Shirley Adams, Charlene Burgess, Willie Mae Herbst Jasik, William Albert Herbst, Helen Herbst and R. May Oil & Gas Company, Ltd. v. Murphy Exploration & Production Co.-USA, a Delaware Corporation
Opinion
ACCEPTED 04-15-00118-CV FOURTH COURT OF APPEALS SAN ANTONIO, TEXAS 7/8/2015 1:17:42 PM KEITH HOTTLE CLERK
NO. 04-15-00118-CV _____________________________________________________________________________ IN THE FOURTH COURT OF APPEALS FILED IN 4th COURT OF APPEALS AT SAN ANTONIO, TEXAS SAN ANTONIO, TEXAS __________________________________________________________________________________________________________________________________________________ 07/08/15 1:17:42 PM SHIRLEY ADAMS, CHARLENE BURGESS, WILLIE MAE HERBST JASIK, KEITH E. HOTTLE Clerk WILLIAM ALBERT HERBST, HELEN HERBST AND R. MAY OIL & GAS COMPANY, LTD., Appellants V.
MURPHY EXPLORATION & PRODUCTION CO. - USA, A DELAWARE CORPORATION, Appellee _____________________________________________________________________________________ On Appeal from the 218TH District Court of Atascosa County, Texas Honorable Stella Saxon, Presiding _________________________________________________________________ APPELLANTS’ BRIEF ________________________________________________________________________________________ Mary A. Keeney State Bar No. 11170300 mkeeney@gdhm.com John B. McFarland State Bar No. 13598500 jmcfarland@gdhm.com GRAVES, DOUGHERTY, HEARON & MOODY A Professional Corporation 401 Congress Avenue, Suite 2200 Austin, Texas 78701 Telephone: (512) 480.5682 Facsimile: (512) 480.5882 ATTORNEYS FOR APPELLANTS SHIRLEY ADAMS, CHARLENE BURGESS, WILLIE MAE HERBST JASIK, WILLIAM ORAL ARGUMENT REQUESTED ALBERT HERBST, HELEN HERBST AND R. MAY OIL & GAS COMPANY, LTD. July 8, 2015 IDENTITIES OF PARTIES AND COUNSEL
The following is a complete list of all parties to the trial court's summary judgment, and the names and addresses of all trial and appellate counsel:
APPELLANTS REPRESENTATIVE/ADDRESS
Shirley Adams, Charlene Mary A. Keeney Burgess, Willie Mae Herbst State Bar No. 11170300 Jasik, William Albert Herbst, mkeeney@gdhm.com Helen Herbst and R. May Oil John B. McFarland & Gas Company, Ltd. State Bar No. 13598500 jmcfarland@gdhm.com GRAVES, DOUGHERTY, HEARON & MOODY A Professional Corporation 401 Congress Avenue, Suite 2200 Austin, Texas 78701 Telephone: (512) 480.5682 Facsimile: (512) 480.5882
APPELLEE REPRESENTATIVE/ADDRESS
Murphy Exploration & Macey R. Stokes Production Company - USA State Bar No. 00788253 Jason A. Newman Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002-4995 Office (713) 229-1369 Fax (713) 229-7869 Macey.stokes@bakerbotts.com Jason.newman@bakerbotts.com
ii TABLE OF CONTENTS
IDENTITY OF PARTIES AND COUNSEL ........................................................ ii
TABLE OF CONTENTS ....................................................................................... iii
INDEX OF AUTHORITIES.................................................................................. vi
STATEMENT OF THE CASE............................................................................. xii
STATEMENT REGARDING ORAL ARGUMENT........................................ xiii
ISSUES PRESENTED.......................................................................................... xiv
STATEMENT OF FACTS.......................................................................................1
A. The Dispute .................................................................................. 1
B. The Lawsuit.........................................................................................4
SUMMARY OF THE ARGUMENT......................................................................6
ARGUMENT............................................................................................................8
I. Standard of Review............................................................................8
II. The trial court erred in granting summary judgment for Murphy (Issue One)...................................................................10
A. The trial court violated basic rules of contract construction in holding Murphy’s well qualified, as a matter of law, as an offset well ..................11
1. The trial court failed to give meaning and effect to each provision of the Leases...............................12
iii TABLE OF CONTENTS (Continued)
2. The trial court failed to give the words of the Offset Clauses their plain meaning ................................16
3. The trial court’s decision ignores the reasons offset clauses like this one are included in leases ...............................................................................21
4. The trial court’s decision is inconsistent with the understanding in the industry.........................23
B. Murphy’s expert affidavit does not support the trial court’s summary judgment ............................. 26
1. Expert testimony is not appropriate here.......................26
2. If expert testimony is appropriate, Murphy’s expert affidavit is not conclusive for several reasons, particularly his misreading of RRC form, rules and orders....................................................... 28
3. If expert testimony is appropriate, the affidavit of the Herbsts’ expert Gregg Robertson either is conclusive as the only testimony that makes sense or at least raises a fact issue ..................................................... 34
III. The trial court erred in awarding Murphy attorney’s fees. (Issue Two) ..............................................................................36
A. The trial court had no statutory authority to award attorney’s fees.............................................................36
iv TABLE OF CONTENTS (Continued)
B. If the trial court had authority to award fees under the UDJA, it abused its discretion in awarding fees on appeal after determining fees in the trial court were not appropriate .......................40
CONCLUSION AND PRAYER ..........................................................................43
CERTIFICATE OF COMPLIANCE ....................................................................44
CERTIFICATE OF SERVICE ...............................................................................45
APPENDIX.............................................................................................................46
v INDEX OF AUTHORITIES
Cases: Page(s):
Amarillo Oil Co. v. Energy-Agri Products, Inc., 794 S.W.2d 20 (Tex. 1990) ................................................................... 30
Amoco Prod. Co. v. Alexander, 622 S.W.2d 563 (Tex. 1981) ..................................................................21, 22
Arkla Exploration Co. v. Haywood, Rice & William Venture, 863 S.W.2d 112 (Tex. App.—Texarkana 1993, writ dism’d by agr.) ............................................................................ 30
BP Am. Prod. Co. v. Zaffirini, 419 S.W.3d 485 (Tex. App.—San Antonio 2013, pet. denied) ........................................................................................9, 12, 24
Bocquet v. Herring, 972 S.W.2d 19 (Tex. 1998) ..........................................................................41
Burrow v. Arce, 997 S.W.2d 229 (Tex. 1999) ........................................................................30
CenterPoint Energy Entex v. Railroad Comm’n, 208 S.W.3d 608 (Tex. App.—Austin 2006, pet. denied) ........................17
Chapman v. Sohio Petroleum Co., 297 S.W.2d 885 (Tex. Civ.
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ACCEPTED 04-15-00118-CV FOURTH COURT OF APPEALS SAN ANTONIO, TEXAS 7/8/2015 1:17:42 PM KEITH HOTTLE CLERK
NO. 04-15-00118-CV _____________________________________________________________________________ IN THE FOURTH COURT OF APPEALS FILED IN 4th COURT OF APPEALS AT SAN ANTONIO, TEXAS SAN ANTONIO, TEXAS __________________________________________________________________________________________________________________________________________________ 07/08/15 1:17:42 PM SHIRLEY ADAMS, CHARLENE BURGESS, WILLIE MAE HERBST JASIK, KEITH E. HOTTLE Clerk WILLIAM ALBERT HERBST, HELEN HERBST AND R. MAY OIL & GAS COMPANY, LTD., Appellants V.
MURPHY EXPLORATION & PRODUCTION CO. - USA, A DELAWARE CORPORATION, Appellee _____________________________________________________________________________________ On Appeal from the 218TH District Court of Atascosa County, Texas Honorable Stella Saxon, Presiding _________________________________________________________________ APPELLANTS’ BRIEF ________________________________________________________________________________________ Mary A. Keeney State Bar No. 11170300 mkeeney@gdhm.com John B. McFarland State Bar No. 13598500 jmcfarland@gdhm.com GRAVES, DOUGHERTY, HEARON & MOODY A Professional Corporation 401 Congress Avenue, Suite 2200 Austin, Texas 78701 Telephone: (512) 480.5682 Facsimile: (512) 480.5882 ATTORNEYS FOR APPELLANTS SHIRLEY ADAMS, CHARLENE BURGESS, WILLIE MAE HERBST JASIK, WILLIAM ORAL ARGUMENT REQUESTED ALBERT HERBST, HELEN HERBST AND R. MAY OIL & GAS COMPANY, LTD. July 8, 2015 IDENTITIES OF PARTIES AND COUNSEL
The following is a complete list of all parties to the trial court's summary judgment, and the names and addresses of all trial and appellate counsel:
APPELLANTS REPRESENTATIVE/ADDRESS
Shirley Adams, Charlene Mary A. Keeney Burgess, Willie Mae Herbst State Bar No. 11170300 Jasik, William Albert Herbst, mkeeney@gdhm.com Helen Herbst and R. May Oil John B. McFarland & Gas Company, Ltd. State Bar No. 13598500 jmcfarland@gdhm.com GRAVES, DOUGHERTY, HEARON & MOODY A Professional Corporation 401 Congress Avenue, Suite 2200 Austin, Texas 78701 Telephone: (512) 480.5682 Facsimile: (512) 480.5882
APPELLEE REPRESENTATIVE/ADDRESS
Murphy Exploration & Macey R. Stokes Production Company - USA State Bar No. 00788253 Jason A. Newman Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002-4995 Office (713) 229-1369 Fax (713) 229-7869 Macey.stokes@bakerbotts.com Jason.newman@bakerbotts.com
ii TABLE OF CONTENTS
IDENTITY OF PARTIES AND COUNSEL ........................................................ ii
TABLE OF CONTENTS ....................................................................................... iii
INDEX OF AUTHORITIES.................................................................................. vi
STATEMENT OF THE CASE............................................................................. xii
STATEMENT REGARDING ORAL ARGUMENT........................................ xiii
ISSUES PRESENTED.......................................................................................... xiv
STATEMENT OF FACTS.......................................................................................1
A. The Dispute .................................................................................. 1
B. The Lawsuit.........................................................................................4
SUMMARY OF THE ARGUMENT......................................................................6
ARGUMENT............................................................................................................8
I. Standard of Review............................................................................8
II. The trial court erred in granting summary judgment for Murphy (Issue One)...................................................................10
A. The trial court violated basic rules of contract construction in holding Murphy’s well qualified, as a matter of law, as an offset well ..................11
1. The trial court failed to give meaning and effect to each provision of the Leases...............................12
iii TABLE OF CONTENTS (Continued)
2. The trial court failed to give the words of the Offset Clauses their plain meaning ................................16
