expenses of directed
inventories may include the following:

 

  A. A per diem rate for each inventory person, representative of actual
salaries, wages, and payroll burdens and benefits of the personnel performing
the inventory or a rate agreed to by the Parties pursuant to Section I.6.A
(General Matters). The per diem rate shall also be applied to a reasonable
number of days for pre-inventory work and report preparation.

 

  B. Actual transportation costs and Personal Expenses for the inventory team.

 

  C. Reasonable charges for report preparation and distribution to the
Non-Operators.

 

2.   NON-DIRECTED INVENTORIES

 

  A. OPERATOR INVENTORIES

Physical inventories that are not requested by the Non-Operators may be
performed by the Operator, at the Operator’s discretion. The expenses of
conducting such Operator-initiated inventories shall not be charged to the Joint
Account.

 

  B. NON-OPERATOR INVENTORIES

Subject to the terms of the Agreement to which this Accounting Procedure is
attached, the Non-Operators may conduct a physical inventory at reasonable times
at their sole cost and risk after giving the Operator at least ninety (90) days
prior written notice. The Non-Operator inventory report shall be furnished to
the Operator in writing within ninety (90) days of completing the inventory
fieldwork.

 

  C. SPECIAL INVENTORIES

The expense of conducting inventories other than those described in Sections V.1
(Directed Inventories), V.2.A (Operator Inventories), or V.2.B (Non-Operator
Inventories), shall be charged to the Party requesting such inventory; provided,
however, inventories required due to a change of Operator shall be charged to
the Joint Account in the same manner as described in Section V.1 (Directed
Inventories).

 

COPYRIGHT © 2005 by COPAS, Inc.

 

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EXHIBIT D

Attached to and made a part of the certain Operating Agreement executed
October 31, 2012 but dated effective November 1, 2012, by and between, Encana
Oil &Gas (USA) Inc. and Nucor Energy Holdings Inc.

INSURANCE

 

1. The Operator shall carry for the benefit of the joint account insurance
unless otherwise agreed, to be comprised of the following coverage:

 

  A. Commercial General Liability

$10,000,000. Each occurrence and in the aggregate

 

  B. Operator’s Extra Expense (Control of Well)

$10,000,000 for wells 10,000 feet or greater in depth

$5,000,000 for wells less than 10,000 feet in depth

Combined Single Limit and any one accident or occurrence for 100% interest.

 

2. The Operator shall carry for the benefit of the joint account the following
minimum amounts of insurance:

 

  A: Workmen’s Compensation in accordance with Federal law and the laws of the
State in which operations will be conducted and/or other applicable
jurisdiction.

 

  B. Employer’s Liability

 

a.      Bodily Injury by Accident

   $1,000,000 each accident

b.      Bodily Injury by Disease

   $1,000,000 policy limit

c.      Bodily Injury by Disease

   $1,000,000 each employee

 

  C. Comprehensive Automobile Public Liability

 

a.      Bodily Injury

   $2,000,000 per occurrence

b.      Property Damage

   $2,000,000 per occurrence

 

3. No other insurance will be required other than that set forth above. Premiums
associated with the insurance for the benefit of the Joint Account herein shall
be charged to the Joint Account.

 

4. The insurance provided for herein for the benefit of the Joint Account
provides for certain deductibles to be borne by the insured parties. In the
event a claim is made by the Operator on behalf of the Joint Account, and the
insurance proceeds are subject to reduction as a result of a deductible
provision, said deductible amount shall be a direct charge to the Joint Account.

 

Exhibit D

Page 1 of 3

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5. The insurance provided for herein shall be primary regardless of any
insurance carried by Operator or Non-Operator for their own account.

 

6. Insurance, other than Worker’s Compensation, will name Non-Operator as an
additional insured and will provide a waiver of subrogation in favor of
Non-Operator.

 

7. In the event a Non-Operator elects to carry its own insurance and waive the
insurance coverage set forth above, then the Non-Operator shall notify Operator
seven days prior to any operation proposed under this Agreement wherein the
applicable premiums shall not be charged to the Joint Account. If Non- Operator
elects to carry its own insurance, or anytime upon the request of Operator, Non-
Operator shall provide a Certificate of Insurance confirming its insurance
coverage.

 

Exhibit D

Page 2 of 3

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ELECTION BALLOT

Well

Location

City State

Nucor Energy Holdings Inc. hereby Elects              Does Not Elect
             to participate for a [%] WI in the drilling of the [well] under
Encana’s insurance program as follows:

Commercial General Liability:

USD 10,000,000 limit, scaled to interest, each occurrence and in the aggregate,
subject to USD 1,000,000 deductible, scaled to interest, each occurrence.

Operator’s Extra Expense:

USD 10,000,000 limit, scaled to interest, each occurrence subject to USD
1,000,000 deductible, scaled to interest, each occurrence

Coverage is extended to the above-named non-operator only in respect of
operations of the above-noted well.

 

NUCOR ENERGY HOLDINGS INC. By:     Print Name:     Title:     Date Signed:    

In the event that you have elected to participate in this operation, please be
advised that Commercial General Liability and Operator’s Extra Expense insurance
covering your interest is required.

Please indicate your well control insurance election below:

 

             Elect to be covered under the JOA with the Operator

 

             Elect to carry own insurance – CERTIFICATE SHOWING PROOF OF
INSURANCE (with Encana Oil & Gas (USA) Inc. named as certificate holder) MUST BE
SUBMITTED TO ENCANA BEFORE THE START OF OPERATIONS.

 

Exhibit D

Page 3 of 3

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EXHIBIT E

GAS BALANCING AGREEMENT (“AGREEMENT”)

Attached to and made a part of the certain Operating Agreement, executed
October 31, 2012 but dated effective November 1, 2012, by and between Encana Oil
&Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

1.   DEFINITIONS

The following definitions shall apply to this Agreement:

 

  1.01 “Arm’s Length Agreement” shall mean any gas sales agreement with an
unaffiliated purchaser or any gas sales agreement with an affiliated purchaser
where the sales price and delivery conditions under such agreement are
representative of prices and delivery conditions existing under other similar
agreements in the area between unaffiliated parties at the same time for natural
gas of comparable quality and quantity.

 

  1.02 “Balancing Area” shall mean:

All of the acreage and depths subject to the Operating Agreement, subject to the
following: (i) if a well is completed in two (2) or more producing intervals
where the working interest and royalty ownership is not uniform, producing
intervals having uniform working interest and royalty ownership shall be
considered a separate Balancing Area, and (ii) if a well or group of wells have
uniform working interest and royalty ownership, but any of such well or wells
are considered to be in a different state and/or federal communitized area,
state or federal unit, or pooled unit, each such well or group of wells shall be
considered a separate Balancing Area.

 

  1.03 “Full Share of Current Production” shall mean the Percentage Interest of
each Party in the Gas actually produced from the Balancing Area during each
month.

 

  1.04 “Gas” shall mean all hydrocarbons produced or producible from the
Balancing Area, whether from a well classified as an oil well or gas well by the
regulatory agency having jurisdiction in such matters, which are or may be made
available for sale or separate disposition by the Parties, excluding oil,
condensate and other liquids recovered by field equipment operated for the joint
account. “Gas” does not include gas used in joint operations, such as for fuel,
recycling or reinjection, or which is vented or lost prior to its delivery from
the Balancing Area.

 

  1.05 “Makeup Gas” shall mean any Gas taken by an Underproduced Party from the
Balancing Area in excess of its Full Share of Current Production, whether
pursuant to Section 3.3 or Section 4.1 hereof.

 

  1.06 “Mcf” shall mean one thousand cubic feet. A cubic foot of Gas shall mean
the volume of gas contained in one cubic foot of space at a standard pressure
base and at a standard temperature base.

 

  1.07 “MMBtu” shall mean one million British Thermal Units. A British Thermal
Unit shall mean the quantity of heat required to raise one pound avoirdupois of
pure water from 58.5 degrees Fahrenheit to 59.5 degrees Fahrenheit at a constant
pressure of 14.73 pounds per square inch absolute.

 

  1.08 “Operator” shall mean the individual or entity designated under the terms
of the Operating Agreement or, in the event this Agreement is not employed in
connection with an operating agreement, the individual or entity designated as
the operator of the well(s) located in the Balancing Area.

 

  1.09 “Overproduced Party” shall mean any Party having taken a greater quantity
of Gas from the Balancing Area than the Percentage Interest of such Party in the
cumulative quantity of all Gas produced from the Balancing Area.

 

  1.10 “Overproduction” shall mean the cumulative quantity of Gas taken by a
Party in excess of its Percentage Interest in the cumulative quantity of all Gas
produced from the Balancing Area.

 

  1.11 “Party” shall mean those individuals or entities subject to this
Agreement, and their respective heirs, successors, transferees and assigns.

 

  1.12 “Percentage Interest” shall mean the percentage or decimal interest of
each Party in the Gas produced from the Balancing Area pursuant to the Operating
Agreement covering the Balancing Area.

 

  1.13 “Published Reference Price” shall mean the Index price published for the
applicable geographic area on the transporting pipeline in the first of the
production month’s edition of Inside FERC Gas Market Report (“Inside FERC
Index”). In the event that the Inside FERC Index ceases to be published, the
parties will attempt in good faith to agree on a replacement reference price
reflective of the same market reflected by the Inside FERC Index.

 

  1.14 “Royalty” shall mean payments on production of Gas from the Balancing
Area to all owners of royalties, overriding royalties, production payments or
similar interests.

 

  1.15 “Underproduced Party” shall mean any Party having taken a lesser quantity
of Gas from the Balancing Area than the Percentage Interest of such Party in the
cumulative quantity of all Gas produced from the Balancing Area.

 

  1.16 “Underproduction” shall mean the deficiency between the cumulative
quantity of Gas taken by a Party and its Percentage Interest in the cumulative
quantity of all Gas produced from the Balancing Area.

 

  1.17 “Winter Period” shall mean the month(s) of November and December in one
calendar year and the month(s) of January, February, and March in the succeeding
calendar year.

 

2.   BALANCING AREA

2.1 If this Agreement covers more than one Balancing Area, it shall be applied
as if each Balancing Area were covered by separate but identical agreements. All
balancing hereunder, other than cash settlements made pursuant to Section 7,
shall be on the basis of Gas taken from the Balancing Area measured in Mcfs.

2.2 In the event that all or part of the Gas deliverable from a Balancing Area
is or becomes subject to one or more maximum lawful prices, any Gas not subject
to price controls shall be considered as produced from a single Balancing Area
and Gas subject to each maximum lawful price category shall be considered
produced from a separate Balancing Area.

 

Exhibit E

Page 1 of 5

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3.   RIGHT OF PARTIES TO TAKE GAS

3.1 Each Party desiring to take Gas will notify the Operator, or cause the
Operator to be notified, of the volumes nominated, the name of the transporting
pipeline and the pipeline contract number (if available) and the meter station
relating to such delivery, sufficiently in advance for the Operator, acting with
reasonable diligence, to meet all nomination and other requirements. Operator is
authorized to deliver the volumes so nominated and confirmed (if confirmation is
required) to the transporting pipeline in accordance with the terms of this
Agreement.

3.2 Each Party to take its Full Share of Current Production each month, to the
extent that such production is required to maintain leases in effect, to protect
the producing capacity of a well or reservoir, to preserve correlative rights,
or to maintain oil production.

3.3 When a Party fails for any reason to take its Full Share of Current
Production (as such Share may be reduced by the right of the other Parties to
make up for Underproduction as provided herein), the other Parties shall be
entitled to take any Gas which such Party fails to take. To the extent
practicable, such Gas shall be made available initially to each Underproduced
Party in the proportion that its Percentage Interest in the Balancing Area bears
to the total Percentage Interests of all Underproduced Parties desiring to take
such Gas and then be made available to the other Parties in the proportion that
their respective Percentage Interests in the Balancing Area bear to the total
Percentage Interests of such Parties.

3.4 All Gas taken by a Party in accordance with the of this Agreement,
regardless of whether such Party is underproduced or overproduced, shall be
regarded as Gas taken for its own account with title thereto being in such
taking Party.

3.5 Notwithstanding the provisions of Section 3.3 hereof, no Overproduced Party
shall be entitled in any month to take any Gas in excess of three hundred
percent ( 300% ) of its Percentage Interest of the Balancing Area’s then-current
Maximum Monthly Availability; provided, however, that this limitation shall not
apply to the extent that it would preclude production that is required to
maintain leases in effect, to protect the producing capacity of a well or
reservoir, to preserve correlative rights, or to maintain oil production.
“Maximum Monthly Availability” shall mean the maximum average monthly rate of
production at which Gas can be delivered from the Balancing Area, as determined
by the Operator, considering the maximum efficient well rate for each well
within the Balancing Area, the maximum allowable(s) set by the appropriate
regulatory agency, mode of operation, production facility capabilities and
pipeline pressures.

3.6 In the event the Operator determines that a Party has failed to make
arrangements to take its Full Share of Current Production required to be
produced to maintain leases in effect, to protect the producing capacity of a
well or reservoir, to preserve correlative rights, or to maintain oil
production, the Operator shall notify such Party that it has failed to take such
Full Share of Current Production. If the notified Party does not begin taking
its Full Share of Current Production effective the second business day following
notification from the Operator, the Operator shall, to the extent practicable,
make available to the Underproduced Party(ies) any part of such Party’s Full
Share of Current Production that such Party fails to take or the Operator may
sell any part of such Party’s Full Share of Current Production that such Party
fails to take for the account of such Party and render to such Party, on a
current basis, the full proceeds of the sale, less any reasonable marketing,
compression, treating, gathering or transportation costs incurred directly in
connection with the sale of such Full Share of Current Production. In making the
sale contemplated herein, the Operator shall be obligated only to obtain such
price and conditions for the sale as are reasonable under the circumstances and
shall not be obligated to share any of its markets. Any such sale by Operator
under the terms hereof shall be only for such reasonable periods of time as are
consistent with the minimum needs of the industry under the particular
circumstances, but in no event for a period in excess of one year.
Notwithstanding the provisions of Section 3.4 hereof, Gas sold by Operator for a
Party under the provisions hereof shall be deemed to be Gas taken for the
account of such Party.

 

4.   IN-KIND BALANCING

Effective the first day of any calendar month following at least thirty
(30) days’ prior written notice to the Operator, any Underproduced Party may
begin taking, in addition to its Full Share of Current Production and any Makeup
Gas taken pursuant to Section 3.3 of this Agreement, a share of current
production determined by multiplying twenty five percent (25%) of the Full
Shares of Current Production of all Overproduced Parties by a fraction, the
numerator of which is the Percentage Interest of such Underproduced Party and
the denominator of which is the total of the Percentage Interests of all
Underproduced Parties desiring to take Makeup Gas. In no event will an
Overproduced Party be required to provide more than twenty five percent (25%) of
its Full Share of Current Production for Makeup Gas.

 

5.   STATEMENT OF GAS BALANCES

5.1 The Operator will maintain appropriate accounting on a monthly and
cumulative basis of the volumes of Gas that each Party is entitled to receive
and the volumes of Gas actually taken or sold for each Party’s account. Within
sixty (60) days after the month of production, the Operator will furnish a
statement for such month showing (1) each Party’s Full Share of Current
Production, (2) the total volume of Gas actually taken or sold for each Party’s
account, (3) the difference between the volume taken by each Party and that
Party’s Full Share of Current Production, (4) the Overproduction or
Underproduction of each Party, and (5) other data as recommended by the
provisions of the Council of Petroleum Accounting Societies Bulletin No.24, as
amended or supplemented hereafter. Each Party taking Gas will promptly provide
to the Operator any data required by the Operator for preparation of the
statements required hereunder. If the Operator is notified that a Party elects
to have another Party market or otherwise dispose of its Gas, the Operator will
allocate to each such Party, in proportion to their respective Percentage
Interests, the difference between the total volume of Gas actually taken by such
Parties and their combined Full Share of Current Production.

 

Exhibit E

Page 2 of 5

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5.2 If any Party fails to provide the data required herein for four
(4) consecutive production months, the Operator, or where the Operator has
failed to provide data, another Party, may audit the production and Gas sales
and transportation volumes of the non-reporting Party to provide the required
data. Such audit shall be conducted only after reasonable notice and during
normal business hours in the office of the Party whose records are being
audited. All costs associated with such audit will be charged to the account of
the Party failing to provide the required data.

 

6.   PAYMENTS ON PRODUCTION

6.1 Each Party taking Gas shall pay or cause to be paid all production and
severance taxes due on all volumes of Gas actually taken by such Party.

6.2 Each Party shall pay or cause to be paid Royalty due with respect to Royalty
owners to whom it is accountable based on the volume of Gas actually taken for
its account.

6.3 In the event that any governmental authority requires that Royalty payments
be made on any other basis than that provided for in this Section 6, each Party
agrees to make such Royalty payments accordingly, commencing on the effective
date required by such governmental authority, and the method provided for herein
shall be thereby superseded.

 

7.   CASH SETTLEMENTS

7.1 Each Party will work cooperatively pursuant to Section 4.0 to reduce any
cumulative Gas production imbalance to as close to zero (0) as practicable. Upon
the earlier of (i) the plugging and abandonment of the last producing interval
in the Balancing Area, (ii) the termination of the Operating Agreement or any
pooling or unit agreement covering the Balancing Area, (iii) any time no Gas is
taken from the Balancing Area for a period of twelve (12) consecutive months,
(iv) all leases in the Balancing Area have expired, or (v) the end of any
calendar year, any Party may give written notice calling for cash settlement of
the Gas production imbalances among the Parties. Such notice shall be given to
all Parties in the Balancing Area.

7.2 Within sixty (60) days after the notice calling for cash settlement under
Section 7.1, the Operator will distribute to each Party a Final Gas Settlement
Statement detailing the quantity of Overproduction owed by each Overproduced
Party to each Underproduced Party and identifying the month to which such
Overproduction is attributed, pursuant to the methodology set out in
Section 7.3.

7.3 The amount of the cash settlement will be based on the proceeds received by
the Overproduced Party under an Arm’s Length Agreement for the Gas taken from
time to time by the Overproduced Party in excess of the Overproduced Party’s
Full Share of Current Production. Any Makeup Gas taken by the Underproduced
Party prior to monetary settlement hereunder will be applied to offset
Overproduction chronologically in the order of accrual.

7.4 The values used for calculating the cash settlement under Section 7.3 will
include all proceeds received for the sale of the Gas by the Overproduced Party
calculated at the Balancing Area, after deducting any production or severance
taxes paid and any Royalty actually paid by the Overproduced Party to an
Underproduced Party’s Royalty owner(s), to the extent said payments amounted to
a discharge of said Underproduced Party’s Royalty obligation, as well as any
reasonable marketing, compression, treating, gathering or transportation costs
incurred directly in connection with the sale of the Overproduction.

7.5 To the extent the Overproduced Party did not sell all Overproduction under
an Arm’s Length Agreement, the cash settlement will be based on the weighted
average price received by the Overproduced Party for any gas sold from the
Balancing Area under Arm’s Length Agreements during the months to which such
Overproduction is attributed. In the event that no sales under Arm’s Length
Agreements were made during any such month the cash settlement for such month
will be based on the spot sales prices published for the applicable geographic
area during such month in a mutually acceptable pricing bulletin.

7.6 Interest compounded at the prime rate published by the Wall Street Journal
plus one percent (1%) per annum or the maximum lawful rate of interest
applicable to the Balancing Area, whichever is less, will accrue for all amounts
due under Section 7.1, beginning the first day following the date payment is due
pursuant to Section 7.3. Such interest shall be borne by the Operator or any
Overproduced Party in the proportion that their respective delays beyond the
deadlines set out in Sections 7.2 contributed to the accrual of the interest.

7.7 In lieu of the cash settlement required by Section 7.3, an Overproduced
Party may deliver to the Underproduced Party an offer to settle its
Overproduction in-kind and at such rates, quantities, times and sources as may
be agreed upon by the Underproduced Party. If the Parties are unable to agree
upon the manner in which such in-kind settlement gas will be furnished within
sixty (60) days after the Overproduced Party’s offer to settle in kind, which
period may be extended by agreement of said Parties, the Overproduced Party
shall make a cash settlement as provided in Section 7.3. The making of an
in-kind settlement offer under this Section 7.7 will not delay the accrual of
interest on the cash settlement should the Parties fail to reach agreement on an
in-kind settlement.

 

8.   OPERATING COSTS

Nothing in this Agreement shall change or affect any Party’s obligation to pay
its proportionate share of all costs and liabilities incurred in operations on
or in connection with the Balancing Area, as its share thereof is set forth in
the Operating Agreement, irrespective of whether any Party is at any time
selling and using Gas or whether such sales or use are in proportion to its
Percentage Interest in the Balancing Area.

 

9.   LIQUIDS

The Parties shall share proportionately in and own all liquid hydrocarbons
recovered with Gas by field equipment operated for the joint account in
accordance with their Percentage Interests in the Balancing Area.

 

Exhibit E

Page 3 of 5

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10.   AUDIT RIGHTS

Notwithstanding any provision in this Agreement or any other agreement between
the Parties hereto, and further notwithstanding any termination or cancellation
of this Agreement, for a period of two (2) years from the end of the calendar
year in which any information to be furnished under Section 5 and 7 hereof is
supplied, any Party shall have the right to audit the records of any other Party
regarding quantity, including but not limited to information regarding
Btu-content. Any Underproduced Party shall have the right for a period of two
(2) years from the end of the calendar year in which any cash settlement is
received pursuant to Section 7 to audit the records of any Overproduced Party as
to all matters concerning values, including but not limited to information
regarding prices and disposition of Gas from the Balancing Area. Any such audit
shall be conducted at the expense of the Party or Parties desiring such audit,
and shall be conducted, after reasonable notice, during normal business hours in
the office of the Party whose records are being audited. Each Party hereto
agrees to maintain records as to the volumes and prices of Gas sold each month
and the volumes of Gas used in its own operations, along with the Royalty paid
on any such Gas used by a Party in its own operations. The audit rights provided
for in this Section 10 shall be in addition to those provided for in Section 5.2
of this Agreement.

 

11.   MISCELLANEOUS

11.1 As between the Parties, in the event of any conflict between the provisions
of this Agreement and the provisions of any gas sales contract, or in the event
of any conflict between the provisions of this Agreement and the provisions of
the Operating Agreement, the provisions of this Agreement shall govern.

11.2 Each Party agrees to defend, indemnify and hold harmless all other Parties
from and against any and all liability for any claims, which may be asserted by
any third party which now or hereafter stands in a contractual relationship with
such indemnifying Party and which arise out of the operation of this Agreement
or any activities of such indemnifying Party under the provisions of this
Agreement, and does further agree to save the other Parties harmless from all
judgments or damages sustained and costs incurred in connection therewith.

11.3 Except as otherwise provided in this Agreement, Operator is authorized to
administer the provisions of this Agreement, but shall have no liability to the
other Parties for losses sustained or liability incurred which arise out of or
in connection with the performance of Operator’s duties hereunder, except such
as may result from Operator’s gross negligence or willful misconduct. Operator
shall not be liable to any Underproduced Party for the failure of any
Overproduced Party (other than Operator) to pay any amounts owed pursuant to the
terms hereof.

11.4 This Agreement shall remain in full force and effect for as long as the
Operating Agreement shall remain in force and effect as to the Balancing Area,
and thereafter until the Gas accounts between the Parties are settled in full,
and shall inure to the benefit of and be binding upon the Parties hereto, and
their respective heirs, successors, legal representatives and assigns, if any.
The Parties hereto agree to give notice of the existence of this Agreement to
any successor in interest of any such Party and to provide that any such
successor shall be bound by this Agreement, and shall further make any transfer
of any interest subject to the Operating Agreement, or any part thereof, also
subject to the terms of this Agreement.

11.5 Unless the context clearly indicates otherwise, words used in the singular
include the plural, the plural includes the singular, and the neuter gender
includes the masculine and the feminine.