3. The trial court’s decision ignores the reasons offset clauses like this one are included in leases ...............................................................................21
4. The trial court’s decision is inconsistent with the understanding in the industry.........................23
B. Murphy’s expert affidavit does not support the trial court’s summary judgment ............................. 26
1. Expert testimony is not appropriate here.......................26
2. If expert testimony is appropriate, Murphy’s expert affidavit is not conclusive for several reasons, particularly his misreading of RRC form, rules and orders....................................................... 28
3. If expert testimony is appropriate, the affidavit of the Herbsts’ expert Gregg Robertson either is conclusive as the only testimony that makes sense or at least raises a fact issue ..................................................... 34
III. The trial court erred in awarding Murphy attorney’s fees. (Issue Two) ..............................................................................36
A. The trial court had no statutory authority to award attorney’s fees.............................................................36
iv TABLE OF CONTENTS (Continued)
B. If the trial court had authority to award fees under the UDJA, it abused its discretion in awarding fees on appeal after determining fees in the trial court were not appropriate .......................40
CONCLUSION AND PRAYER ..........................................................................43
CERTIFICATE OF COMPLIANCE ....................................................................44
CERTIFICATE OF SERVICE ...............................................................................45
APPENDIX.............................................................................................................46
v INDEX OF AUTHORITIES
Cases: Page(s):
Amarillo Oil Co. v. Energy-Agri Products, Inc., 794 S.W.2d 20 (Tex. 1990) ................................................................... 30
Amoco Prod. Co. v. Alexander, 622 S.W.2d 563 (Tex. 1981) ..................................................................21, 22
Arkla Exploration Co. v. Haywood, Rice & William Venture, 863 S.W.2d 112 (Tex. App.—Texarkana 1993, writ dism’d by agr.) ............................................................................ 30
BP Am. Prod. Co. v. Zaffirini, 419 S.W.3d 485 (Tex. App.—San Antonio 2013, pet. denied) ........................................................................................9, 12, 24
Bocquet v. Herring, 972 S.W.2d 19 (Tex. 1998) ..........................................................................41
Burrow v. Arce, 997 S.W.2d 229 (Tex. 1999) ........................................................................30
CenterPoint Energy Entex v. Railroad Comm’n, 208 S.W.3d 608 (Tex. App.—Austin 2006, pet. denied) ........................17
Chapman v. Sohio Petroleum Co., 297 S.W.2d 885 (Tex. Civ. App.—El Paso 1956, writ ref’d n.r.e.) ........23
Chesapeake Exploration, L.L.C., v. Hyder, No. 14-0302, ___ S.W.3d ___, 2015 WL 3653446 (Tex. June 12, 2015)........................15
City of Keller v. Wilson, 168 S.W.3d 802 (Tex. 2005) ..........................................................................9
vi INDEX OF AUTHORITIES (Continued)
Cases: Page(s):
Commercial Union Assurance Co. v. Silva, 75 S.W.3d 1 (Tex. App.—San Antonio 2001, pet. denied) ....................13
Contreras v. Clint Ind. Sch. Dist., 347 S.W.3d 413 (Tex. App.—El Paso 2011, no pet.) ...............................27
Davis v. CIG Exploration, Inc., 789 F.2d 328 (5th Cir. 1986) .............................................................. 15
Downer v. Aquamarine Operators, Inc., 701 S.W.2d 238 (Tex. 1985) ..................................................................10, 41
Etan Indus. v. Lehmann, 359 S.W.3d 620 (Tex. 2011) ........................................................................38
GTE Southwest, Inc. v. Public Util. Comm’n, 102 S.W.3d 282 (Tex. App.—Austin 2003, pet. denied) ........................27
Green Int’l, Inc. v. Solis, 951 S.W.2d 384 (Tex. 1997) ..................................................................36, 37
Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) ......................................................12, 14, 16, 19
Holland v. Wal-Mart Stores, Inc., 1 S.W.3d 91 (Tex. 1999) ..............................................................................10
Houston Exploration Co. v. Wellington Underwriting Agencies, Ltd., 352 S.W.3d 462 (Tex. 2011) ........................................................................21
vii INDEX OF AUTHORITIES (Continued)
Cases: Page(s):
In the Interest of D.W.G., 391 S.W.3d 154 (Tex. App.—San Antonio 2012, no pet.) ........................9
KCM Financial LLC v. Bradshaw, 457 S.W.3d 70 (Tex. 2015) ............................................................................8
Killam Oil Co. v. Bruni, 806 S.W.2d 264 (Tex. App.—San Antonio 1991, writ denied)..............11
Lee M. Bass, Inc. v. Shell Western E&P, Inc., 957 S.W.2d 159 (Tex. App.—San Antonio 1997, no pet.) ......................11
Lightning Oil Co. v. Anardarko E&P Onshore, LLC, No. 04-14-00152-CV, 2014 WL 5463956 (Tex. App.—San Antonio Oct. 29, 2014, pet. filed) (mem. op.)............24
MBM Fin. Corp. v. Woodlands Operating Co., L.P., 292 S.W.3d 660 (Tex. 2009) ............................................................37, 38, 39
Menking v. Tar Heel Energy Corp., 621 S.W.2d 447 (Tex. Civ. App.—Corpus Christi 1981, no writ).........23
Mescalero Energy Inc. v. Underwriters Indemn. Gen. Agency, Inc., 56 S.W.3d 313 (Tex. App.—Houston [1st Dist.] 2001, pet. denied) ..................................................................................................26
Mungia v. Via Metro. Transit, 441 S.W.3d 542 (Tex. App.—San Antonio 2014, pet. denied) ........39, 40
Nat’l Union Fire Ins. Co. v. CBI Industries, 907 S.W.2d at 517 (Tex. 1995) ....................................................................29
viii INDEX OF AUTHORITIES (Continued)
Cases: Page(s):
Oakrock Exploration Co. v. Killam, 87 S.W.3d 685 (Tex. App.—San Antonio 2002, pet. denied) ................24
Occidental Permian Ltd. v. Helen Jones Foundation, 333 S.W.3d 392 (Tex. App.—Amarillo 2011, pet. denied) ....................29
Reagan v. Marathon Oil Co., 50 S.W.3d 70 (Tex. App-Waco 2001, no pet.)..........................................42
Rhone-Poulenc, Inc. v. Steel, 997 S.W.2d 217 (Tex. 1999) ......................................................................8, 9
Save Our Springs Alliance, Inc. v. Lazy Nine Mun. Util. Dist., 198 S.W.3d 300 (Tex. App.—Texarkana 2006, pet. denied)..................................................39, 40
Stanolind Oil & Gas Co. v. Christian, 83 S.W.2d 408 (Tex. Civ. App.—Texarkana 1935, writ ref’d)...............13
State Farm Lloyds v. Gulley, 399 S.W.3d 242 (Tex. App.—San Antonio 2012, writ denied)..............13
States v. Phillips Petroleum Co., 161 S.W.2d 366 (Tex. App.—San Antonio 1942, writ ref’d w.o.m.) ....................................................................................... 22
Sutton v. SM Energy Co., 421 S.W.3d 153 (Tex. App.—San Antonio 2013, no pet.) ......................12
Tittizer v. Union Gas Corp., 171 S.W.3d 857 (Tex. 2005) ........................................................................11
ix INDEX OF AUTHORITIES (Continued)
Cases: Page(s):
Uniroyal Goodrich Tire co. v. Martinez, 977 S.W.2d 328 (Tex. 1998) ........................................................................28
United Interests, Inc. v. Brewington, Inc., 729 S.W.2d 897 (Tex. App.—Houston [14th Dist.] 1987, writ ref’d n.r.e.) ...........................................................................................42
Washington Square Fin., LLC v. RSL Funding, LLC, 418 S.W.3d 761 (Tex. App.— Houston [14th Dist.] 2013, pet. denied) ..................................................................................................40
Woodglen Homeowners Ass’n v. Odom, 452 S.W.3d 489 (Tex. App.—San Antonio 2014, no pet.) ......................41
Yancy v. United Surgical Partners Int’l Inc., 236 S.W.3d 778, 786 at n. 6. (Tex. 2007)....................................................13
Zurich Am. Ins. Co. v. Hunt Petroleum (AEC), Inc., 157 S.W.3d 462 (Tex. App.—Houston [14th Dist.] 2004, pet. denied) ........................................................................................27
Statutes: Page(s):
Chapter 37, Tex. Civ. Prac. & Rem. Code ............................................. 37, 38 Chapter 38, Tex. Civ. Prac. & Rem. Code ............................................. 37, 38
Tex. Civ. Prac. & Rem. Code Ann. § 37.009 (Vernon 2013) ......................37, 40 Tex. Civ. Prac. & Rem. Code Ann. § 38.001 (Vernon 2013) ............................37
x INDEX OF AUTHORITIES (Continued)
Rules: Page(s):
16 Tex. Admin. Code § 3.36 ......................................................................... 34 16 Tex. Admin. Code § 3.36(c)(3)(C) ........................................................... 34 16 Tex. Admin. Code § 3.37(a)(1) ................................................................ 32 16 Tex. Admin. Code § 3.46 ......................................................................... 34
A Dictionary of Petroleum Terms (2nd ed.) ............................................. 25
Babylon Online Dictionary, Glossary of Petroleum Industry, http://dictionary.babylon.com/offset_well (last visited July 6, 2015)......................................................................... 24, 25
R. D. Langenkamp, HANDBOOK OF OIL INDUSTRY TERMS & PHRASES, p. 344 (6th ed. 2014).................................................................. 25
THE AMERICAN HERITAGE DICTIONARY OF THE ENGLISH LANGUAGE 1224 (5th ed. 2011)............................................................. 16, 17
THE NEW SHORTER OXFORD ENGLISH DICTIONARY 1985 (1993 ed.)........................................................................................................16
Williams & Meyer’s Manual of Oil and Gas Terms, p. 718 (1994 Ed.) .... 24
xi STATEMENT OF THE CASE Nature of the Case: This is a suit for breach of two oil and gas leases in which the Plaintiffs Shirley Adams, Charlene Burgess, Willie Mae Herbst Jasik, William Albert Herbst, Helen Herbst And R. May Oil & Gas Company, Ltd. (the “Herbsts”) assert that Murphy Exploration & Production Co.-USA breached its obligations under the offset well provisions in both leases.
Trial Court: Plaintiffs filed a motion for partial summary judgment on the issue of the breach. Supplemental Clerk’s Record (SCR) 401. Murphy filed a motion for partial summary judgment on that issue as well. SCR 119. After a hearing on the motions, the trial court sent a letter to the parties stating that she was granting Murphy’s motion and denying Plaintiffs’ motion. SCR 433. Instead of submitting an order on the partial summary judgment motions, Murphy submitted a Motion for Entry of Final Judgment, seeking attorney’s fees in addition to the ruling on the breach issue. SCR 379. Trial Court Disposition: Without conducting a hearing on the Motion for Entry of Final Judgment, the trial court entered judgment for Murphy. SCR 414. The judgment denied Murphy an award of trial court fees but awarded Murphy $150,000 in fees in the event Plaintiffs pursued an unsuccessful appeal. Plaintiffs filed motions for new trial and to vacate, modify or reconsider the judgment. SCR 417. After a hearing on Plaintiffs’ motions, the trial court entered an amended final judgment that reduced the amount of fees to be awarded on appeal but left intact the summary judgment for Murphy. SCR 485. Court of Appeals: Plaintiffs’ timely filed a Notice of Appeal. SCR 490.