11.6 In the event that any “Optional” provision of this Agreement is not adopted
by the Parties to this Agreement by a typed, printed or handwritten indication,
such provision shall not form a part of this Agreement, and no inference shall
be made concerning the intent of the Parties in such event. In the event that
any “Alternative” provision of this Agreement is not so adopted by the Parties,
Alternative 1 in each such instance shall be deemed to have been adopted by the
Parties as a result of any such omission. In those cases where it is indicated
that an Optional provision may be used only if a specific Alternative is
selected: (i) an election to include said Optional provision shall not be
effective unless the Alternative in question is selected; and (ii) the election
to include said Optional provision must be expressly indicated hereon, it being
understood that the selection of an Alternative either expressly or by default
as provided herein shall not, in and of itself, constitute an election to
include an associated Optional Provision.

11.7 This Agreement shall bind the Parties in accordance with the provisions
hereof, and nothing herein shall be construed or interpreted as creating any
rights in any person or entity not a signatory hereto, or as being a stipulation
in favor of any such person or entity.

11.8 In the event Internal Revenue Service regulations require a uniform method
of computing taxable income by all Parties, each Party agrees to compute and
report income to the Internal Revenue Service based on the quantity of Gas taken
for its account (the cumulative method) in accordance with such regulations,
insofar as same relate to sales method tax computations.

 

12.   ASSIGNMENT AND RIGHTS UPON ASSIGNMENT

12.1 Subject to the provisions of Sections 12, and notwithstanding anything in
this Agreement or in the Operating Agreement to the contrary, if any Party
assigns (including any sale, exchange or other transfer) any of its working
interest in the Balancing Area when such Party is an Underproduced or
Overproduced Party, the assignment or other act of transfer shall, insofar as
the Parties hereto are concerned, include all interest of the assigning or
transferring Party in the Gas, all rights to receive or obligations to provide
or take Makeup Gas and all rights to receive or obligations to make any monetary
payment which may ultimately be due hereunder, as applicable. Operator and each
of the other Parties hereto shall thereafter treat the assignment accordingly,
and the assigning or transferring Party shall look solely to its assignee or
other transferee for any interest in the Gas or monetary payment that such Party
may have or to which it may be entitled, and shall cause its assignee or other
transferee to assume its obligations hereunder.

12.2 The provisions of this Section 12 shall not be applicable in the event any
Party mortgages its interest or disposes of its interest by merger,
reorganization, consolidation or sale of substantially all of its assets to a
subsidiary or parent company, or to any company in which any parent or
subsidiary of such Party owns a majority of the stock of such company.

 

Exhibit E

Page 4 of 5

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13.   DISPUTE RESOLUTION

The Parties agree to resolve all disputes concerning or relating to this
Agreement pursuant to the provisions of this Section. The Parties agree to
submit all disputes to binding arbitration in Denver, Colorado. The arbitration
will be conducted according to the procedure that follows. The arbitration
proceedings shall be governed by Colorado law and shall be conducted in
accordance with the rules for Non-Administered Arbitration of Business Disputes
published by The Center for Public Resources, Inc., with discovery to be
conducted in accordance with the Federal Rules of Civil Procedure, and with any
disputes over the scope of discovery to be determined by the Arbitrators (as
defined below). The arbitration shall be before a single Arbitrator chosen by
the mutual agreement of the Parties, or if no agreement as to the identity of
the Arbitrator can be reached within ten days, a three-person panel of neutral
Arbitrators, consisting of one person chosen by each Party, and the two
Arbitrators so selected choosing the third. The panel so chosen or the single
person are referred to herein as the “Arbitrators.” The Arbitrators shall
conduct a hearing no later than 60 days after submission of the matter to
arbitration, and the Arbitrators shall render a written decision within 30 days
of the hearing. At the hearing, the Parties shall present such evidence and
witnesses as they may choose, with or without counsel. Adherence to formal rules
of evidence shall not be required, but the Arbitrators shall consider any
evidence and testimony that they determine to be relevant, in accordance with
procedures that they determine to be appropriate. Any award entered in the
arbitration shall be made by a written opinion stating the reasons and basis for
the award made and any payment due pursuant to the arbitration shall be made
within 15 days of the decision by the Arbitrators. The decision of the
Arbitrators shall be binding on the Parties, final and non-appealable, and may
be filed in a court of competent jurisdiction and may be enforced by either
Party as a final judgment of such court. Each Party shall bear its own costs and
expenses of the arbitration, provided, however, that the costs of employing the
Arbitrators shall by shared equally by the Parties.

 

Exhibit E

Page 5 of 5

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EXHIBIT F

Attached to and made a part of the certain Operating Agreement executed
October 31, 2012 but dated effective November 1, 2012, by and between, Encana
Oil &Gas (USA) Inc. and Nucor Energy Holdings Inc.

NON-DISCRIMINATION AND CERTIFICATION OF

NON-SEGREGATED FACILITIES

In the performance of work under this Agreement, Operator agrees to comply with
all the provisions of Section 202 (1) to (7), inclusive, of Executive Order
11246 (30 F.R 12319), as amended by Executive Order 11758 – Employment of the
Handicapped, Equal Employment Opportunity 11701 – Employment of Veterans, and
Equal Employment Opportunity 11625 – Minority Business Enterprise.

The foregoing obligations of Operator shall be modified as necessary to comply
with current executive orders, regulations and statutes, federal or state,
relating to non-discrimination in employment.

--------------------------------------------------------------------------------

Exhibit G to

 

Operating Agreement executed October 31, 2012 but dated effective November 1,
2012 by and between Nucor Energy Holdings Inc. and Encana Oil & Gas (USA) Inc.

TAX PARTNERSHIP PROVISIONS

OF THE ENCANA-NUCOR 2012 TAX PARTNERSHIP

EIN: [TBD]

Table of Contents

 

1.

 

General Provisions

     -2-     

1.1.

  Designation of Documents.      -2-     

1.2.

  Relationship of the Parties.      -2-     

1.3.

  Priority of Provisions of this Exhibit.      -2-     

1.4.

  Survivorship.      -2-   

2.

 

Tax Reporting Partner

     -3-   

3.

 

Income Tax Compliance and Capital Accounts

     -3-     

3.1.

  Tax Returns.      -3-     

3.2.

  Fair Market Value Capital Accounts.      -3-     

3.3.

  Information Requests.      -3-     

3.4.

  Best Efforts Without Liability.      -3-     

3.5.

  Tax Matters Partner      -3-   

4.

 

Tax and FMV Capital Account Elections

     -4-     

4.1.

  General Elections.      -4-     

4.2.

  Depletion.      -5-     

4.3.

  Election Out Under Code 761(a).      -5-     

4.4.

  Consent Requirements For Subsequent Tax or FMV Capital Account Elections.     
-5-   

5.

 

Capital Contributions and FMV Capital Accounts

     -5-     

5.1.

  Capital Contributions.      -5-     

5.2.

  FMV Capital Accounts.      -5-   

6.

 

Partnership Allocations

     -6-     

6.1.

  FMV Capital Account Allocations.      -6-     

6.2.

  Tax Return and Tax Basis Capital Account Allocations.      -7-   

7.

 

Termination and Liquidating Distribution

     -8-     

7.1.

  Termination of the Tax Partnership.      -8-     

7.2.

  Balancing of FMV Capital Accounts.      -8-     

7.3.

  Deemed Sale Gain/Loss Charge Back.      -8-   

 

-1-

Encana Model Tax Partnership Agreement

--------------------------------------------------------------------------------

 

7.4.

  Deficit Make-Up Obligation and Balancing Cash Contributions.      -8-     

7.5.

  Distribution to Balance Capital Accounts.      -9-     

7.6.

  FMV Determination.      -9-     

7.7.

  Final Distribution.      -9-   

8.

 

Transfers, Indemnification, and Correspondence

     -9-     

8.1.

  Transfer of Tax Partnership Interests.      -9-     

8.2

  Farmouts, Distributions and Contributions to Other Partnerships      -9-     

8.3.

  Correspondence.      -9-   

9.

 

Elections and Changes to above Provisions

     -10-     

9.1.

  Special Tax Elections.      -10-   

 

  1. GENERAL PROVISIONS

 

  1.1. Designation of Documents.

This exhibit is referred to in, and is part of, the agreements identified above
and, if so provided, a part of any agreement to which the agreements are an
exhibit. Such agreements (including all exhibits thereto, other than this
exhibit) shall be hereinafter referred to as the “Agreement;” and this exhibit
is hereinafter referred to as the “Exhibit” or the “Tax Partnership Provisions”
(the “TPPs”). Except as may be otherwise provided in this Exhibit, terms defined
and used in the Agreement shall have the same meaning when used herein.

 

  1.2. Relationship of the Parties.

The parties to the Agreement shall be hereinafter referred to as “Party” or
“Parties.” The Parties understand and agree that the arrangement and
undertakings evidenced by the Agreement result in a partnership for purposes of
Federal income taxation and certain State income tax laws which incorporate or
follow Federal income tax principles as to tax partnerships. Such partnership
for tax purposes is hereinafter referred to as the “Tax Partnership”. For every
other purpose of the Agreement, the Parties understand and agree that their
legal relationship to each other under applicable State law with respect to all
property subject to the Agreement is one of tenants in common, or undivided
interest owners and not members in or partners of a partnership; that the
liabilities of the Parties shall be several and not joint or collective; and
that each Party shall be responsible solely for its own obligations.

 

  1.3. Priority of Provisions of this Exhibit.

If there is a conflict or inconsistency, whether direct or indirect, actual or
apparent, between the terms and conditions of this Exhibit and the terms and
conditions of the Agreement, or any other exhibit or any part thereof, the terms
and conditions of this Exhibit shall govern and control.

 

  1.4. Survivorship.

1.4.1. Any termination of the Agreement shall not affect the continuing
application of the TPPs for the termination and liquidation of the Tax
Partnership.

1.4.2. Any termination of the Agreement shall not affect the continuing
application of the TPPs for the resolution of all matters regarding Federal and
State income reporting.

 

-2-

Encana Model Tax Partnership Agreement

--------------------------------------------------------------------------------

1.4.3. These TPPs shall inure to the benefit of, and be binding upon, the
Parties hereto and their successors and assigns.

1.4.4. The effective date of the Agreement shall be the effective date of these
TPPs. The Tax Partnership shall continue in full force and effect from, and
after such date, until termination and liquidation pursuant to Sec. 7.1.

 

  2. TAX REPORTING PARTNER

Encana Oil & Gas (USA) Inc. as the Tax Reporting Partner (“TRP”) is responsible
for compliance with all tax reporting obligations of the Tax Partnership, see
Sec. 3.1, below. In the event of any change in the TRP, the Party serving as TRP
at the beginning of a given taxable year shall continue as TRP with respect to
all matters concerning such year.

 

  3. INCOME TAX COMPLIANCE AND CAPITAL ACCOUNTS

 

  3.1. Tax Returns.

The TRP shall prepare and file all required Federal and State partnership income
tax returns. Not less than thirty (30) days prior to the return due date
(including extensions), the TRP shall submit to each Party for review a copy of
the return as proposed.

 

  3.2. Fair Market Value Capital Accounts.

The TRP shall establish and maintain for each Party a fair market value (“FMV”)
capital account and a tax basis capital account. Upon request, the TRP shall
submit to each Party along with a copy of any proposed partnership income tax
return an accounting of such Party’s FMV capital account as of the end of the
return period.

 

  3.3. Information Requests.

In addition to any obligation under Sec. 2, each Party agrees to furnish to the
TRP not later than sixty (90) days before the return due date (including
extensions) such information relating to the operations conducted under the
Agreement as may be required for the proper preparation of such returns.
Similarly, each Party agrees to furnish timely to the TRP, as requested, any
information and data necessary for the preparation and/or filing of other
required reports and notifications, and for the computation of the capital
accounts. As provided in Code §6050K(c), a Party transferring its interest must
notify the TRP to allow compliance with Code §6050K(a) (see also Sec. 8.1).

 

  3.4. Best Efforts Without Liability.

The TRP and the other Party shall use their best efforts to comply with
responsibilities outlined in this Section, and with respect to the service as
TRP as outlined Sec. 2, and in doing so shall incur no liability to any other
Party.

 

  3.5. Tax Matters Partner

The provisions of this Section 3.5 shall be applicable only if the Tax
Partnership does not qualify for the “small partnership exception” from
Subchapter C of Chapter 63 of Subtitle A (the “TEFRA rules”) of the Internal
Revenue Code of 1986, as amended (the “Code”) or otherwise elects in Section 9.1
to be subject to the TEFRA Rules.

3.5.1 The TRP shall also be the Tax Matters Partner as defined in Code §6231(a)
(the “TMP”) and references to the TRP shall then include references to the TMP.

3.5.2 The TMP shall not be required to incur any expenses for the preparation
for, or pursuance of, administrative or judicial proceedings, unless the Parties
agree on a method for sharing such expenses.

 

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3.5.3 The Parties shall furnish the TMP, within two weeks from the receipt of
the request, the information the TMP may reasonably request to comply with the
requirements on furnishing information to the Internal Revenue Service.

3.5.4 The TMP shall not agree to any extension of the statute of limitations for
making assessments on behalf of the Tax Partnership without first obtaining the
written consent of all Parties. The TMP shall not bind any other Party to a
settlement agreement in tax audits without obtaining the written concurrence of
any such Party.

3.5.5 Any Party who enters in a settlement agreement with the Secretary of the
Treasury with respect to any “partnership items,” as defined in Code
§6231(a)(3), shall notify the other Parties of the terms within ninety (90) days
from the date of such settlement.

3.5.6 If any Party intends to file a notice of inconsistent treatment under Code
§6222(b), such Party shall, prior to the filing of such notice, notify the TMP
of the (actual or potential) inconsistency of the Party’s intended treatment of
a partnership item with the treatment of that item by the Tax Partnership.
Within one week of receipt the TMP shall remit copies of such notification to
the other Parties. If an inconsistency notice is filed solely because a Party
has not received a Schedule K-1 in time for filing of its income tax return, the
TMP need not be notified.

3.5.7 No Party shall file pursuant to Code §6227 a request for an administrative
adjustment of partnership items (a “RFAA”) without first notifying all other
Parties. If all other Parties agree with the requested adjustment, the TMP shall
file the RFAA on behalf of the Tax Partnership. If unanimous consent is not
obtained within thirty (30) days from such notice, or within the period required
to timely file the RFAA, if shorter, any Party, including the TMP, may file a
RFAA on its own behalf.

3.5.8 Any Party intending to file with respect to any partnership item, or any
other tax matter involving the Tax Partnership, a petition under Code § §6226,
6228, or any other provision, shall notify the other Parties prior to such
filing of the nature of the contemplated proceeding. If the TMP is the Party
intending to file such petition, such notice shall be given within a reasonable
time to allow the other Parties to participate in the choice of the forum for
such petition. If the Parties do not agree on the appropriate forum, then the
forum shall be chosen by majority vote. Each Party shall have a vote in
accordance with its percentage interest in the Tax Partnership for the year
under audit. If a majority cannot agree, the TMP shall choose the forum. If a
Party intends to seek review of any court decision rendered as a result of such
proceeding, the Party shall notify the other Parties prior to seeking such
review.

 

  4. TAX AND FMV CAPITAL ACCOUNT ELECTIONS

 

  4.1. General Elections.

For both income tax return and capital account purposes, the Tax Partnership
shall elect:

4.1.1. to deduct when incurred intangible drilling and development costs
(“IDC”);

4.1.2. to use the maximum allowable accelerated tax method and the shortest
permissible tax life for depreciation;

4.1.3. the accrual method of accounting;

4.1.4. to report income on a calendar year basis;

and the Tax Partnership shall also make any elections as specially noted in Sec.
9.1, below.

 

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  4.2. Depletion.

Solely for FMV capital account purposes, depletion shall be calculated by using
simulated cost depletion within the meaning of Treas.
Reg.§1.704-1(b)(2)(iv)(k)(2), unless the use of simulated percentage depletion
is elected in Sec. 9.1, below. The simulated cost depletion allowance shall be
determined under the principles of Code §612 and be based on the FMV capital
account basis of each property. Solely for purposes of this calculation,
remaining reserves shall be determined consistently by the TRP.

 

  4.3. Election Out Under Code §761(a).

4.3.1. The Parties agree not to elect to be excluded from the application of
Subchapter K of Chapter 1 of the Code. The TRP shall notify all Parties of an
intended election to be excluded from the application of Subchapter K of Chapter
1 of the Code not later than sixty (60) days prior to the filing date or the due
date (including extensions) for the Federal partnership income tax return,
whichever comes earlier. Even after an effective election-out, the TRP’s rights
and obligations, other than the relief from tax return filing obligations of the
Tax Partnership, shall continue.

4.3.2. After an election-out, to avoid an unintended impairment of the
election-out: The Parties will avoid, without prior coordination, any
operational changes which would terminate the qualification for the election-out
status; all Parties will monitor the continuing qualification of the Tax
Partnership for the election-out status and will notify the other Parties if, in
their opinion, a change in operations will jeopardize the election-out; and, all
Parties will use, unless agreed to by them otherwise, the cumulative gas
balancing method as described in Treas. Reg. §1.761-2(d)(3).

 

  4.4. Consent Requirements For Subsequent Tax or FMV Capital Account Elections.

Future elections, in addition to or in amendment of those in this Exhibit, must
be approved by the affirmative consent of the Parties.

 

  5. CAPITAL CONTRIBUTIONS AND FMV CAPITAL ACCOUNTS

The provisions of this Sec. 5 and any other provisions of the TPPs relating to
the maintenance of the capital accounts are intended to comply with Treas. Reg.
§1.704-1(b) and shall be interpreted and applied in a manner consistent with
such regulations.

 

  5.1. Capital Contributions.

The respective capital contributions of each Party to the Tax Partnership shall
be (a) each Party’s interest in the oil and gas lease(s), including all
associated lease and well equipment, committed to the Tax Partnership, and
(b) all amounts of money paid by each Party in connection with the acquisition,
exploration, development, and operation of the lease(s), and all other costs
characterized as contributions or expenses borne by such Party under the
Agreement. The contribution of the leases and any other properties committed to
the Tax Partnership shall be made by each Party’s agreement to hold legal title
to its interest in such leases or other property as nominee of the Tax
Partnership.

 

  5.2. FMV Capital Accounts.

The FMV capital accounts shall be increased and decreased as follows:

5.2.1. The FMV capital account of a Party shall be increased by:

(i) the amount of money and the FMV (as of the date of contribution) of any
property contributed by such Party to the Tax Partnership (net of liabilities
assumed by the Tax Partnership or to which the contributed property is subject);

 

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(ii) that Party’s share of Tax Partnership items of income or gain, allocated in
accordance with Sec. 6.1; and

(iii) that Party’s share of any Code §705(a)(1)(B) item.

5.2.2. The FMV capital account of a Party shall be decreased by:

(i) the amount of money and the FMV of property distributed to a Party (net of
liabilities assumed by such Party or to which the property is subject);

(ii) that Party’s Sec. 6.1 allocated share of Tax Partnership loss and
deductions, or items thereof; and,

(iii) that Party’s share of any Code §705(a)(2)(B) item.

5.2.3. “FMV” when it applies to property contributed by a Party to the Tax
Partnership shall be assumed, for purposes of 5.2.1, to equal the adjusted tax
basis, as defined in Code §1011, of that property unless the Parties agree
otherwise as indicated in Sec. 9.1.

5.2.4. As provided in Treas. Reg. §1.704-1(b)(2)(iv)(e), upon distribution of
Tax Partnership property to a Party the capital accounts will be adjusted to
reflect the manner in which the unrealized income, gain, loss and deduction
inherent in distributed property (not previously reflected in the FMV capital
accounts) would be allocated among the Parties if there were a taxable
disposition of such property at its FMV as of the time of distribution.
Furthermore, if so agreed to in Sec. 9.1, pursuant to the rules of Treas. Reg. §
1.704-1(b)(2)(iv)(f), the FMV capital accounts shall be revalued at certain
times to reflect value changes of the Tax Partnership property.

 

  6. PARTNERSHIP ALLOCATIONS

 

  6.1. FMV Capital Account Allocations.

Each item of income, gain, loss, or deduction shall be allocated to each Party
as follows:

6.1.1. Actual or deemed income from the sale, exchange, distribution or other
disposition of production shall be allocated to the Party entitled to such
production or the proceeds from the sale of such production. The amount received
from the sale of production and the amount of the FMV of production taken in
kind by the Parties are deemed to be identical; accordingly, such items may be
omitted from the adjustments made to the Parties’ FMV capital accounts.

6.1.2. Exploration cost, IDC, operating and maintenance cost shall be allocated
to each Party in accordance with its respective contribution, or obligation to
contribute, to such cost.

6.1.3. Depreciation shall be allocated to each Party in accordance with its
contribution, or obligation to contribute, to the cost of the underlying asset.

6.1.4. Simulated depletion shall be allocated to each Party in accordance with
its FMV capital account adjusted basis in each oil and gas property of the Tax
Partnership.

 

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6.1.5. Loss (or simulated loss) upon the sale, exchange, distribution,
abandonment or other disposition of depreciable or depletable property shall be
allocated to the Parties in the ratio of their respective FMV capital account
adjusted bases in the depreciable or depletable property.

6.1.6. Gain (or simulated gain) upon the sale, exchange, distribution, or other
disposition of depreciable or depletable property shall be allocated to the
Parties so that the FMV capital account balances of the Parties will most
closely reflect their respective percentage or fractional interests in such
property under the Agreement.

6.1.7. Costs or expenses of any other kind shall be allocated to each Party in
accordance with its respective contribution, or obligation to contribute, to
such costs or expense.

6.1.8. Any other income item shall be allocated to the Parties in accordance
with the manner in which such income is realized by each Party.

 

  6.2. Tax Return and Tax Basis Capital Account Allocations.

6.2.1. Unless otherwise expressly provided in this Sec. 6.2, the allocations of
the Tax Partnership’s items of income, gain, loss, or deduction for tax return
and tax basis capital account purposes shall follow the principles of the
allocations under Sec. 6.1. However, the Tax Partnership’s gain or loss on the
taxable disposition of a Tax Partnership property in excess of the gain or loss
under Sec. 6.1, if any, is allocated to the contributing Party to the extent of
such Party’s pre-contribution gain or loss.

6.2.2. The Parties recognize that under Code §613A(c)(7)(D) the depletion
allowance is to be computed separately by each Party. For this purpose, each
Party’s share of the adjusted tax basis in each oil and gas property shall be
equal to its contribution to the adjusted tax basis of such property.

6.2.3. Under Code §613A(c)(7)(D) gain or loss on the disposition of an oil and
gas property is to be computed separately by each Party. Pursuant to Treas. Reg.
§1.704-1(b)(4)(v), the amount realized shall be allocated as follows: (i) an
amount that represents recovery of adjusted simulated depletion basis is
allocated (without being credited to the FMV capital accounts) to the Parties in
the same proportion as the aggregate simulated depletion basis was allocated to
such Parties under Sec. 5.2; and (ii) any remaining realization is allocated in
accordance with Sec. 6.1.6.

6.2.4. Depreciation shall be allocated to each Party in accordance with its
contribution to the adjusted tax basis of the depreciable asset.

6.2.5. In accordance with Treas. Reg. §1.1245-1(e), depreciation recapture shall
be allocated, to the extent possible, among the Parties to reflect their prior
sharing of the depreciation deductions.

6.2.6. In accordance with the principles of Treas. Reg. §1.1254-5, any recapture
of IDC shall be determined and reported by each Party separately. Similarly, any
recapture of depletion shall be computed separately by each Party, in accordance
with its depletion allowance computed pursuant to Sec. 6.2.2.

6.2.7. For Tax Partnership properties with FMV capital account values different
from their adjusted tax bases the Parties intend that the allocations described
in this Section 6.2 constitute a “reasonable method” of allocating gain or loss
under Treas. Reg. §1.704-3(a)(1).

 

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6.2.8. Take-in-kind.

If checked “Yes” in Sec. 9.1, below, each Party has the right to determine the
market for its proportionate share of production. All items of income,
deductions, and credits arising from such marketing of production shall be
recognized by the Tax Partnership and shall be allocated to the Party whose
production is so marketed.

 

  7. TERMINATION AND LIQUIDATING DISTRIBUTION

 

  7.1. Termination of the Tax Partnership.

The Tax Partnership shall terminate upon the first to occur of (a) a deemed
termination of the Tax Partnership pursuant to Section 708(b)(1)(A) of the Code,
(b) the effectiveness of an election by the Parties to be excluded from the
application of Subchapter K of Chapter 1 of the Code (if and when all the
Parties affirmatively agree to make such an election) or (c) the occurrence of
any other event which causes the Tax Partnership to terminate as a matter of
law.