1 All references to the Clerk’s Record are to the Supplemental Clerk’s Record and are designated “SCR.” References to the Reporter’s Record are designated “RR.” xii STATEMENT REGARDING ORAL ARGUMENT
This case presents an important issue regarding the meaning of offset
clauses in oil and gas leases. Provisions like the one here exist in many oil
and gas leases. Alfred Steinle, who drafted the leases at issue here,
submitted an amicus letter to the trial court in which he stated that he has
“prepared hundreds of leases that contain this same offset clause provision
for mineral interest owners in this part of the State.” SCR 448.
Lessors and lessees alike need to know how the rules of contract
construction apply to these offset clauses.
Oral argument will assist the Court in resolving this issue.
xiii ISSUES PRESENTED
1. The district court erred in granting Murphy’s motion for summary judgment, which allows Murphy to satisfy its obligation to drill an offset well simply by drilling a well anywhere on the Herbst Leases.
2. The district court erred in awarding Murphy attorney’s fees on appeal because (a) the district court had no authority to award fees and (b) the award was an abuse of discretion.
xiv STATEMENT OF FACTS
A. The Dispute.
The Herbsts are the royalty owners under two oil and gas leases
(“Leases”) on two 302-acre tracts of land in Atascosa County. SCR 6-7, 150-
70. Shirley Mae Herbst Adams is the owner of the executive rights in one
tract (“Shirley Tract”), and William Albert Herbst is the owner of the
executive rights in the other tract (“William Tract”).
Murphy is the lessee/operator under those Leases. SCR 120. Each
lease contains an Offset Clause, paragraph 25, which imposes obligations
on the lessee when a well is drilled on adjacent property within 467 feet of
the boundary or lease line. SCR 155, 166 (¶ 25). Murphy contends that, as
a matter of law, it has drilled an offset well in compliance with the Offset
Clauses. The Herbsts contend Murphy has not drilled such a well.
The Offset Clauses in the Herbst Leases state that, if a well “is
completed as a producer of oil and/or gas on land adjacent and contiguous
to the leased premises, and within 467 feet of the premises covered by this
lease, … [then], within 120 days after the completion date of the well or
wells on the adjacent acreage,” the lessee must either:
1 (1) commence drilling operations on the leased acreage and thereafter continue the drilling of such off-set well or wells with due diligence to a depth adequate to test the same formation from which the well or wells are producing from on the adjacent acreage; or
(2) pay the Lessor royalties as provided for in this lease as if an equivalent amount of production of oil and/or gas were being obtained from the off-set location on these leased premises as that which is being produced from the adjacent well or wells; or
(3) release an amount of acreage sufficient to constitute a spacing unit equivalent in size to the spacing unit that would be allocated under this lease to such well or wells on the adjacent lands, as to the zones or strata producing in such adjacent well.
SCR 155, 166 (¶ 25).
These provisions do not leave the lessee without protection from
having to drill an uneconomic well. The lessee has three options: drill the
offset well, pay substitute royalties equal to what the royalties would be on
the neighboring well, or release acreage. Thus, if the lessee believes
drilling the offset well is not in its best interests, it has the option either to
pay the substitute royalties or to release acreage so that the Herbsts can
either drill the well themselves or seek another operator for that part of
their mineral estate.
2 Comstock Oil & Gas, LP drilled a well, the Lucas A (the “Lucas
Well”) on the tract just to the southwest of the Shirley and William Tracts.
SCR 86-87; 114, ¶ 9; 148. The well was completed in the Eagleville (Eagle
Ford-1) Field, and began producing. The lateral of the Lucas Well is
located 350 feet from the boundaries of the Shirley and William Tracts,
thereby triggering Murphy’s duties under the Offset Clauses. SCR 121.
Murphy did not pay royalties or release acreage, as permitted under
the Offset Clauses. Instead, Murphy asserts that it exercised the first
option: it “chose to drill an offset well.” SCR 123.
Murphy claims that a horizontal well it drilled on the opposite
boundaries/lease lines of Shirley’s and William’s Tracts – the Herbst Unit B
#1H well (“Herbst B”) – qualifies as an offset well under both Leases. SCR
121-22. As permitted and drilled, the lateral of the Herbst B well runs
parallel to and approximately 450 feet from the northeast line of the Shirley
and William Tracts. SCR 148. Thus, the Herbst B well is over 2,100 feet
from the Lucas well, almost as far away from the Lucas well as it could
possibly be and still be located on the Shirley and William Tracts.
Provided below is a simplified sketch of the tracts and the horizontal
wells, which run the length of the black lines depicting them: 3 B. The Lawsuit.
The Herbsts sued Murphy for failure to comply with Murphy’s
obligations under the Offset Clauses, seeking the substitute royalties
attributable to the Lucas well and filing a motion for partial summary
judgment on the issue of the breach. SCR 5-11; 40. Murphy filed a motion
4 for partial summary judgment on the breach issue as well. SCR 119. After
a hearing on the motions, the trial court sent a letter to the parties stating
that it was granting Murphy’s motion and denying Plaintiffs’ motion. SCR
433. Instead of submitting an order on the partial summary judgment
motions as instructed, Murphy submitted a Motion for Entry of Final
Judgment, seeking attorney’s fees in addition to the ruling on the breach
issue. SCR 379.
Without conducting a hearing on the Motion for Entry of Final
Judgment, the trial court signed a judgment for Murphy. SCR 414. The
judgment crossed out Murphy’s proposed award of trial court fees but
awarded Murphy $150,000 in fees in the event the Herbsts pursued an
unsuccessful appeal. SCR 414. The Herbsts filed motions for new trial and
to vacate, modify or reconsider the judgment. SCR 417. After a hearing on
those motions, the trial court entered an amended final judgment that left
the other relief granted to Murphy intact, continued to deny trial court fees
but still awarded fees on appeal – this time in a reduced amount. SCR 485.
From that judgment, the Herbsts timely perfected this appeal. SCR
490.
5 SUMMARY OF ARGUMENT
The district court erred in granting a summary judgment that holds
Murphy’s drilling of a well more than 2,100 feet from a well on adjacent
property satisfies its obligation to drill an offset well. The purpose of an
offset well is to protect against drainage from a mineral owner’s property
by a well drilled on a neighboring tract. The plain language of the Leases
makes clear that an offset well must be in close proximity to the well it is
supposed to offset. Murphy argues there is no distance requirement. But
there is a distance that triggers Murphy’s offset obligations – that distance
is the location of a neighboring well 467 feet from Plaintiffs’ lease
boundary. Murphy claims that a well located 2,100 feet from that
neighboring well – 1,800 feet from the Leases’ boundaries – is an offset well
within the meaning of the Offset Clauses. If all Murphy had to do to satisfy
the Offset Clauses was drill a well, the offset clause would have said that.
It did not; it added the term “offset” to describe the well that had to be
drilled.
Murphy’s and the trial court’s interpretation of the Leases renders the
word “offset” meaningless. Take that word out, and the trial court’s
6 interpretation makes sense. However, all words in the Offset Clauses must
be given effect.
The trial court’s acceptance of Murphy’s interpretation of the Leases
violates basic rules of contract construction by failing to give meaning and
effect to each provision of the Leases and by failing to the give the words in
the Offset Clauses their plain meaning. The holding undermines the
purpose of explicit offset clauses, which is to eliminate the need to actually
prove drainage. The holding is also inconsistent with the understanding in
the industry of what constitutes an offset well.
Murphy relied on a conclusory expert affidavit regarding the
meaning of the term “offset well” as support for its motion. Expert
testimony is not needed to interpret the Offset Clauses. Their meaning can
be readily determined from the plain language and the context in which
the Offset Clauses were used. Provisions like those found in these Leases
are designed to explicitly define what lessees must do when a well is
drilled on adjacent property within a specific distance from the lease line.
That plain language is consistent with every dictionary and industry
definition provided by either the Herbsts or by Murphy.
7 Murphy’s expert affidavit is conclusory, misreads the regulatory
decisions on which the expert based his opinions, and is improperly based
on terms not found in the Leases. The affidavit is either no evidence at all
or, at best, raises a fact issue on the meaning of the Offset Clauses.
In addition to erring in granting summary judgment on the meaning
of the Offset Clauses, the trial court both erred and abused its discretion in
awarding appellate attorney’s fees. The trial court had no statutory
authority to award Murphy fees – the Uniform Declaratory Judgments Act
cannot be used to award fees for defending against a breach of contract
claim. In addition, even if the trial court had authority to award fees, its
decision to award fees only in the event the Herbsts pursued an
unsuccessful appeal creates an improper disincentive for the exercise of the
right of appeal and is a clear abuse of discretion.
ARGUMENT
I. Standard of Review
The Court reviews “a grant of summary judgment de novo.” KCM
Financial LLC v. Bradshaw, 457 S.W.3d 70, 79 (Tex. 2015). “Summary
judgments must stand on their own merits.” Rhone-Poulenc, Inc. v. Steel,
997 S.W.2d 217, 223 (Tex. 1999). The Court reviews the record “in the
8 light most favorable to the nonmovant, indulging every reasonable
inference and resolving any doubts against the motion.” City of Keller v.
Wilson, 168 S.W.3d 802, 824 (Tex. 2005). “On appeal, the movant
[Murphy] still bears the burden of showing that there is no genuine issue
of material fact and that the movant is entitled to judgment as a matter of
law.” Rhone-Poulenc, 997 S.W.2d at 223. See also BP Am. Prod. Co. v.
Zaffirini, 419 S.W.3d 485, 495 (Tex. App.—San Antonio 2013, pet. denied)
(same).
Because the Herbsts filed only a motion for partial summary
judgment, this Court’s precedent is that it may not review the trial court’s
denial of the Herbsts’ motion in the event it reverses the granting of the
motion for Murphy but must, instead, remand the case to the trial court.
See In the Interest of D.W.G., 391 S.W.3d 154, 164-65 (Tex. App.—San
Antonio 2012, no pet.) (holding Court cannot review denial of a motion
for partial summary judgment after reversing the trial court’s grant of the
other side’s summary judgment motion).
The issues on the award of appellate attorney’s fees are twofold. The
first issue, whether fees may be awarded under the statute on which
Murphy based its request, is a question of law to be reviewed de novo. See 9 Holland v. Wal-Mart Stores, Inc., 1 S.W.3d 91, 94 (Tex. 1999) (“The
availability of attorney's fees under a particular statute is a question of law
for the court.”). The second issue is whether the trial court abused its
discretion in awarding fees for an appeal when it had determined that it
was not appropriate to award fees incurred in the trial court because of the
Herbsts’ right to litigate their claim without being burdened with
Murphy’s attorney’s fees. Whether a trial court abused its discretion is also
a question of law but is reviewed differently from whether a court had the
statutory authority to award fees. The test for abuse of discretion is
“whether the court acted without reference to any guiding rules and
principles” or “whether the act was arbitrary or unreasonable.” Downer v.
Aquamarine Operators, Inc., 701 S.W.2d 238, 241-42 (Tex. 1985).
II. The trial court erred in granting summary judgment for Murphy. (Issue One)
The trial court’s grant of summary judgment for Murphy is wrong.
A well drilled pursuant to the Offset Clauses must be close to the well it is
designed to offset. A well drilled more than 2,100 feet from the
neighboring well is not remotely close to and does not “offset” the
neighboring well. The Offset Clauses require an offset well to be drilled
10 when the neighboring well is within 467 feet of the lease line. The Lucas
well was within 350 feet of the lease line. The trial court’s holding here is
that, as a matter of law, a well drilled more than 2,100 feet from the
neighboring well satisfies Murphy’s offset obligations. This interpretation
of the Leases is unreasonable, contrary to the plain language of the Leases
and inconsistent with the clear purpose of the Offset Clauses.
A. The trial court violated basic rules of contract construction in holding Murphy’s well qualified, as a matter of law, as an offset well.
The Herbst Leases are governed by the basic rules of contract
interpretation. Application of those rules precludes summary judgment for
Murphy.
“An oil and gas lease is a contract, and its terms are interpreted as
such.” Tittizer v. Union Gas Corp., 171 S.W.3d 857, 860 (Tex. 2005); Lee M.
Bass, Inc. v. Shell Western E&P, Inc., 957 S.W.2d 159, 161 (Tex. App.—San
Antonio 1997, no pet.). “In construing the provisions of an oil and gas
lease, the court must determine the intention of the parties, as expressed in
the lease.” Killam Oil Co. v. Bruni, 806 S.W.2d 264, 266 (Tex. App.—San
Antonio 1991, writ denied).
11 1. The trial court failed to give meaning and effect to each provision of the Leases.
A primary consideration in interpreting oil and gas leases is the need
to make sure every provision of the lease has meaning and effect. See BP
Am. Prod. Co. v. Zaffirini, 419 S.W.3d 485, 497 (Tex. App.—San Antonio
2013, pet. denied) (Courts “examine the plain language of the entire lease
agreement, consider the interaction between each of its provisions, and
seek ‘to harmonize and give effect to all the [lease] provisions.’”). As part
of the effort to give effect to all provisions, courts “examine the entire
document and consider each part with every other part so that the effect
and meaning of one part on any other part may be determined.” Heritage
Resources, Inc. v. NationsBank, 939 S.W.2d 118, 121 (Tex. 1996). Courts
“presume that the parties to a contract intend every clause to have some
effect.” Id.
An oil and gas lease typically has many provisions, and each of them
serves a different purpose. See Sutton v. SM Energy Co., 421 S.W.3d 153, 158
(Tex. App.—San Antonio 2013, no pet.) (observing different purposes of
continuous drilling clause versus retained acreage clause). Here, Offset
Clauses, which impose a duty to drill an offset well to protect against
12 drainage, have completely different purposes from the lease provisions
requiring Murphy to develop the property by drilling a well. See Stanolind
Oil & Gas Co. v. Christian, 83 S.W.2d 408, 409 (Tex. Civ. App.—Texarkana
1935, writ ref’d)2 (“[T]he implied covenant to drill offset wells for
protection of the property from drainage is a distinct obligation from the
obligation imposed by the implied covenant to develop the property.”).
“Courts should examine and consider the entire writing in an
effort to harmonize and give effect to all the provisions of the contract so
that none will be rendered meaningless.” State Farm Lloyds v. Gulley, 399
S.W.3d 242, 247 (Tex. App.—San Antonio 2012, writ denied) (emphasis
added). Courts strive to “give meaning to every sentence, clause and
word to avoid rendering any portion inoperative.” Commercial Union
Assurance Co. v. Silva, 75 S.W.3d 1, 3 (Tex. App.—San Antonio 2001, pet.
denied).
The district court’s holding that drilling a well anywhere on the
Leases satisfies Murphy’s obligations under the Offset Clauses undermines
the meaning and operative purpose of those provisions. Murphy already
2 A writ refused decision in 1935 has the same authority as a Supreme Court decision. See Yancy v. United Surgical Partners Int’l Inc., 236 S.W.3d 778, 786 at n. 6. (Tex. 2007) (stating writ refused decisions from this time period “have equal precedential value with the Texas Supreme Court's own opinions”).
13 needed to drill a well in order to hold and develop the Leases under
paragraph 2, which provides that the Leases will terminate after a period of
three years unless “operations, as hereinafter defined are conducted upon
said land . . . .” SCR 150, 161. Paragraph 6 of the Leases defines
“operations” as “drilling, testing, completing, reworking, recompleting,
deepening, plugging back or repairing of a well . . . .” SCR 152, 163.
Murphy’s position that drilling an oil well anywhere on the leased
premises can constitute an offset well works only if the term “off-set” is
removed from the Offset Clauses. The clause, with the term “off-set”
removed, would then state:
(1) commence drilling operations on the leased acreage and thereafter continue the drilling of such [] well or wells with due diligence to a depth adequate to test the same formation from which the well or wells are producing from on the adjacent acreage.
With the term “off-set” removed, Murphy’s claim that drilling a well
anywhere on the tract would satisfy Murphy’s obligations under this
provision would be correct. But courts do not write words out of
contracts. On the contrary, the rules of contract construction require
them to strive to give all words meaning and effect. See Heritage
Resources, 939 S.W.2d at 121. 14 The “effect of a lease is governed by a fair reading of its text.”
Chesapeake Exploration, L.L.C., v. Hyder, No. 14-0302, ___ S.W.3d ___, 2015
WL 3653446 at *5 (Tex. June 12, 2015). Allowing the drilling of a well
anywhere on the property to satisfy Murphy’s offset obligations is not
consistent with a “fair reading” of the Leases. Such a result defeats the
purpose of the Offset Clauses’ requirement that Murphy drill a well to
protect the lease from drainage by the neighboring well, which drainage is
presumed whenever a neighboring well is within 467 feet of the lease line.
The trial court’s decision thus undermines the separate meaning and
purpose inherent in the requirement to drill an offset well.
In support of its claim that it has the discretion to locate the well
anywhere on the Leases, Murphy cited in the trial court Davis v. CIG
Exploration, Inc., 789 F.2d 328, 332 (5th Cir. 1986). SCR 121. Davis did
not involve an offset clause and is inapposite. The passage Murphy
quoted – that the “lessee decides when to drill, where to drill, and how
many wells to drill” – must be read in context. That statement follows
the observation that “Texas law has long recognized that an oil and gas
lessor is often at the mercy of his lessee.” Id. The Offset Clauses here
15 are contractual provisions specifically designed to protect the Herbsts
from being at the “mercy” of Murphy.
2. The trial court failed to give the words of the Offset Clauses their plain meaning.
The district court’s decision is contrary to the plain, common sense
meaning of the term “offset.” When examining the language in a lease,
courts “give terms their plain, ordinary, and generally accepted meaning
unless the instrument shows that the parties used them in a technical or
different sense.” Heritage Resources, 939 S.W.2d at 121. The term “offset” is
an “ordinary” term with a “plain” meaning.
The noun “offset” is commonly understood to mean a
“counterbalance to or compensation for something else.” THE NEW
SHORTER OXFORD ENGLISH DICTIONARY 1985 (1993 ed.). See also
THE AMERICAN HERITAGE DICTIONARY OF THE ENGLISH
LANGUAGE 1224 (5th ed. 2011) (“agent, element, or thing that balances,
counteracts or compensates for something else”). The verb “offset” means
to “[s]et off as an equivalent against; cancel out by something on the other
side ….” THE NEW SHORTER OXFORD ENGLISH DICTIONARY 1985
(1993 ed.) (emphasis added). See also THE AMERICAN HERITAGE
16 DICTIONARY OF THE ENGLISH LANGUAGE 1224 (5th ed. 2011) (to
offset is “to counterbalance, counteract, or compensate for”).
Courts regularly “rely on definitions listed in commonly used
dictionaries to discern the plain meaning of terms . . . ” when, as here,
those terms are not otherwise defined. CenterPoint Energy Entex v.
Railroad Comm’n, 208 S.W.3d 608, 619 (Tex. App.—Austin 2006, pet.
denied) (interpreting a statute). Ordinary dictionary definitions are not
extrinsic evidence but, instead, confirmation of the generally accepted
plain meaning of words. These dictionary definitions indicate that an
offset well must be close to the well drilled on the neighboring tract so
that it can actually “offset” or “counterbalance” the neighboring well.
A well located 2,100 feet away from the well it is supposed to “offset”
does not comport with this plain meaning.
The common-sense reading of the Offset Clauses is that the offset
well will be close to the well drilled on the neighboring tract so that it can
truly “offset” or “counterbalance” the neighboring well. Railroad
Commission Field Rules for the Eagle Ford-1 Field where these wells are
located prohibit drilling a well “nearer than THREE HUNDRED THIRTY
(330) feet to any property line, lease line, or subdivision line” without 17 obtaining a spacing exception. See SCR 98 (RRC Final Order, Rule 2).
Therefore, Murphy could, and should, have drilled its offset well close to
that 330 foot distance. Instead, Murphy drilled a well that was situated
1,800 feet from the boundary of the lease and over 2,100 feet from the
neighboring well – a distance over 6 times longer than the distance allowed
under the applicable RRC Field Rules.
In fact, Murphy drilled the well within 450 feet of the opposite side of
the Shirley and William tracts – almost as far away from the Lucas well as
it possibly could have drilled. A well situated along the opposite boundary
– the far northeastern edge of the leased premises – does not constitute an
offset well. Were that a proper reading of these Offset Clauses, a well on
the opposite end of a 30,000 acre lease – some 5 or 6 miles away – could be
considered an offset well. These provisions are common in oil and gas
leases; the trial court’s ruling, if affirmed, will likely affect tracts much
larger than the Herbsts. Mr. Steinle, a local attorney and scrivener of these
leases, informed the trial court that he has “prepared hundreds of leases”
with these provisions. SCR 448. Under the “plain, ordinary, and generally
accepted meaning” of the term offset well, Murphy has not complied with
18 its offset obligations under either of the two Leases. Heritage Resources, 939
S.W.2d at 121.
Murphy claims it placed the well where it did because it believed a
well located on the northeast side of the properties would be more
productive than a well drilled on the southwest side closest to the Lucas
well. SCR 132-33, ¶ 12 (claiming the Herbst B well was in “the best location
to optimize production from the Lease”). The Herbsts are not challenging
Murphy’s right to choose to drill a well where the Herbst B well is located.