7.1.1. Upon termination, as provided in Code §708(b)(1)(A), the business shall
be wound-up and concluded, and the assets shall be distributed to the Parties as
described below by the end of such calendar year (or, if later, within
ninety (90) days after the date of such termination). The assets shall be valued
and distributed to the Parties in the order provided in Secs. 7.1.2, 7.5, and
7.7

7.1.2. First, all cash representing unexpended contributions by any Party and
any property in which no interest has been earned by any other Party under the
Agreement shall be returned to the contributor.

 

  7.2. Balancing of FMV Capital Accounts.

Second, the FMV capital accounts of the Parties shall be determined as described
hereafter. The TRP shall take the actions specified under Secs. 7.2 through 7.5
in order to cause the Parties’ FMV capital accounts to reflect, to the maximum
extent possible, their interests under the Agreement. These actions are
hereafter referred to as the “balancing of the FMV capital accounts” and, when
each Party’s FMV capital account balance is equal to the fair market value of
its interest under the Agreement, the FMV capital accounts of the Parties shall
be referred to as “balanced.”

 

  7.3. Deemed Sale Gain/Loss Charge Back.

The FMV of all Tax Partnership properties shall be determined and the gain or
loss for each property, which would have resulted if sold at such FMV, shall be
allocated in accordance with Secs. 6.1.5 and 6.1.6. If each Party’s FMV capital
account balance following such allocation does not correspond to the fair market
value of its respective interests under the Agreement, then income, gain, loss,
and deduction for the taxable year in which the liquidation occurs shall be
reallocated among the Parties to cause, to the maximum extent possible, the
ratio of their positive FMV capital account balances to equal the fair market
value of their respective interests under the Agreement.

 

  7.4. Deficit Make-Up Obligation and Balancing Cash Contributions.

If hereafter a Party has a negative FMV capital account balance, that is a
balance of less than zero, in accordance with Treas. Reg.
§1.704-1(b)(2)(ii)(b)(3), such Party is obligated to contribute by the end of
the taxable year or, if later, within 90 days from the Tax Partnership’s
liquidation, an amount of money to the Tax Partnership sufficient to achieve a
zero balance FMV capital account (the “Deficit Make-Up Obligation”). Moreover,
any Party may contribute an amount of cash to the Tax Partnership to facilitate
the balancing of the FMV capital accounts. If after these adjustments the FMV
capital accounts are not balanced, Sec. 7.5 shall apply.

 

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  7.5. Distribution to Balance Capital Accounts.

7.5.1. If the FMV capital accounts of the Parties are not balanced after the
application of Sec. 7.3, (i) a Party may contribute cash in the amount required
to cause its FMV capital account to be balanced, and/or (ii) if all Parties
agree, any cash or an undivided interest in certain selected properties shall be
distributed to any Party whose FMV capital account balance exceeds its interest
in the fair market value of the Tax Partnership properties under the Agreement
as necessary to cause, following such distribution, all FMV capital accounts to
be balanced with respect to the remaining Tax Partnership properties.

7.5.2. Unless Sec.7.5.1 applies, an undivided interest in each and every
property shall be distributed to one or more Parties in accordance with their
FMV capital accounts.

 

  7.6. FMV Determination.

If a property is to be valued for purposes of balancing the capital accounts and
making a distribution under this Sec. 7, the Parties shall first attempt to
agree on the FMV of the property; failing such an agreement, the TRP shall cause
a nationally recognized independent engineering firm to prepare an appraisal of
the FMV of such property.

 

  7.7. Final Distribution.

After the FMV capital accounts of the Parties have been adjusted pursuant to
Secs. 7.2 to 7.5, all remaining property and interests then held by the Tax
Partnership shall be distributed to the Parties in accordance with their
positive FMV capital account balances.

 

  8. TRANSFERS, INDEMNIFICATION, AND CORRESPONDENCE

 

  8.1. Transfer of Tax Partnership Interests.

Transfers of Tax Partnership interests shall be governed by the Agreement. A
Party transferring its interest, or any part thereof, shall notify the TRP in
writing within two (2) weeks after such transfer.

 

  8.2. Farmouts, Distributions and Contributions to Other Partnerships.

If any Party wishes to sell, farm out or exchange a portion of any property with
a third party or contribute its interest in a property to a partnership or tax
partnership with a third party to the extent allowed under the Agreement, the
other Parties shall not unreasonably withhold consent to distribute the property
from the Tax Partnership to each Party in proportion to its interest in such
property, and shall execute within 30 days such documents as are necessary to
effect the distribution; provided that the Party participating in such sale,
farm out, exchange or contribution shall fully compensate the other Party or
Parties for any accelerated recognition of gain to such Party or Parties
resulting from the distribution, including any gain recognized under Code
§704(c)(1)(B) and Code §737.

 

  8.3 Correspondence.

All correspondence relating to the preparation and filing of the Tax
Partnership’s income tax returns and capital accounts shall be sent to:

(Attach separate list, if necessary)

 

TRP    “Att to:” reference

Encana Oil & Gas (USA) Inc.

370 17th Street, Suite 1700

Denver, CO 80202

   Tax Department

Nucor Energy Holdings Inc.

1915 Rexford Road

Charlotte, NC 28211

   Tax Department

 

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  9. ELECTIONS AND CHANGES TO ABOVE PROVISIONS

 

  9.1. Special Tax Elections.

With respect to Sec. 4.1, the Parties agree (if not agreed, insert “No”):

 

a) that the Tax Partnership shall elect to account for dispositions of
depreciable assets under the general asset method to the extent permitted by
Code §168(i)(4);

     No   

b) that the Tax Partnership shall elect under Code §754 to adjust the basis of
Tax Partnership property, with the adjustments provided in Code §734 for a
distribution of property and in Code §743 for a transfer of a partnership
interest. In case of distribution of property the TRP shall adjust all tax basis
capital accounts. In the case of a transfer of a partnership interest the
acquiring party(ies) shall establish and maintain its (their) tax basis capital
account(s);

     Yes   

c) that the Tax Partnership shall elect under Code §6231 to be subject to the
TEFRA rules;

     No   

d) that the Tax Partnership shall elect under Code §709 to amortize over the
shortest permissible period all deferred organizational expenses;

     Yes   

e) that the Tax Partnership shall elect under Code §195 to amortize over the
shortest permissible period all deferred business start-up expenses;

     Yes   

f) with respect to Sec. 4.2, Depletion, the Parties agree that the Tax
Partnership shall use simulated percentage depletion instead of simulated cost
depletion;

     No   

g) with respect to Sec.5.2.4, under the rules of Treas. Reg. §
1.704-1(b)(2)(iv)(f) the Parties agree that the FMV capital accounts shall be
revalued to reflect value changes of the Tax Partnership property upon the
occurrence of the events specified in (5)(i) through (iii) of said
-1(b)(2)(iv)(f) regulations;

     Yes   

h) with respect to Sec. 6.2.8, the income attributable to take-in-kind
production will be reflected on the tax return.

     No   

With respect to Sec. 5.2.3, the FMV for the listed properties are determined on
Schedule 5.2.3, which shall describe each property that becomes subject to the
Agreement and the agreed fair market value of such property at the time it
becomes subject to the Agreement.

 

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Exhibit H

Attached to and made a part of the Operating Agreement executed October 31, 2012
but dated effective November 1, 2012, by and between, Encana Oil & Gas (USA)
Inc. and Nucor Energy Holdings Inc.

 

 

 

  A. WELL INFORMATION AND NOTIFICATION REQUIREMENTS

 

 

 

FIELD/PAD:

      

OPERATOR:

  Encana Oil & Gas (USA) Inc.   

WELL:

      

 

 

 

 

In the drilling of the above well(s), please furnish Nucor Energy Holdings Inc.
with the following notices, reports and information:

Copies by mail or email:

 

  1. Daily drilling reports by email

  2. Location plat and drilling prognosis

  3. Regulatory forms

  4. DST reports, core analysis, etc.

  5. Mud logs

  6. Wireline log prints

  7. Cased hole logs

  8. Directional surveys

  9. Daily completion reports by email

  10. Production reports by email

Notify:

 

  Mail: Nucor Energy Holdings Inc.
1915 Rexford Road
Charlotte, North Carolina 28211
Attention: Chief Financial Officer

 

  Telephone: 704-365-1321

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AAPL – FORM 610RS – 1989

 

EXHIBIT I

MODEL FORM RECORDING SUPPLEMENT TO

OPERATING AGREEMENT AND FINANCING STATEMENT

THIS AGREEMENT, entered into by and between Encana Oil & Gas (USA) Inc.
hereinafter referred to as “Operator,” and the signatory party or parties other
than Operator, hereinafter referred to individually as “Non-Operator,” and
collectively as “Non-Operators.”

WHEREAS, the parties to this agreement executed that certain BJU Carry and
Earning Agreement on October 31, 2012 but dated effective November 1, 2012 to
jointly drill Carry and/or Head’s Up Wells on lands identified on Exhibit “A”
(said lands being hereinafter called the “Contract Area”).

WHEREAS, the parties hereto executed an Operating Agreement on October 31, 2012
that is dated effective November 1, 2012 (herein the “Operating Agreement”),
covering the Contract Area for the purpose of exploring and developing such
lands, Leases and Interests for Oil and Gas; and

WHEREAS, the parties hereto have executed this agreement for the purpose of
imparting notice to all persons of the rights and obligations of the parties
under the Operating Agreement and for the further purpose of perfecting those
rights capable of perfection.

NOW, THEREFORE, in consideration of the mutual rights and obligations of the
parties hereto, it is agreed as follows:

1. This agreement supplements the Operating Agreement, which Agreement in its
entirety is incorporated herein by reference, and all terms used herein shall
have the meaning ascribed to them in the Operating Agreement.

2. The parties do hereby agree that:

A. The Interests of the parties comprising the Contract Area shall be subject to
and burdened with the terms and provisions of this agreement and the Operating
Agreement, and the parties do hereby commit such Interests to the performance
thereof.

B. The exploration and development of the Contract Area for Oil and Gas shall be
governed by the terms and provisions of the Operating Agreement, as supplemented
by this agreement.

C. All costs and liabilities incurred in operations under this agreement and the
Operating Agreement shall be borne and paid, and all equipment and materials
acquired in operations on the Contract Area shall be owned, by the parties
hereto, as provided in the Operating Agreement.

D. Regardless of the record title ownership to the Interests identified on
Exhibit “A,” all production of Oil and Gas from the Contract Area shall be owned
by the parties as provided in the Operating Agreement; provided nothing
contained in this agreement shall be deemed an assignment or cross-assignment of
interests covered hereby.

E. Each party shall pay or deliver, or cause to be paid or delivered, all
burdens on its share of the production from the Contract Area as provided in the
Operating Agreement.

F. An overriding royalty, production payment, net profits interest or other
burden payable out of production hereafter created, assignments of production
given as security for the payment of money and those overriding royalties,
production payments and other burdens payable out of production heretofore
created and defined as Subsequently Created Interests in the Operating Agreement
shall be (i) borne solely by the party whose interest is burdened therewith,
(ii) subject to suspension if a party is required to assign or relinquish to
another party an interest which is subject to such burden, and (iii) subject to
the lien and security interest hereinafter provided if the party subject to such
burden fails to pay its share of expenses chargeable hereunder and under the
Operating Agreement, all upon the terms and provisions and in the times and
manner provided by the Operating Agreement.

G. The Interests which are subject hereto may not be assigned or transferred
except in accordance with those terms, provisions and restrictions in the
Operating Agreement regulating such transfers. This agreement and the Operating
Agreement shall be binding upon and shall inure to the benefit of the parties
hereto, and their respective heirs, devisees, legal representatives, and
assigns, and the terms hereof shall be deemed to run with the or interests
included within the Contract Area.

H. The parties shall have the right to acquire an interest in wells proposed to
be abandoned, and interests to be relinquished as a result of non- participation
in subsequent operations, all in accordance with the terms and provisions of the
Operating Agreement.