But that well does not satisfy the Offset Clauses. Murphy needed either to
drill another well close to the Lucas well or utilize one of its two other
options – pay substitute royalties or release acreage so that the Herbsts
could lease that land to someone else. Murphy did neither but, instead,
claimed a well it already planned to drill – the Herbst B – constituted an
offset well. Under the plain, common-sense meaning of the Offset Clauses,
it does not.
Murphy also claims that it satisfied its drilling obligation because the
well was “drilled ‘to a depth adequate to test the same formation from
which the well or wells are producing from on the adjacent acreage.’” SCR
123 (quoting paragraph 25 of the Leases). The Herbsts have never 19 challenged the adequacy of the depth of the Herbst B well. But drilling a
well deep enough does not equate to drilling a well close enough. Murphy
has provided no evidence that its drilling of the Herbst B well in any way
protected against drainage from the Lucas well. On the contrary, it
asserted in the trial court that no drainage has occurred, suggesting that as
an additional reason why it could put the well anywhere it chose. SCR 296
(“the Eagle Ford does not contain freely migrating hydrocarbons in a
common reservoir that can be drained from the adjacent lease”). Whether
drainage is, in fact, occurring from the Lucas well is beside the point. The
very purpose of the Offset Clauses is to eliminate the need for proof of
drainage by presuming drainage is occurring whenever a neighboring well
is located within 467 feet of the lease line. If Murphy believed no drainage
was possible in the Eagle Ford, Murphy should not have accepted leases
with these offset provisions.
Murphy also argued in the trial court that it could locate the well
anywhere on the Leases because the Leases do not specify the distance
from the boundary for the offset well. SCR 125. This argument ignores the
fact that the Leases do define the distance for the neighboring well and
presume drainage whenever that neighboring well is within 467 feet of the 20 lease line. The logical inference from the presumption created by these
provisions is that the offset well must be at least within 467 feet on the
other side the boundary. No logic supports holding, as a matter of law,
that a well 1,800 feet from the boundary satisfies the offset well obligation.
3. The trial court’s decision ignores the reasons offset clauses like this one are included in leases.
The trial court’s decision here undermines the very purpose for
which offset clauses like the ones here are included in oil and gas leases.
Consideration of the context in which offset clauses like these came to be
included in leases is relevant to interpreting them. See Houston Exploration
Co. v. Wellington Underwriting Agencies, Ltd., 352 S.W.3d 462, 469 (Tex. 2011)
(parol evidence rule “does not prohibit consideration of surrounding
circumstances that inform, rather than vary from or contradict, the contract
text”). Courts consider the “setting in which the contract was negotiated
and other objectively determinable factors that give a context to the
transaction between the parties.” Id.
Texas law has long recognized that an implied covenant exists in an
oil and gas lease to protect the lessor from drainage of the oil and gas
under his tract by a well drilled on neighboring property. See Amoco Prod.
21 Co. v. Alexander, 622 S.W.2d 563, 568 (Tex. 1981). Under such an implied
covenant, lessees have the duty of a “reasonably prudent operator to
protect from field-wide drainage.” Id. A lessee’s duty to protect against
drainage even extends to seeking permission from the Texas Railroad
Commission (RRC), which regulates the oil and gas industry, so as to locate
a well closer to the lease boundary than RRC rules would ordinarily
permit. Id. (stating duties under the implied covenant could include
“seeking Rule 37 exceptions from the Railroad Commission”).
Over the course of oil and gas development in Texas, many leases
incorporated the implied covenant with express language requiring
protection against drainage. These leases typically required a lessee to drill
only if a “reasonably prudent operator” would choose to drill the offset
well. Thus, under both these express lease provisions as well as the
implied covenant, the lessor was required to establish that the lessee failed
to act as a reasonably prudent operator. To do so, the lessor had to show
not only that actual drainage was occurring but also that the lessee could
make a profit from the offset well. See States v. Phillips Petroleum Co., 161
S.W.2d 366, 367-68 (Tex. App.—San Antonio 1942, writ ref’d w.o.m.)
(affirming judgment for lessee because lessor failed to show lessee could 22 make a profit from the offset well); Menking v. Tar Heel Energy Corp., 621
S.W.2d 447, 449 (Tex. Civ. App.—Corpus Christi 1981, no writ) (same
holding); Chapman v. Sohio Petroleum Co., 297 S.W.2d 885, 886-87 (Tex. Civ.
App.—El Paso 1956, writ ref’d n.r.e.)(same holding).
As these cases illustrate, lessors often failed to prevail in suits based
on either the implied or the express covenant because of the difficulty of
proving either that drainage had, in fact, occurred or that the offset well
would be profitable to the lessee.
The Offset Clauses in the Herbst Leases eliminate the proof problems
that arose in these earlier cases by eliminating the need to prove either that
drainage was actually occurring or that drilling a well would be profitable.
Instead, under these provisions, the lessee’s duties are explicit. Murphy’s
argument that proximity to the neighboring well is irrelevant because there
is no risk of drainage ignores this context and undermines the very reasons
these explicit provisions were included in the Leases.
4. The trial court’s decision is inconsistent with the understanding in the industry.
Courts properly use the generally accepted meaning that a term has
been given in the oil and gas industry, if it is consistent with the plain
23 language of the lease. See BP Am. Prod. Co. v. Zaffirini, 419 S.W.3d at 497.
(“If a lease term has a generally accepted meaning in the oil and gas
industry, [courts] use its generally accepted meaning.”). Provisions
addressing “offset well obligations” are “common terms” in oil and gas
leases. Oakrock Exploration Co. v. Killam, 87 S.W.3d 685, 691 (Tex. App.—
San Antonio 2002, pet. denied). See also Lightning Oil Co. v. Anardarko E&P
Onshore, LLC, No. 04-14-00152-CV, 2014 WL 5463956 (Tex. App.—San
Antonio Oct. 29, 2014, pet. filed) (mem. op.) (recent case with offset well
provisions at issue).
Contrary to Murphy’s position and the district court’s holding,
industry definitions are consistent with the dictionary definitions for
what constitutes an “offset.” In Williams & Meyer’s Manual of Oil and
Gas Terms, p. 718 (1994 Ed.), an offset well is defined as a “well drilled
on one tract of land to prevent the drainage of oil or gas to an adjoining
tract of land, on which a well is being drilled or is already in
production.” The common industry understanding of an offset well
requirement in a lease is that the well will be as close as regulations
permit it to be to the well it is “offsetting.” See Babylon Online
Dictionary, Glossary of Petroleum Industry, 24 http://dictionary.babylon.com/offset_well (last visited July 6, 2015)
(defining an offset well as “(1) A well drilled on the next location to the
original well. The distance from the first well to the offset well depends
upon spacing regulations and whether the original well produces oil or
gas. (2) A well drilled on one tract of land to prevent the Drainage of oil
or gas to an adjoining tract where a well is being drilled or is already
producing”). See also R. D. Langenkamp, HANDBOOK OF OIL INDUSTRY
TERMS & PHRASES, p. 344 (6th ed. 2014) (same definition).
Murphy’s expert, John McBeath, claimed he had never seen these
definitions before and relied, instead, on his “personal copy of ‘A
Dictionary of Petroleum Terms’ 2nd ed.” SCR 178, ¶ 21. He stated this
dictionary defined an offset well as “a well drilled on a tract of land
next to another owner’s tract on which there is a producing well.” SCR
178, ¶ 21 (emphasis added). This definition similarly connotes
proximity – describing the offset well as one “next to” another owner’s
tract. A well 1,800 feet from the lease boundary is not “next to” the
other owner’s tract.
25 B. Murphy’s expert affidavit does not support the trial court’s summary judgment.
In its motion for summary judgment, Murphy contended extrinsic
evidence provided by an expert was necessary to address what Murphy
claimed were industry standards. SCR 123-27. Extrinsic, expert testimony
is not necessary to determine that Murphy failed to comply with its
obligations under the Offset Clauses. Industry understanding can be
determined without resort to Murphy’s expert affidavit. If, however,
expert testimony is appropriate, Murphy’s expert’s testimony is in no way
conclusive but is, instead, both illogical and contradicted by the very RRC
documents on which he relies. It is also directly controverted by the
Herbsts’ expert, Gregg Robertson, who has over 35 years of experience in
the oil and gas industry. SCR 238-42.
1. Expert testimony is not appropriate here.
In the trial court, Murphy relied on Mescalero Energy Inc. v.
Underwriters Indemn. Gen. Agency, Inc., 56 S.W.3d 313, 320 (Tex. App.—
Houston [1st Dist.] 2001, pet. denied), as support for its reliance on
expert testimony. SCR 123-25. Mescalero, however, allowed expert
testimony only because the contract term was ambiguous. At issue was
26 an insurance policy that provided coverage for underground blowouts
by oil and gas wells and defined a blowout as a sudden flow of oil, gas
or water “between two or more separate formations.” Id. at 316. The
court held that the policy was ambiguous. Id. at 325.
Mescalero recognizes that when the meaning of a word is plain,
expert testimony is not proper. “A term not specifically defined by [the
contract] must be given its plain, ordinary and generally accepted
meaning, unless consideration of the [contract] shows it to have been
used in a different sense.” Id. at 320. The word “offset” has a plain
dictionary meaning; it is not ambiguous.
The other cases Murphy cited in the trial court (SCR at 124) also
do not support use of expert testimony. Contreras v. Clint Ind. Sch. Dist.,
347 S.W.3d 413, 420 (Tex. App.—El Paso 2011, no pet.), involved an
expert affidavit to explain the medical term “complication” in a
settlement agreement – a word not readily understood in the medical
context. Zurich Am. Ins. Co. v. Hunt Petroleum (AEC), Inc., 157 S.W.3d
462, 467 (Tex. App.—Houston [14th Dist.] 2004, pet. denied), involved
an ambiguous contract and, therefore, a fact issue. GTE Southwest, Inc.
v. Public Util. Comm’n, 102 S.W.3d 282 (Tex. App.—Austin 2003, pet. 27 denied), did not involve expert testimony but merely consideration of
the “‘commercial context of the transaction.’” Id. at 295. The
“commercial context” of offset wells is clear from the language of the
Leases: they must be drilled – or the lessee must pay substitute
royalties or release acreage – whenever a neighboring well is within 467
feet of the Herbsts’ lands.
2. If expert testimony is appropriate, Murphy’s expert affidavit is not conclusive for several reasons, particularly his misreading of RRC form, rules and orders.
Even if expert testimony were appropriate, Murphy’s expert
affidavit from Mr. McBeath cannot establish Murphy’s interpretation of
the Offset Clauses as a matter of law for several reasons. First, opinion
testimony generally raises only a question of fact. Uniroyal Goodrich
Tire co. v. Martinez, 977 S.W.2d 328, 338 (Tex. 1998) (“The general rule is
that opinion testimony, even when uncontroverted, does not bind the
jury unless the subject matter is one for experts alone.”).
Second, Mr. McBeath’s testimony contradicts the plain language
in the Leases. Mr. McBeath’s opinion is that any well anywhere on the
Leases constitutes an offset well. SCR 176 ¶ 13. Expert testimony that
“does not comport with the plain language of the leases” is “no
28 evidence.” Occidental Permian Ltd. v. Helen Jones Foundation, 333 S.W.3d
392, 399 (Tex. App.—Amarillo 2011, pet. denied). See also Nat’l Union
Fire Ins. Co. v. CBI Industries, 907 S.W.2d at 517, 521 (Tex. 1995)
(extrinsic evidence inadmissible to “contradict or vary the meaning of
the explicit language”).
To support his claims regarding what constitutes an offset well,
Mr. McBeath introduces terms not found in the Leases. He asserts that
a “direct offset well” is a “specialized term within the oil and gas
industry, and is commonly understood to be a well that is located
directly across a lease line or other legal boundary.” SCR 176 at ¶ 13.
He also refers to “immediate offset wells” – another term not found in
the Leases – and claims this means the same thing as a “direct offset
well.” Id. In other words, he suggests that, unless the term “offset
well” has the adjective “direct” or “immediate” preceding it, the offset
well need not be in close proximity to the well it is offsetting.
Third, Mr. McBeath has nothing more than his own bare opinion
to support his claims that these terms are commonly used in the
industry. “[I]t is the basis of the witness’s opinion, and not the
witness’s qualifications or his bare opinions alone, that can settle an 29 issue as a matter of law; a claim will not stand or fall on the mere ipse
dixit of a credentialed witness.” Burrow v. Arce, 997 S.W.2d 229, 235
(Tex. 1999).
Mr. McBeath cites and relies on, but does not attach to his
affidavit, numerous RRC Rules, Orders and a form and suggests these
RRC documents support his differentiation between “regular” offset
wells and “direct” or “immediate” offset wells. SCR 176-77. The RRC
rules, orders, and form do not support the special meanings Mr.
McBeath has attempted to give to the term offset well. The RRC has
“no authority to determine title and ownership of property, to construe
a lease . . . .” Arkla Exploration Co. v. Haywood, Rice & William Venture,
863 S.W.2d 112, 117 (Tex. App.—Texarkana 1993, writ dism’d by agr.)
(citing Amarillo Oil Co. v. Energy-Agri Products, Inc., 794 S.W.2d 20, 26
(Tex. 1990)).
More important, these RRC documents, placed in the record by
the Herbsts, do not support Mr. McBeath’s strained interpretation of
what constitutes an offset well. SCR 244-89. Mr. McBeath states that
the RRC’s H-1 form “shows that the term ‘offset well’ is understood
within the industry to describe any well drilled on adjacent property” 30 and asserts the form “requires offset wells within 1/2 mile of the
subject well to be identified on a map.” SCR 176, ¶ 15. Mr. McBeath
misrepresents the form. Quoted below is the only portion of Form H-1
that mentions offset wells:
7. Plat of Leases, Notice and Hearings
(a) Plat of Leases. Attach a plat of leases showing producing wells, injection wells, offset wells and identifying ownership of all surrounding leases within one-half (1/2) mile.
SCR 245.
This provision does not indicate that an offset well is any well
located within one-half mile of the lease. The one-half mile refers to the
leases in the vicinity, not to the locations of the wells within those
leases. Moreover, the form distinguishes between “producing wells”
and “offset wells,” indicating that an offset well is not the same thing as
a producing well. In other words, this form undermines Mr. McBeath’s
claim that any producing well is an offset well.
Similarly, a review of the examiner’s proposal for decision and the
RRC’s final order in RRC Oil and Gas Docket No. XX-XXXXXXX – another
RRC document relied on by Mr. McBeath – shows that the terms “direct
31 offset well” and “immediate offset well” are not used at all in the
discussion. SCR 247-55. The sole reference to the term offset well is in
the examiner’s recommendation that the requested disposal well be
allowed only if the applicant can demonstrate “through plume analysis
and offset well construction/plugging evaluation that the injected
fluids will be confined to the proposed disposal zone.” See SCR 247 ¶ 2.
This statement does not support Mr. McBeath’s opinion.
RRC Rule 37 decisions, also relied on by Mr. McBeath, do not
support his claim that “direct” or “immediate” offset wells are
somehow closer to the boundary line or otherwise different from “offset
wells.” RRC Rule 37 is a spacing rule that, absent special field rules,
requires operators to drill wells no closer than 467 feet from the
boundary of the lease. See 16 Tex. Admin. Code § 3.37(a)(1). Operators
may seek what is called a Rule 37 exception, which allows operators to
drill wells closer to a boundary line than the applicable field rules
permit, if the operators can show drainage resulting from a neighboring
well.
Rule 37 decisions do not assign specialized definitions to describe
the offset wells that are allowed to prevent drainage. For example, in 32 RRC Docket No. 0213270, the operator sought a Rule 37 exception to
locate an offset well 349 feet from the nearest lease line in a field where
the normal distance was 467 feet. SCR 259. The examiner granted the
exception. He used the term offset to describe both the neighboring
well that was draining the tract and also a well that could offset the
draining well. See SCR 259. Examiners sometimes use adjectives such
as “nearby” or “direct” (SCR 268), but there is no special significance
ascribed to those words.
What is clear from all of the Rule 37 decisions Mr. McBeath cites,
which require proof of actual drainage to drill closer to the boundary
line than the RRC field rules otherwise permit, is that an offset well is
always in close proximity to the boundary line. Operators sought
permission in these cases to locate the offset wells 254 feet (SCR 265),
100 feet (SCR 273), 349 feet (SCR 259), and 75 feet (SCR 281) from the
boundary/lease line. These RRC orders hurt Murphy’s position,
illustrating the unreasonableness of Mr. McBeath’s attempt to
characterize a well 1,800 feet from the boundary line as an offset well.
The RRC rules Mr. McBeath cites also provide no support for his
ipse dixit that the industry considers any well an offset well regardless 33 of its distance from the neighboring well. Neither 16 Tex. Admin. Code
§ 3.46 (Rule 46) nor § 3.37 (Rule 37) has the term “offset well” in it. 16
Tex. Admin. Code § 3.36 (Rule 36) uses the term once with respect to
determining the escape rate for hydrogen sulfide in subsection
3.36(c)(3)(C). The phrase does not indicate where the offset well may be
located.
3. If expert testimony is appropriate, the affidavit of the Herbsts’ expert Gregg Robertson either is conclusive as the only testimony that makes sense or at least raises a fact issue.
Although expert testimony is neither necessary nor appropriate
here, the Herbsts provided in response to Mr. McBeath a competing
expert affidavit from Gregg Robertson, who has worked in the oil and
gas business for 35 years and joined with Petrohawk Energy to drill the
initial discovery wells for the Eagle Ford Shale field.3 SCR 238, ¶ 2. If
expert testimony is appropriate, the experts disagree. The Court should
either accept Mr. Robertson’s affidavit as conclusive because Mr.
McBeath’s affidavit is unsupported by anything other than his personal
3 Murphy filed but did not set for hearing a motion to strike Mr. Robertson’s affidavit as conclusory because Mr. Robertson did not cite treatises, dictionaries or regulations in support of his opinion. The motion was waived and the claims are false and meritless. Mr. Robertson references that he reviewed the Herbsts’ motion, which included dictionary and industry definitions, RRC filings, and the McBeath affidavit in preparation of his affidavit, which refuted in considerable non-conclusory detail Mr. McBeath’s opinions. SCR 238-42.
34 opinion or should hold there is a fact issue on the meaning of the term
“offset well.”
Mr. Robertson states that he been involved in “the construction of
several hundred oil and gas leases, and specifically over one hundred
oil and gas leases in the past five years for the development of Eagle
Ford Shale reserves.” SCR 240, ¶ 8. He further states that has “never
seen in any written contract nor heard in any conversation” the
distinction Mr. McBeath purports to make between “an offset well” and
“a direct offset well.” SCR 241, ¶ 9. Mr. Robertson refutes Mr.
McBeath’s claim that the terms “direct offset well” and “immediate
offset well” are terms commonly used in the oil and gas industry. SCR
239-42, ¶¶ 5-9.
The Court should reject Mr. McBeath’s claim (SCR 177,¶ 19) that
the purpose of the offset clause is not to protect acreage from drainage.
This claim defies common sense, as well as dictionary and industry
definitions and court decisions. It is also expressly refuted by Mr.
Robertson. SCR 240, ¶ 8. Mr. McBeath opines that no drainage would
actually occur here because experience has shown that only “a
relatively modest amount of reservoir is drained by each horizontal 35 well.” SCR 177, ¶ 19. Mr. McBeath’s claim that no drainage has, in fact,
occurred is precisely the kind of factual dispute the Offset Clause
renders irrelevant. Mr. McBeath’s claim that the purpose of an offset
well is not to protect against drainage is nonsensical. The “sole
purpose” of an offset well is “to prevent, compensate and mitigate the
drainage of the leased premises by the offending well. Common sense
precludes any other construction.” SCR 175, ¶ 8 (Robertson Aff.).
III. The trial court erred in awarding Murphy attorney’s fees. (Issue Two)
A. The trial court had no statutory authority to award attorney’s fees.
There is no legal basis for awarding Murphy any attorney’s fees in
this case. The Herbsts sued Murphy for breach of contract. SCR 5-11.
Murphy counterclaimed for attorneys’ fees under Chapters 37 and 38 of the
Texas Civil Practice and Remedies Code. SCR 116. Neither provides a
basis for a recovery of fees by Murphy.
Murphy cannot recover fees under Chapter 38, which defines when
fees are recoverable in a breach of contract case. Chapter 38 limits recovery
of fees to when the prevailing party has recovered damages in the breach of
contract action. See, e.g., Green Int’l, Inc. v. Solis, 951 S.W.2d 384, 390 (Tex.
36 1997) (“To recover attorney’s fees under Section 38.001, a party must (1)
prevail on a cause of action for which attorney’s fees are recoverable, and
(2) recover damages.”) (emphasis added). Murphy has no claim for damages
and, therefore cannot recover fees under Chapter 38. Murphy conceded as
much in its Motion for Final Judgment, wherein it does not seek recovery
of fees under Chapter 38 but, instead, seeks fees under Chapter 37.
Murphy may not recover fees under Chapter 37 either. Chapter 37
contains the Uniform Declaratory Judgments Act (UDJA) and, when the
UDJA is properly invoked, § 37.009 gives the trial court the discretion to
award such fees “as are equitable and just.” The UDJA, however, may not
be used “as a vehicle to obtain otherwise impermissible attorney’s fees.”
MBM Fin. Corp. v. Woodlands Operating Co., L.P., 292 S.W.3d 660, 669 (Tex.
2009). When, as here, the core issue lies in contract, a defendant like
Murphy cannot simply “replead[] a claim as a declaratory judgment.” Id.