I. The rights and obligations of the parties and the adjustment of interests
among them in the event of a failure or loss of title, each party’s right to
propose operations, obligations with respect to participation in operations on
the Contract Area and the consequences of a failure to participate in
operations, the rights and obligations of the parties regarding the marketing of
production, and the rights and remedies of the parties for failure to comply
with financial obligations shall be as provided in the Operating Agreement.

J. Each party’s interest under this agreement and under the Operating Agreement
shall be subject to relinquishment for its failure to participate in subsequent
operations and each party’s share of production and costs shall be reallocated
on the basis of such relinquishment, all upon the terms and provisions provided
in the Operating Agreement.

K. All other matters with respect to exploration and development of the Contract
Area and the ownership and transfer of the Interest therein shall be governed by
the terms and provisions of the Operating Agreement.

3. The parties hereby grant reciprocal liens and security interests as follows:

A. Each party grants to the other parties hereto a lien upon any interest it now
owns or hereafter acquires in Carry and/or Head’s Up Wells in the Contract Area,
and a security interest and/or purchase money security interest in any interest
it now owns or hereafter acquires in the personal property and fixtures on or
used or obtained for use in connection therewith, to secure performance of all
of its obligations under this agreement, the Operating Agreement and the Carry
and Earning Agreement, including but not limited to payment of expense, interest
and fees, the proper Disbursement of all monies paid under this agreement, the
BJU Carry and Earning Agreement and the Operating Agreement, the assignment or
relinquishment of interest in Carry and/or Head’s Up Wells as required under
this agreement, the BJU Carry and Earning Agreement and the Operating Agreement,
and the proper performance of operations under this agreement and the Operating
Agreement. Such lien and security interest granted by each party hereto shall
include such party’s working interests in the Carry and/or Head’s Up Wells now
owned or hereafter acquired and in lands pooled or unitized therewith or
otherwise becoming subject to this agreement, the BJU Carry and Earning
Agreement and the Operating Agreement, the Oil and Gas when extracted therefrom
and equipment situated thereon or used or obtained for use in connection
therewith (including, without limitation, all wells, tools, and tubular goods),
and accounts (including, without limitation, accounts arising from the sale of
production at the wellhead), contract rights, inventory and general intangibles
relating thereto or arising therefrom, and all proceeds and products of the
foregoing.

B. Each party represents and warrants to the other parties hereto that the lien
and security interest granted by such party to the other parties shall be a
first and prior lien, and each party hereby agrees to maintain the priority of
said lien and security interest against all persons acquiring an interest in
Interests covered by this agreement, the BJU Carry and Earning Agreement and the
Operating Agreement by, through or under such party. All parties acquiring an
interest in Interests covered by this agreement, the BJU Carry and Earning
Agreement and the Operating Agreement, whether by assignment, merger, mortgage,
operation of law, or otherwise, shall be deemed to have taken subject to the
lien and security interest granted by the Operating Agreement and this
instrument as to all obligations attributable to such interest under this
agreement, the BJU Carry and Earning Agreement and the Operating Agreement
whether or not such obligations arise before or after such interest is acquired.

 

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AAPL – FORM 610RS – 1989

 

C. To the extent that the parties have a security interest under the Uniform
Commercial Code of the state in which the Contract Area is situated, they shall
be entitled to exercise the rights and remedies of a secured party under the
Code to the extent provided by the BJU Carry and Earning Agreement and the
Operating Agreement. . All purchasers of production may rely on a notification
of default from the non-defaulting party or parties stating the amount due as a
result of the default, and all parties waive any recourse available against
purchasers for releasing production proceeds as provided in this paragraph.

Paragraphs D through G are intentionally omitted.

H. The above described security will be financed at the wellhead of the well or
wells located on the Contract Area and this Recording Supplement may be filed in
the land records in the County in which the Contract Area is located, and as a
financing statement in all recording offices required under the Uniform
Commercial Code or other applicable state statutes to perfect the
above-described security interest, and any party hereto may file a continuation
statement as necessary under the Uniform Commercial Code, or other state laws.

4. This agreement shall be effective as of the date of the Operating Agreement
as above recited. Upon termination of this agreement and the Operating Agreement
and the satisfaction of all obligations thereunder, Operator is authorized to
file of record in all necessary recording offices a notice of termination, and
each party hereto agrees to execute such a notice of termination as to
Operator’s interest, upon the request of Operator, if Operator has complied with
all of its financial obligations.

5. This agreement, the BJU Carry and Earning Agreement and the Operating
Agreement shall be binding upon and shall inure to the benefit of the parties
hereto and their respective heirs, devisees, legal representatives, successors
and assigns. No sale, encumbrance, transfer or other disposition shall be made
by any party of any interest in the Interests subject hereto except as expressly
permitted under the BJU Carry and Earning and the Operating Agreement and, if
permitted, shall be made expressly subject to this agreement, the BJU Carry and
Earning Agreement and the Operating Agreement and without prejudice to the
rights of the other parties. If the transfer is permitted, the assignee of an
ownership interest in any Interest shall be deemed a party to this agreement,
the BJU Carry and Earning Agreement and the Operating Agreement as to the
interest assigned from and after the effective date of the transfer of
ownership; provided, however, that the other parties shall not be required to
recognize any such sale, encumbrance, transfer or other disposition for any
purpose hereunder until thirty (30) days after they have received a copy of the
instrument of transfer or other satisfactory evidence thereof in writing from
the transferor or transferee. No assignment or other disposition of interest by
a party shall relieve such party of obligations previously incurred by such
party under this agreement, the BJU Carry and Earning Agreement or the Operating
Agreement with respect to the interest transferred, including without limitation
the obligation of a party to pay all costs attributable to an operation
conducted under this agreement, the BJU Carry and Earning Agreement and the
Operating Agreement in which such party has agreed to participate prior to
making such assignment, and the lien and security interest granted by Article
VII.B. of the Operating Agreement and hereby, shall continue to burden the
interest transferred to secure payment of any such obligation.

6. In the event of a conflict between the terms and provisions of this agreement
and the terms and provisions of the Operating Agreement, then, as between the
parties, the terms and provisions of the Operating Agreement shall control.

7. This agreement shall be binding upon each Non-Operator when this agreement or
a counterpart thereof has been executed by such Non-Operator and Operator
notwithstanding that this agreement is not then or thereafter executed by all of
the parties to which it is tendered or which are listed on Exhibit “A” as owning
an interest in the Contract Area or which own, in fact, an interest in the
Contract Area. In the event that any provision herein is illegal or
unenforceable, the remaining provisions shall not be affected, and shall be
enforced as if the illegal or unenforceable provision did not appear herein.

8. Other provisions.

-NONE-

IN WITNESS WHEREOF, this agreement shall be effective as of the 1st day of
November, 2012.

 

ATTEST OR WITNESS:    

ENCANA OIL & GAS (USA) INC.

OPERATOR

      By            

Ricardo D. Gallegos

VP, Bus. Dev. – Negotiations

& Lead Rockies & Intl. Land

    Date     ATTEST OR WITNESS:    

NUCOR ENERGY HOLDINGS INC.

NON-OPERATOR

      By                 Date    

 

-2-

--------------------------------------------------------------------------------

AAPL – FORM 610RS – 1989

 

ACKNOWLEDGEMENTS

 

STATE OF COLORADO   §   § CITY AND COUNTY OF DENVER   §

BEFORE ME, the undersigned authority, on this day personally appeared Ricardo D.
Gallegos, VP, Bus. Dev. – Negotiations & Lead Rockies & Intl. Land for ENCANA
OIL & GAS (USA) INC., known to me to be the person whose name is subscribed to
the foregoing instrument, and acknowledged to me that he executed the same for
the purposes and consideration therein expressed and in the capacity therein
stated.

GIVEN UNDER MY HAND AND OFFICIAL SEAL OF OFFICE on this 1st day of November,
2012.

 

MY COMMISSION EXPIRES:                    Notary Public in and for the State of
Colorado

 

STATE OF                        §   § COUNTY OF                        §

BEFORE ME, the undersigned authority, on this day personally appeared
                         for Nucor Energy Holdings Inc., known to me to be the
person whose name is subscribed to the foregoing instrument, and acknowledged to
me that he executed the same for the purposes and consideration therein
expressed and in the capacity therein stated.

GIVEN UNDER MY HAND AND OFFICIAL SEAL OF OFFICE on this 1st day of November,
2012

 

MY COMMISSION EXPIRES:                    Notary Public

 

-3-

--------------------------------------------------------------------------------

EXHIBIT A

Attached to and made a part of that certain Model Form Recording Supplement to
Operating Agreement and Financing Statement executed October 31, 2012 but dated
effective November 1, 2012, by and between EnCana Oil & Gas (USA) Inc. and Nucor
Energy Holdings Inc.

 

I.   DESCRIPTION OF CARRY WELLS AND HEAD’S UP WELLS SUBJECT TO THIS AGREEMENT

Carry Wells and Head’s Up Wells drilled pursuant to the BJU Carry and Earning
Agreement dated effective November 1, 2012 and Operating Agreement dated
effective November 1, 2012 between the Parties in the following described
sections:

Garfield County, Colorado

[***]

Rio Blanco County, Colorado

[***]

 

II.   RESTRICTIONS AS TO DEPTHS, FORMATIONS, PREVIOUSLY EXISTING WELLS AND
SUBSTANCES

Wellbore interest only in Carry Wells and/or Head’s Up Wells designated and
drilled pursuant to the BJU Carry and Earning Agreement executed October 31,
2012 but effective November 1, 2012 between the Parties. All interests are
limited in depth to the depth drilled in the applicable well, but not below the
base of the Formation as defined in the BJU Carry and Earning Agreement, subject
to Section 2.1 I of such agreement.

--------------------------------------------------------------------------------

Article XVI. Other Provisions

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012 by and between Encana Oil
&Gas (USA) Inc. and Nucor Energy Holdings Inc.

A. Other Provisions. This Article XVI Other Provisions is attached to and made a
part of that certain Operating Agreement (this “Agreement”) executed October 31,
2012 but effective November 1, 2012, by and between Encana Oil & Gas (USA) Inc.
and Nucor Energy Holdings Inc. In the event of a conflict between the terms and
conditions of this Article XVI and the terms and conditions of this Agreement,
the terms and conditions of this Article XVI shall control and govern the point
in conflict.

B. BJU Carry and Earning Agreement. This Agreement is subject to and burdened by
the terms and conditions of that certain BJU Carry and Earning Agreement
executed October 31, 2012 but effective November 1, 2012, between Encana Oil &
Gas (USA) Inc. and Nucor Energy Holdings Inc. (the “BJU Carry and Earning
Agreement”). Except as otherwise defined herein, all capitalized terms shall
have the meaning assigned to them in the BJU Carry and Earning Agreement. In the
event of a conflict between the terms and conditions hereof and the terms and
conditions of the BJU Carry and Earning Agreement: (i) during the term of the
BJU Carry and Earning Agreement only, the terms and conditions of the BJU Carry
and Earning Agreement shall control and govern the point in conflict; and
(ii) after the expiration of the term of the BJU Carry and Earning Agreement,
the terms and conditions of this Agreement shall control and govern the point in
conflict.

C. Conflicts. If any of the Carry Wells or Head’s Up Wells are subject to an
existing operating agreement with a third party, such existing operating
agreement shall control as to such third party. However, as between Nucor and
Encana, this Agreement and the BJU Carry and Earning Agreement shall control. In
the event of any conflict or inconsistency between the terms of this Agreement
and the BJU Carry and Earning Agreement, the BJU Carry and Earning Agreement
shall prevail to the extent of such conflict. If Nucor and/or Encana acquire the
entire interest covered by an existing third party operating agreement, then
such third party agreement shall be superseded and replaced in its entirety by
this Agreement. Carry Wells and Head’s Up Wells shall be designated under the
BJU Carry and Earning Agreement. The Parties intend that this Agreement shall
govern a Party’s election to participate in subsequent operations on the Carry
Wells. Head’s Up Wells shall be proposed under the provisions of this Agreement,
as modified by the provisions of Section 2.4 of the BJU Carry and Earning
Agreement. Carry Wells and Head’s Up Wells are defined in the BJU Carry and
Earning Agreement.