The Supreme Court’s reasoning in MBM Financial is controlling here:
[W]hile declaratory relief may be obtained under the Act in all these circumstances, that does not mean attorney’s fees can too. Texas has long followed the “American Rule” prohibiting fee awards unless specifically provided by contract or statute. By contrast, the Declaratory Judgments Act allows fee awards to either party in all cases. If repleading a claim as a declaratory judgment could justify a fee award, attorney’s fees would be 37 available for all parties in all cases. That would repeal not only the American Rule but also the limits imposed on fee awards in other statutes. Accordingly, the rule is that a party cannot use the Act as a vehicle to obtain otherwise impermissible attorney’s fees.
The Act was originally “intended as a speedy and effective remedy” for settling disputes before substantial damages were incurred. It is “intended to provide a remedy that is simpler and less harsh than coercive relief, if it appears that a declaration might terminate the potential controversy.” But when a claim for declaratory relief is merely tacked onto a standard suit based on a matured breach of contract, allowing fees under Chapter 37 would frustrate the limits Chapter 38 imposes on such fee recoveries. And granting fees under Chapter 37 when they are not permitted under the specific common-law or statutory claims involved would violate the rule that specific provisions should prevail over general ones. While the Legislature intended the Act to be remedial, it did not intend to supplant all other statutes and remedies.
MBM Financial, 292 S.W.3d at 669-70 (footnotes omitted).
Thus, a request for declaratory judgment that is merely “tacked onto”
a breach of contract claim cannot be a basis for a fee award. Id. at 670; see
also Etan Indus. v. Lehmann, 359 S.W.3d 620, 624 (Tex. 2011) (“When a claim
for declaratory relief is merely ‘tacked onto’ statutory or common-law
claims that do not permit fees, allowing the UDJA to serve as a basis for
fees ‘would violate the rule that specific provisions should prevail over
general ones.’”).
38 Here, Murphy’s UDJA counterclaim sought to determine whether
Murphy had breached the Leases. SCR 115-16. That counterclaim is “part
and parcel” of the contract claim. MBM Fin. Corp., 292 S.W.3d at 671.
Thus, Murphy cannot recover fees. See Mungia v. Via Metro. Transit, 441
S.W.3d 542, 550 (Tex. App.—San Antonio 2014, pet. denied) (“[A]ttorney's
fees under the UDJA [are not authorized] simply because declaratory relief
is sought as a means to obtain relief quicker and more effectively than that
authorized by another asserted cause of action.”).
In its Motion for Final Judgment, Murphy cited Save Our Springs
Alliance, Inc. v. Lazy Nine Mun. Util. Dist., 198 S.W.3d 300 (Tex. App.—
Texarkana 2006, pet. denied), as authority for awarding fees under the
UDJA. Save Our Springs is inapposite -- it was not a breach of contract case.
See id. at 308-310. Instead, Plaintiff in that case challenged the
constitutionality of a statute. Id. at 308. Plaintiff’s sole claim was as a
declaratory judgment. Id. at 318. Here, the Herbsts’ claim is for breach of
contract and recovery of damages.
That the Herbsts also sought a declaratory judgment does not give
Murphy the right to recover fees. The Herbsts’ UDJA claim was, on its
face, redundant of its breach of contract action. See SCR 9-10. 39 Courts have distinguished Save Our Springs from cases involving
common law claims similar to the present one, in which Murphy’s
requested declaratory judgment relief is supplementary and incidental to
Plaintiffs’ contract claim. These courts have held that, when a party files a
common-law claim and “only s[eeks] declarations accepting the premises
on which its [common law] claim i[s] based,” fees are unwarranted. See
Washington Square Fin., LLC v. RSL Funding, LLC, 418 S.W.3d 761, 776 (Tex.
App.— Houston [14th Dist.] 2013, pet. denied); see also, Mungia, 441 S.W.3d.
at 550 (distinguishing case law in which there is “only one claim . . . for
declaratory relief under the UDJA” from cases involving more than one
claim and finding trial court had no discretion to award UDJA attorneys’
fees).
B. If the trial court had authority to award fees under the UDJA, it abused its discretion in awarding fees on appeal after determining fees in the trial court were not appropriate.
If, however, the Court holds that a fee award under the UDJA is
available, the Court should nevertheless reverse the district court’s award
of attorney’s fees here as an abuse of its discretion. An award of fees under
the UDJA is discretionary. See Tex. Civ. Prac. & Rem. Code Ann. § 37.009
(Vernon 2013) (stating the court “may” award fees and costs). A court
40 “may conclude that it is not equitable or just to award even reasonable and
necessary fees.” Bocquet v. Herring, 972 S.W.2d 19, 21 (Tex. 1998).
The test for abuse of discretion is “whether the court acted without
reference to any guiding rules and principles” or was “arbitrary or
unreasonable.” Downer v. Aquamarine Operators, Inc., 701 S.W.2d at 241-42.
See also Woodglen Homeowners Ass’n v. Odom, 452 S.W.3d 489, 490 (Tex.
App.—San Antonio 2014, no pet.) (“A trial court abuses its discretion if its
decision is arbitrary, unreasonable, and without any reference to any
guiding rules or principles.”).
The district court here exercised its discretion to deny Murphy an
award of fees incurred in the trial court, stating:
And frankly my thinking on not awarding attorney’s fees as a result of the trial proceeding was that the Plaintiffs were certainly entitled to their thoughts as to the offset well needing to be drilled closer and had the right to present their arguments to the Court for the Court to make a determination on that, and should not be penalized by having to pay huge amounts of attorney’s fees. And so attorney’s fees were not awarded.
RR 46, l. 22 – 47, l. 6.
The trial court then proceeded to award conditional fees to Murphy
in the event the Herbsts sought review in this Court and, if necessary, in
the Supreme Court. SCR 494. Having effectively found that it was not 41 “equitable or just” to award trial court fees, the court had no basis for then
holding that the Herbsts should be “penalized” with fees if they sought
review in this Court.
The trial court held the Herbsts had a legitimate issue to litigate and
should not be burdened with their opponents’ trial court fees for that
litigation. That reasoning applies equally to the Herbsts’ appeal. The
court’s ruling that it is not “equitable and just” to award trial fees but it is
“equitable and just” to impose those fees in the event of an appeal is
arbitrary and capricious and without guiding principles. Such an award
“could serve only to place a financial disincentive” for the Herbsts to
exercise their right to appeal to this Court and, as such, constitutes an
abuse of discretion. Reagan v. Marathon Oil Co., 50 S.W.3d 70, 83-84 (Tex.
App-Waco 2001, no pet.) (holding trial court abused its discretion when it
declined to award trial fees but did award appellate fees). See also United
Interests, Inc. v. Brewington, Inc., 729 S.W.2d 897, 906 (Tex. App.—Houston
[14th Dist.] 1987, writ ref’d n.r.e.) (same). The Court should reverse the
trial court’s award of fees in the event of an unsuccessful appeal as an
abuse of discretion.
42 CONCLUSION AND PRAYER For the reasons stated, the Herbsts respectfully pray that the Court
reverse the trial court’s grant of summary judgment for Murphy as well as
its award of fees and remand this case to the trial court for further
proceedings. The Herbsts seek such other and further relief, including the
costs of this appeal, to which they may be entitled.
Respectfully submitted, GRAVES DOUGHERTY HEARON & MOODY, P.C. By: /s/ Mary A. Keeney Mary A. Keeney State Bar No. 11170300 mkeeney@gdhm.com John B. McFarland State Bar No. 13598500 jmcfarland@gdhm.com 401 Congress Ave., Suite 2200 Austin, Texas 78701 Telephone: (512) 480-5682 Facsimile: (512) 480-5882 ATTORNEYS FOR APPELLANTS SHIRLEY ADAMS, CHARLENE BURGESS, WILLIE MAE HERBST JASIK, WILLIAM ALBERT HERBST, HELEN HERBST AND R. MAY OIL & GAS COMPANY, LTD.
43 CERTIFICATE OF COMPLIANCE
This brief complies with the type-volume limitation of Tex. R. App.
P.9.4(i)(2)(B) because it contains 8,950 words, excluding the parts of the
brief exempted by Tex. R. App. P. 9.4(i)(l). The undersigned relied on the
word count of MS Word, the computer program used to prepare the brief.
/s/ Mary A. Keeney Mary A. Keeney
44 CERTIFICATE OF SERVICE
I hereby certify that on July 8, 2015, a true and correct copy of the foregoing was served on counsel for Appellee via email and/or electronic service as shown below:
Macey R. Stokes Jason A. Newman Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002-4995 ATTORNEYS FOR APPELLEE MURPHY EXPLORATION & PRODUCTION COMPANY - USA Macey.stokes@bakerbotts.com Jason.newman@bakerbotts.com
/s/ Mary A. Keeney Mary A. Keeney
TAB
1. Order Setting Aside Final Judgment In Part And Entering Amended Final Judgment
2. Final Judgment
3. Oil and Gas Leases a. Shirley Adams lease b. William Herbst lease
4. RRC Field Rules for Eagle Ford Field
5. Affidavit of John McBeath
6. RRC Form H-1
7. RRC Orders a. RRC Docket No. XX-XXXXXXX b. RRC Rule 37 Case No. 0213270 c. RRC Rule 37 Case No. 0240684 d. RRC Rule 37 Case No. 0211820 e. RRC Rule 37 Case No. 0245869
8. Affidavit of Gregg Robertson
9. Excerpt from Court Reporter’s Record
10. January 21, 2015 Alfred A. Steinle Amicus Letter
11. RRC Administrative Rules a. 16 Tex. Admin. Code § 3.36 b. 16 Tex. Admin. Code § 3.37 c. 16 Tex. Admin. Code § 3.46
46 TAB 1 Order Setting Aside Final Judgment in Part and Entering Amended Final Judgment CAUSE NO. 13-05-0466-CVA
SHIRLEY ADAMS, CHARLENE BURGESS, WILLIE MAE HERBST JASIK, IN THE DISTRICTFItTIT4.0 O'CLOCK r M MARGARET E. LITTLETON, DISTRICT CLERK WILLIAM ALBERT HERBST, HELEN HERBST and R. MAY OIL & GAS COMPANY, LTD., FEB 10 ;-:315 Plaintiffs, CLERK DISTRICT vs. 218th JUDICIAL 13
MURPHY EXPLORATION & PRODUCTION CO.-USA, A DELAWARE CORPORATION, Defendant. ATASCOSA COUNTY, TEXAS r- PAR( ORDER SETTING ASIDE FINAL JUDGMENT AND ENTERING AMENDED FINAL JUDGMENT
On February 2, 2015, came on to be considered the Motion for New Trial, Motion to
Vacate or Modify the Judgment, and Motion to Reconsider the Court's Decision on Partial
Summary Judgment Motions, filed by Plaintiffs Shirley Adams, Charlene Burgess, Willie Mae
Herbst Jasik, William Albert Herbst, Helen Herbst, and R. May Oil & Gas Company, Ltd. The
Court has considered the motions, the respohse filed by Murphy Exploration & Production Co.-
USA, and the arguments presented by counsel and is of the opinion that Plaintiffs' motions yvwx1 ,-.0e a:A pa-4- should be granted in part end-denied in partifor the following rOsons:
-17----The--Eoeeerrrber-l-57201-4-Ftrfal-JtRigrnent-was-presented-to-the-Goug--without--
_praper-notice-to-Plaintiffrin-viefatiorref-Texas Ra1e-tifeivil-PTeeeelure-305-,--
2. The December 15, 2014 Final Judgment _improperly awards appellate attorney's
fees to Murphy. -Th a-fincls-that-these4es-ape-het-reowerable-under-either-C-hapter-3-7-or-
Zhapter.a&of_the-Texas-Givil-Practice-&:-R-Gmecli€s-Goele,--The-Gourt-furtherfrnthat-it
-be-noitherequitabi e-neriust-ttraward-these4Gos-:-The-eourt-finther-linds-that-these-fees-are-not-
2250162.1 485 „
FCWAL 3-‘,6(5,4v1-$44+. The Court vacates and modifies its *Me* in part with regard to the award of appellate fees to
Murphy. The Court modifies paragraph 3 of its December 15, 2014 final judgment in this matter
and finds that should Plaintiffs appeal this Final Judgment, Murphy will expend reasonable and
necessary attorneys' fees in the amount of $25,000 for defending the matter in the Court of
Appeals, $7500 for responding to a petition for review, and $20,000 in the event the Supreme
Court orders briefing on the merits and grants the petition. Therefore, should Plaintiffs Avvmketiza unsuccessfully appeal this4inal Judgment, they are ordered to pay Murphy's reasonable and
necessary attorney's fees on appeal as directed in this judgment.