D. Burdens. Notwithstanding anything in Article III.B and C of this Agreement to
the contrary, with respect to the Carry Wells and Head’s Up Wells, the burdens
on the production shall be equal to and shall not exceed those in existence on
the effective date of the BJU Carry and Earning Agreement; provided, however,
that Nucor’s interest in Carry Wells and Head’s Up Wells shall be subject to no
overriding royalties or other burdens on production owned by Encana or its
Affiliates other than those shown on Schedule 5.2 to the BJU Carry and Earning
Agreement and other than the royalty provided for in Section 2.1 H.(iv) of the
BJU Carry and

--------------------------------------------------------------------------------

Earning Agreement. If any Party receives acreage support for such Carry and/or
Head’s Up Well from a third party, the burdens shall include any burdens
reserved by such third party, but the Party receiving such acreage support shall
not reserve any additional burdens to itself burdening such acreage support.

After the Effective Date, if Encana or Nucor creates any additional burdens on
the Property, the Party creating such additional burden shall be solely
responsible for and shall pay such additional burden; provided however, that any
mineral interest owned by Encana that is not subject to a lease will be subject
to a royalty payable to Encana of 16.67%. Subject to the foregoing sentence,
Encana shall make payment of all burdens affecting the Carry Wells and Head’s Up
Wells, and Nucor shall reimburse Encana for all burdens on the interest of
Nucor.

E. Operations. Notwithstanding anything in Article V.B of this Agreement to the
contrary, if the Operator of the Carry and/or Head’s Up Wells sells, assigns or
otherwise transfers its interest in the Carry and/or Head’s Up Wells, such
Operator’s successor-in-interest to the Carry Wells and Head’s Up Wells shall
have the right to vote for itself and elect itself as successor Operator of the
Carry Wells and Head’s Up Wells.

F. Definitions. “Reworked” or “reworking”, as used in this Agreement, shall
include perforating, cleaning out, acidizing, fracturing, testing, completing
(in the same horizon or in a deeper or shallower horizon), plugging back or any
other operation for the purpose of restoring or increasing production which does
not involve the drilling of an additional hole. In each instance in Articles
VI.B. and VI.C. in which the term “deepen”, “deeper drilling” or “deepening” are
used, the same shall also mean “deepen, sidetrack”, “deepened, sidetracked”, or
“deeper drilling, sidetracking” and “deepening, sidetracking”.

G. Well Requirements and Information Operator agrees to furnish information to
participating Non-Operator on a current basis, including but not limited to
daily drilling reports, test reports, logs and all other related reports and
data. Non-Operator has furnished Operator a list of geological requirements and
information that Non-Operator requires, and such requirements and information
are attached hereto as Exhibit H.

H. Royalties, Overriding Royalties And Other Payments. Operator shall use its
reasonable best effort to pay or cause to be paid all royalties, shut-in
royalties, minimum royalties, overriding royalties, payments out of production,
or other amounts or charges which may be or become payable out of production and
shall charge all such payments to the account of the Party or Parties
responsible therefor. However, Operator shall never be liable for a standard of
performance in making such payment or payments in excess of a reasonable good
faith effort to pay same prior to the due date; and no liability is to be
incurred for the failure to make payment within the time, in the manner and for
the amounts due through error or omission of the employees or representatives of
Operator.

I. Shut-in Production. Operator shall not shut-in Non-Operator’s share of
production from any Carry Well or a Head’s Up Well for a period of more than 90
days or due solely to market conditions without Non-Operator’s consent.

--------------------------------------------------------------------------------

J. Revision to Article V.D.: Rights and Duties of Operator. Competitive Rates
and Use of Affiliates: All wells drilled on the Contract Area shall be drilled
on a competitive basis at the prevailing market rate for such operations as
would be charged by a Third Party contractor in a bona fide arm’s length
transaction. If it so desires, Operator has the right to provide materials,
equipment and services, either directly or indirectly or through Operator, or an
affiliate of Operator, or a third party whose equipment was funded by the
Operator or an Affiliate so long as the rates charged by Operator or any such
Affiliate do not exceed the prevailing market rates in the area for comparable
services and/or equipment as would be charged by a Third Party contractor in a
bona fide arm’s length transaction. Such work shall be performed by Operator
under the same terms and conditions as are customary and usual in the area.

K. Mutuality. The Parties hereto acknowledge and declare that this Agreement is
the result of extensive negotiations between themselves. Accordingly, in the
event of any ambiguity in this Agreement, there shall be no presumption that
this instrument was prepared solely by either Party hereto.

L. Headings. The heading of the several articles and sections of this Agreement
are for convenience only, and shall not control or affect the meaning or
construction of the terms and provisions hereof.

M. Notice Of Recording Supplement. The Parties hereto agree to execute a
Recording Supplement in substantially the form attached hereto as Exhibit I to
give notice of this Agreement to third parties, and to further create, secure,
and perfect the liens and security interests provided by Article VII B. Such
Notice may be filed of record at any time by any Party hereto. The Parties may
execute additional Recording Supplements in order to accurately reflect the
current properties covered by the Operating Agreement and the current working
interests of the Parties.

N. Dispute Resolution. The Parties agree to resolve all disputes concerning or
relating to this Agreement pursuant to the provisions of this Section XVI N. The
Parties agree to submit all disputes to binding arbitration in Denver, Colorado.
The arbitration will be conducted according to the procedure that follows. The
arbitration proceedings shall be governed by Colorado law and shall be conducted
in accordance with the rules for Non-Administered Arbitration of Business
Disputes published by The Center for Public Resources, Inc., with discovery to
be conducted in accordance with the Federal Rules of Civil Procedure, and with
any disputes over the scope of discovery to be determined by the Arbitrators (as
defined below). The arbitration shall be before a single Arbitrator chosen by
the mutual agreement of the Parties, or if no agreement as to the identity of
the Arbitrator can be reached within ten days, a three person panel of neutral
Arbitrators, consisting of one person chosen by each Party, and the two
Arbitrators so selected choosing the third. The panel so chosen or the single
person are referred to herein as the “Arbitrators.” The Arbitrators shall
conduct a hearing no later than sixty (60) days after submission of the matter
to arbitration, and the Arbitrators shall render a written decision within
thirty (30) days of the hearing. At the hearing, the Parties shall present such
evidence and witnesses as they may choose, with or without counsel. Adherence to
formal rules of evidence

--------------------------------------------------------------------------------

shall not be required, but the Arbitrators shall consider any evidence and
testimony that they determine to be relevant, in accordance with procedures that
they determine to be appropriate. Any award entered in the arbitration shall be
made by a written opinion stating the reasons and basis for the award made and
any payment due pursuant to the arbitration shall be made within fifteen
(15) days of the decision by the Arbitrators. The decision of the Arbitrators
shall be binding on the Parties, final and non-appealable, and may be filed in a
court of competent jurisdiction and may be enforced by either Party as a final
judgment of such court. Each Party shall bear its own costs and expenses of the
arbitration, provided, however, that the costs of employing the Arbitrators
shall by shared equally by the Parties.

O. TLQ Expenses. Non-operator shall bear none of the capital costs for
Operator’s Temporary Living Quarters (“TLQ”) located adjacent to the Big Jimmy
Unit, but Non-operator shall bear its pro rata share of TLQ operating expenses,
including, without limitation, electricity, gas, water, maintenance, food, staff
and insurance.

P. Water Disposal. If disposal of Nucor’s share of water used for Completion
Operations or produced from the Contract Area (“Nucor Water”) is required, Nucor
shall pay its share of the costs of such disposal, including, but not limited
to, transportation costs. If there is excess Nucor Water that is released from
any dedication made by Nucor for disposal services, and Operator has sufficient
capacity on the water facilities owned or leased by Operator (including, but not
limited to, Operator’s water facility at the Middle Fork Station and disposal
wells owned or leased by Operator), then Operator shall dispose of Nucor Water
in such facilities; provided, however, that Operator shall have no obligation to
dispose of Nucor Water pro rata with any other water disposed of by Operator. If
Operator disposes of Nucor Water by injection into a disposal well owned or
leased by Operator, Nucor shall pay actual operating costs to transport and
dispose of such Nucor Water, including, but not limited to, disposal fees,
surface owner injection fees, and water treatment costs, plus $0.15 per bbl. In
lieu of disposal of Nucor Water, Operator may, but shall not have any obligation
to, use Nucor Water for completion operations for wells in which Nucor does not
have an interest, and in such case, Nucor shall not be required to pay any
operating costs to transport or dispose of such water nor the $0.15 per bbl
injection fee. Beginning on January 1, 2014, and every year thereafter on such
date, the $0.15 per bbl injection fee shall be adjusted by the percentage
increase or decrease, if any, in the Consumer Price Index for All Urban
Consumers (“CPI-U”) between the immediately preceding December and the previous
December; provided, however the injection fee shall never be less than $0.15.
The percentage adjustment shall be calculated based upon the difference between
the most recent calendar year and the previous calendar year, as published in
the U.S. Department of Labor, Bureau of Labor Statistics. If the CPI-U ceases to
be published, the parties shall use commercially reasonable efforts to negotiate
a replacement index. The provisions of this paragraph are not intended to modify
the provisions of the BJU Carry and Earning Agreement with respect to Nucor’s
obligation to pay the Nucor Cost Share.

END OF ARTICLE XVI

--------------------------------------------------------------------------------

Schedule 2.2 A

[***]

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

12987.000

  

USA COC 64805

   6/1/2001   

[***]

       0.00000000           0.00000000   

12988.000

  

USA COC 64806

   6/1/2001   

[***]

       0.00000000           0.00000000   

12989.000

  

USA COC 64815

   6/1/2001   

[***]

       0.00000000           0.00000000   

12989.000

  

USA COC 64815

   6/1/2001   

[***]

       0.00000000           0.00000000   

12989.000

  

USA COC 64815

   6/1/2001   

[***]

       0.00000000           0.00000000   

12990.000

  

USA COC 64804

   6/1/2001   

[***]

       0.00000000           0.00000000   

12992.000

  

USA COC 64836

   6/1/2001   

[***]

       0.00000000           0.00000000   

12992.000

  

USA COC 64836

   6/1/2001   

[***]

       0.00000000           0.00000000   

12995.000

  

USA COC 64835

   6/1/2001   

[***]

       0.00000000           0.00000000   

12996.000

  

USA COC 64807

   6/1/2001   

[***]

       0.00000000           0.00000000   

12997.000

  

USA COC 64814

   6/1/2001   

[***]

       0.00000000           0.00000000   

12997.000

  

USA COC 64814

   6/1/2001   

[***]

       0.00000000           0.00000000   

12997.000

  

USA COC 64814

   6/1/2001   

[***]

       0.00000000           0.00000000   

12997.000

  

USA COC 64814

   6/1/2001   

[***]

       0.00000000           0.00000000   

12997.000

  

USA COC 64814

   6/1/2001   

[***]

       0.00000000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

Page 1 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

12997.000

  

USA COC 64814

   6/1/2001   

[***]

       0.00000000           0.00000000   

12998.000

  

USA COC 64834

   6/1/2001   

[***]

       0.00000000           0.00000000   

12998.000

  

USA COC 64834

   6/1/2001   

[***]

       0.00000000           0.00000000   

12999.000

  

USA COC 64820

   6/1/2001   

[***]

       0.00000000           0.00000000   

13000.000

  

USA COC 64821

   6/1/2001   

[***]

       0.00000000           0.00000000   

13410.000

  

USA COC 65563

   12/1/2001   

[***]

       0.00000000           0.00000000   

13410.000

  

USA COC 65563

   12/1/2001   

[***]

       0.00000000           0.00000000   

13411.000

  

USA COC 65557

   12/1/2001   

[***]

       0.00000000           0.00000000   

13411.000

  

USA COC 65557

   12/1/2001   

[***]

       0.00000000           0.00000000   

13412.000

  

USA COC 65556

   12/1/2001   

[***]

       0.00000000           0.00000000   

13412.000

  

USA COC 65556

   12/1/2001   

[***]

       0.00000000           0.00000000   

13413.000

  

USA COC 65555

   12/1/2001   

[***]

       0.00000000           0.00000000   

13413.000

  

USA COC 65555

   12/1/2001   

[***]

       0.00000000           0.00000000   

13413.000

  

USA COC 65555

   12/1/2001   

[***]

       0.00000000           0.00000000   

13413.000

  

USA COC 65555

   12/1/2001   

[***]

       0.00000000           0.00000000   

13414.000

  

USA COC 65574

   12/1/2001   

[***]

       0.00000000           0.00000000   

13415.000

  

USA COC 65573

   12/1/2001   

[***]

       0.00000000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

Page 2 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

13416.000

  

USA COC 65571

   12/1/2001   

[***]

       0.00000000           0.00000000   

13417.000

  

USA COC 65570

   12/1/2001   

[***]

       0.00000000           0.00000000   

13418.000

  

USA COC 65569

   12/1/2001   

[***]

       0.00000000           0.00000000   

13419.000

  

USA COC 65568

   12/1/2001   

[***]

       0.00000000           0.00000000   

13422.000

  

USA COC 65565

   12/1/2001   

[***]

       0.00000000           0.00000000   

13423.000

  

USA COC 65564

   12/1/2001   

[***]

       0.00000000           0.00000000   

13424.000

  

USA COC 65562

   12/1/2001   

[***]

       0.00000000           0.00000000   

13425.000

  

USA COC 65561

   12/1/2001   

[***]

       0.00000000           0.00000000   

13426.000

  

USA COC 65559

   12/1/2001   

[***]

       0.00000000           0.00000000   

13426.000

  

USA COC 65559

   12/1/2001   

[***]

       0.00000000           0.00000000   

13432.000

  

USA COC 65771

   4/1/2002   

[***]

       0.00000000           0.00000000   

13432.000

  

USA COC 65771

   4/1/2002   

[***]

       0.00000000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

Page 3 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

14802.000

  

USA COC 56835

   9/1/1994   

[***]

       0.00000000           0.00000000   

14802.000

  

USA COC 56835

   9/1/1994   

[***]

       0.00000000           0.00000000   

14802.000

  

USA COC 56835

   9/1/1994   

[***]

       0.00000000           0.00000000   

14806.000

  

USA COC 56834

   11/1/1994   

[***]

       0.00000000           0.00000000   

15002.000

  

USA COC 64833

   6/1/2001   

[***]

       0.00000000           0.00000000   

15002.000

  

USA COC 64833

   6/1/2001   

[***]

       0.00000000           0.00000000   

15084.000

  

USA COC 60751

   10/1/1997   

[***]

       0.00000000           0.00000000   

15085.000

  

USA COC 60752

   10/1/1997   

[***]

       0.00000000           0.00000000   

15085.000

  

USA COC 60752

   10/1/1997   

[***]

       0.00000000           0.00000000   

15085.000

  

USA COC 60752

   10/1/1997   

[***]

       0.00000000           0.00000000   

15283.000

  

USA COC 58684

   9/1/1997   

[***]

       0.00000000           0.00000000   

15283.000

  

USA COC 58684

   9/1/1997   

[***]

       0.00000000           0.00000000   

15283.000

  

USA COC 58684

   9/1/1997   

[***]

       0.00000000           0.00000000   

15619.000

  

EXXON MOBIL

CORPORATION

   11/1/2002   

[***]

       0.00000000           0.00000000   

15619.000

  

EXXON MOBIL

CORPORATION

   11/1/2002   

[***]

       0.00000000           0.00000000   

15619.000

  

EXXON MOBIL

CORPORATION

   11/1/2002   

[***]

       0.00000000           0.00000000   

23513.000

  

USA COC 64832

   6/1/2001   

[***]

       0.00000000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

Page 4 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

23521.000

  

USA COC 66587

   3/1/2003   

[***]

       0.00000000           0.00000000   

23549.000

  

USA COC 66809

   6/1/2001   

[***]

       0.00000000           0.00000000   

23552.000

  

USA COC 57683

   3/1/1995   

[***]

       0.00000000           0.00000000   

23553.000

  

USA COC 57685

   3/1/1995   

[***]

       0.00000000           0.00000000   

23553.000

  

USA COC 57685

   3/1/1995   

[***]

       0.00000000           0.00000000   

23554.000

  

USA COC 50268

   11/1/1989   

[***]

       0.00250000           0.00000000   

23554.000

  

USA COC 50268

   11/1/1989   

[***]

       0.00250000           0.00000000   

23554.000

  

USA COC 50268

   11/1/1989   

[***]

       0.00250000           0.00000000   

23554.000

  

USA COC 50268

   11/1/1989   

[***]

       0.00250000           0.00000000   

23554.000

  

USA COC 50268

   11/1/1989   

[***]

       0.00250000           0.00000000   

23555.000

  

USA COC 56828

   11/1/1994   

[***]

       0.02750001           0.00000000   

23559.000

  

USA COC 65560

   12/1/2001   

[***]

       0.02750001           0.00000000   

23608.000

  

USA COC 50950

   2/1/1990   

[***]

       0.02750001           0.00000000   

23608.000

  

USA COC 50950

   2/1/1990   

[***]

       0.02750001           0.00000000   

23609.000

  

USA COC 57687

   3/1/1995   

[***]

       0.02750001           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

Page 5 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

23609.000

  

USA COC 57687

   3/1/1995   

[***]

       0.02750001           0.00000000   

23610.000

  

USA COC 61717

   6/1/1998   

[***]

       0.01096563           0.00000000   

23610.000

  

USA COC 61717

   6/1/1998   

[***]

       0.01096563           0.00000000   

23610.000

  

USA COC 61717

   6/1/1998   

[***]

       0.02750001           0.00000000   

23611.000

  

USA COC 57965

   6/1/1995   

[***]

       0.01083302           0.00000000   

23612.000

  

USA COC 57966

   6/1/1995   

[***]

       0.02750001           0.00000000   

23612.000

  

USA COC 57966

   6/1/1995   

[***]

       0.02750001           0.00000000   

23613.000

  

USA COC 57967

   6/1/1995   

[***]

       0.01083302           0.00000000   

23614.000

  

USA COC 57969

   6/1/1995   

[***]

       0.01083302           0.00000000   

23614.000

  

USA COC 57969

   6/1/1995   

[***]

       0.01083302           0.00000000   

23615.000

  

USA COC 57970

   6/1/1995   

[***]

       0.01083302           0.00000000   

23615.000

  

USA COC 57970

   6/1/1995   

[***]

       0.01083302           0.00000000   

23616.000

  

USA COC 57972

   6/1/1995   

[***]

       0.01083302           0.00000000   

23617.000

  

USA COC 57973

   6/1/1995   

[***]

       0.01083302           0.00000000   

23618.000

  

USA COC 57975

   6/1/1995   

[***]

       0.01083302           0.00000000   

23619.000

  

USA COC 57976

   6/1/1995   

[***]

       0.01083302           0.00000000   

23620.000

  

USA COC 59138

   6/1/1996   

[***]

       0.01083302           0.00000000   

23621.000

  

USA COC 50267

   9/1/1989   

[***]

       0.01375000           0.00000000   

23621.000

  

USA COC 50267

   9/1/1989   

[***]

       0.00250000           0.00000000   

23621.000

  

USA COC 50267

   9/1/1989   

[***]

       0.00250000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

Page 6 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

23621.000

  

USA COC 50267

   9/1/1989   

[***]

       0.00250000           0.00000000   

23622.000

  

USA COC 56829

   9/1/1994   

[***]

       0.02750001           0.00000000   

23623.000

  

USA COC 60729

   10/1/1997   

[***]

       0.01096563           0.00000000   

23623.000

  

USA COC 60729

   10/1/1997   

[***]

       0.01096563           0.00000000   

23623.000

  

USA COC 60729

   10/1/1997   

[***]

       0.02750001           0.00000000   

23624.000

  

SHELL FRONTIER

OIL & GAS

   6/1/1998   

[***]

       0.00666668           0.16666667   

23624.000

  

SHELL FRONTIER

OIL & GAS

   6/1/1998   

[***]

       0.01083302           0.16666667   

23624.000

  

SHELL FRONTIER

OIL & GAS

   6/1/1998   

[***]

       0.01083302           0.16666667   

23624.000

  

SHELL FRONTIER

OIL & GAS

   6/1/1998   

[***]

       0.01083302           0.16666667   

23624.000

  

SHELL FRONTIER

OIL & GAS

   6/1/1998   

[***]

       0.01083302           0.16666667   

28301.000

  

USA COC 67779

   2/1/2005   

[***]

       0.00000000           0.00000000   

28302.000

  

USA COC 67781

   2/1/2005   

[***]

       0.00000000           0.00000000   

28303.000

  

USA COC 67780

   2/1/2005   

[***]

       0.00000000           0.00000000   

28352.000

  

USA COC 61138

   1/1/1998   

[***]

       0.00000000           0.00000000   

28352.000

  

USA COC 61138

   1/1/1998   

[***]

       0.00000000           0.00000000   

28352.000

  

USA COC 61138

   1/1/1998   

[***]

       0.00000000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

 

Page 7 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

28353.000

  

USA COC 61137

   1/1/1998   

[***]

       0.00000000           0.00000000   

28353.000

  

USA COC 61137

   1/1/1998   

[***]

       0.00000000           0.00000000   

28354.000

  

USA COC 61136

   1/1/1998   

[***]

       0.00000000           0.00000000   

28355.000

  

USA COC 61129

   1/1/1998   

[***]

       0.00000000           0.00000000   

28356.000

  

USA COC 69620

   1/1/1998   

[***]

       0.00000000           0.00000000   

28357.000

  

USA COC 61461

   4/1/1998   

[***]

       0.00000000           0.00000000   

28358.000

  

USA COC 62562

   4/1/1999   

[***]

       0.00000000           0.00000000   

28360.000

  

USA COC 68711

   12/1/2001   

[***]

       0.00000000           0.00000000   

28369.000

  

USA COC 61460

   4/1/1998   

[***]

       0.00000000           0.00000000   

28370.000

  

USA COC 61459

   4/1/1998   

[***]

       0.00000000           0.00000000   

28373.000

  

USA COC 69557

   12/1/2001   

[***]

       0.00000000           0.00000000   

28373.000

  

USA COC 69557

   12/1/2001   

[***]

       0.00000000           0.00000000   

28374.000

  

USA COC 67295

   4/1/1978   

[***]

       0.07500000           0.00000000   

28375.000

  

USA COC 60728

   10/1/1997   

[***]

       0.00000000           0.00000000   

28376.000

  

USA COC 64819

   6/1/2001   

[***]

       0.00000000           0.00000000   

28377.000

  

USA COC 62808

   6/1/1999   

[***]

       0.00000000           0.00000000   

28378.000

  

USA COC 62803

   6/1/1999   

[***]

       0.00000000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

Page 8 of 9

--------------------------------------------------------------------------------

Schedule 5.2

Attached to and made a part of the BJU Carry and Earning Agreement executed
October 31, 2012 but effective as of November 1, 2012

by and between Encana Oil & Gas (USA) Inc. and Nucor Energy Holdings Inc.

 

Agreement Number    Agreement Name    Effective
Date    Legal Description    Encana’s
ORRI    Encana’s RI

28379.000

  

USA COC 60749

   10/1/1997   

[***]

       0.00000000           0.00000000   

28380.000

  

USA COC 60727

   10/1/1997   

[***]

       0.00000000           0.00000000   

28381.000

  

USA COC 63811

   6/1/1995   

[***]

       0.00000000           0.00000000   

28386.000

  

EXXON MOBIL

CORPORATION

   9/1/2005   

[***]

       0.00000000           0.00000000   

28386.000

  

EXXON MOBIL

CORPORATION

   9/1/2005   

[***]

       0.00000000           0.00000000   

28388.000

  

USA COC 69590

   6/1/2001   

[***]

       0.00000000           0.00000000   

28388.000

  

USA COC 69590

   6/1/2001   

[***]

       0.00000000           0.00000000   

28432.000

  

USA COC 70653

   6/1/2001   

[***]

       0.00000000           0.00000000   

28432.000

  

USA COC 70653

   6/1/2001   

[***]

       0.00000000           0.00000000   

36115.000

  

USA COC 69593

   6/1/2001   

[***]

       0.00000000           0.00000000   

36117.000

  

USA COC 70626

   1/1/1953   

[***]

       0.00000000           0.00000000   

36230.000

  

EXXON MOBIL

CORPORATION

   9/1/2009   

 

[***]

       0.00000000           0.00000000   

[***] This confidential information has been omitted and filed separately with
the Securities and Exchange Commission pursuant to a request for confidential
treatment.

 

 

Page 9 of 9