3, The Court finds that its rulings on Plaintiffs' Motion for Partial Summary
Judgment and Defendant's Motion for Partial Summary Judgment should stand.
IT IS THEREFORE ORDERED THAT Plaintiffs' Motion for New Trial, Motion to oK Vacate or Modify the Judgment, and Motion to Reconsider the Court's Decision 43f Partial
Summary Judgment Motions is denied, except that the December 15, 2014 Final Judgment in
this case is vacated and modified solely with regard to paragraph 3 as reflected in this order.
IT IS FURTHER ORDERED THAT Plaintiffs' Motion for Partial Summary Judgment is
DENIED AND Defendant's Motion for Partial Summary Judgment is GRANTED.
Costs are taxed against Plaintiffs.
IT IS FURTHER ORDERED that all other relief requested in this cause is DENIED.
SIGNED this 10th day of February, 2015.
ELLA SAXON, Judge Presiding
486 TAB 2 Final Judgment FILED O'CLOCK r.) MARGARET E. LITTLETON, DISTRI T CLERK
CAUSE NO. 13-05-0466-CVA
SHIRLEY ADAMS, CHARLENE BURGESS, WILLIE MAE HERBST JASIK, WILLIAM ALBERT HERBST, HELEN HERBST and R. MAY OIL & GAS COMPANY, LTD., '§
Plaintiffs.
vs. 218 TH JUDICIAL DISTRICT
MURPHY EXPLORATION & PRODUCTION CO. USA, A DELAWARE CORPORATION,
Defendant. ATASCOSA COUNTY, TEXAS
FINAL JUDGMENT
WHEREAS, Plaintiffs Shirley Adams, Charlene Burgess, Willie Mae Herbst
Jasik, William Albert Herbst, Helen Herbst, and R. May Oil & Gas Company, Ltd. (collectively
"Plaintiffs") filed a Motion for Partial Summary Judgment on September 5, 2013.
WHEREAS, Murphy Exploration & Production Company—USA ("Murphy")
filed its Motion For Partial Summary Judgment on January 24, 2014.
• WHEREAS, the cross-motions for partial summary judgment concerned the two
leases executed by Plaintiffs Shirley Adams and William Herbst covering the following tracts of
land:
302.0 acres of land, more or less, in the Octavius A. Cook Survey No. 195, A-176, in Atascosa County, Texas, and being the same land set aside to Shirley Mae Herbst Adams in Division No. 5 in an Agreement on Division of Estate dated October 20, 1993, recorded in Volume 865, Page 506 of the Deed Records of Atascosa County, Texas."
302.0 acres of land, more or less, in the Mark H. Moore Survey No. 185, A-559 and the Octavius A. Cook Survey No. 195, A-176 in Atascosa County, Texas, and being the same land set aside to William Albert Herbst in Division No. 4 in an Agreement on
CIVIL
414 VOL q0 PAGE 1(47 Division of Estate dated October 20, 1993, recorded in Volume 865, Page 506 of the Deed Records of Atascosa County, Texas."
The two leases together are referred to as the "Leases."
WHEREAS, On September 2, 2014, the Court heard oral argument on both
Motions for Partial Summary Judgment. On November 14, 2014, the Court, having considered
the motions, responses, and arguments of counsel, GRANTED Murphy's Motion for Partial
Summary Judgment and DENIED Plaintiffs' Motion for Partial Summary Judgment.
WHEREAS, On , Murphy moved for entry of final judgment in this
matter.'Having considered the motion, the Court hereby GRANTS Murphy's Motion for Entry
of Final Judgment.
It is, therefore, ORDERED, ADJUDGED, AND DECREED as follows:
1. Based upon the Court's Order granting Murphy's Motion for Partial
Summary Judgment and denying Plaintiffs' Motion for Partial Summary Judgment, the Court
finds that judgment should be entered and is hereby RENDERED in favor of Murphy, and the
Court DECLARES as follows:
a. Paragraph 25 of the Leases is unambiguous;
b. The Herbst #1H Well, on which Murphy commenced drilling
operations June 8, 2012, was drilled as an off-set well pursuant to
Paragraph 25 of the Leases and satisfies the requirements of Paragraph 25
of the Leases; and
c. Murphy has not breached the Leases with regard to the drilling and
completion of the Herbst #1H Well and does not owe compensatory or
other royalties or any other obligations under Paragraph 25 as a result.
2. The Court has found that Murphy's attorneys' fees in the amount of
$120,853.36 and costs in the amount of $5,119.71 are reasonable and necessary and it is CIVIL 415 VOL PAGE 1 16 equitable and just for Plaintiffs to pay Murphy's -and costs. Therefore, Plaintiffs
are ORDERED to pay AllE1 •
5-1-20,853.36 anktcosts in the amount of $5,119.71.
3. The Court has further found that, should Plaintiffs appeal this Final
Judgment, Murphy will expend reasonable and necessary attorneys' fees in the amount of
$150,000 to defend the appeal. Therefore, should Plaintiffs unsuccessfully appeal this Final
Judgment, they are ORDERED to pay Murphy's reasonable and necessary attorneys' fees on
appeal in the amount of $150,000.
4. Plaintiffs TAKE NOTHING by their claims.
5. This is a final judgment, finally disposing of all claims and all parties, and
is appealable.
SIGNED this -Cday of
CIVIL
VOL___RaPAGE (ei 416 TAB 3 Oil and Gas Leases Notice of confidentiality rights: If you are a natural person, you may remove or strike any or all of the following information from any instrument that transfers an interest in real property before it is Bled for record in tha Public Records: Your social security number or your driver's license number. fa11.1;17.1'21.1atel OIL, GAS AND KIMIRAL LEASE . THIS AGREEMENT made this 14th day of August , 2009, between SEHRLEY MAE HERBST ADAMS, whose address is P. 0. Box 37, Karnes City, Texas 78118, Lessor (whether one or more); and
ALVIN M. BARRETT & ASSOCIATES INC, a Texas Corporation, 11202 Sandstone Street, Houston, Texas 77072, Lessee,
WITNESSETH: 1. Lessor, in consideration of Ten and No/100 Dollars and other good and valuable consideration, the receipt of which is hereby acknowledged, and of the covenants and agreements of Lessee hereinafter contained, does hereby grant, lease and et unto Lessee the land covered hereby for the purposes and with thb exclusive right of exploring, drilling, mining and opmating for, producing and owning oil, gas, sulphur and all other minerals (whether or not similar to those mentioned), together with the right to make surveys on said land, lay pipe lines, establish and utilize facilities for surface or subsurface disposal of salt water, conitruce roads and bridges, dig canals, build tanks, power stations, telephone lines, in sployettionets and other structures on said land, necessary or useful in Lessee's operations in exploring, drilling for, producing, treating, storing and transporting minerals produced from the land covered hereby or any other land adjacent thereto. The land covered hereby, herein called "said lend, is located in the County of Atascosa , State of Texas , and is described as follows: 302.0 acres of land, more or less, In the Octraviue A. Cook Survey No. 195, A-176 In Atascosa County, Texas, and being the same land set aside to Shirley Mao Herbst Adams in Division No. 5 in an Agreement on Division of Estate dated October 20,1993, recorded In Volume 865, Page 506 of the Deed Records of Atascosa County, Texas. T1 l eee also tees c. s-and-includcs,.hrstIclitiairto that-aboTe-drzeribech-a111—. -ifistry.roontivxow o. atii3ox.rit to-or ATticrining-thc--1and above &scribed ands( • • — • • • • . ••• • • • 4. • SiOn7 • a • • 4 •• •rtle)-ertowhierh-Lessorhasserpreef mese sigh of aiutrisition. Lessor agrees to
execute any supplemental instrument requested by Lessee for a more complete or accurate description of said land, For the p ose of determining the amount of any bonus or other payment hereunder, said land shall bo deemed to contain 2. • acres, whether actually containing more or less, and the above recital of acreage in any tract shall be deemed to be the true acreage thereof. Lessor accepts the bonus as lump sum consideration for this lease and all rights and options hereunder. •2. Unless sooner terminated or longer kept ins force under other provisions hereof, this lease shall remain in force for a term of three (3) years from the date hereof, hereinafter called "primary term", and as long thereafter as operations, as hereinafter defined, are conducted upon said land with no cessation for more than ninety (90) consecutive days. 3. As royalty, lessee covenants and agrees: (a) To deliver to the credit of-lessor, In the pipe line to which lessee may connect its wells, the equal out-cagleir(1/0) one-fifth (1/5th) part of all oil produced and saved by lessee from said land, or from time to time, at the option of lessee, to pay lessor the average posted market price of such one- (1/0) one-fifth (1/5th). pert of such oil at the wells as of the day it is run to the pipe line or storage tanks, lessor's interest, in either case, to bear one-eighth (1/0) one-fifth (1/5th) of the cost of treating oil to render it marketable i e line oil; (b) To pay lessor on gas and casinghead gas produocd from eaid land (1) when sold by lessee, orris ' one-flfth (115th) of the amount malizedby lessee, computed at the mouth orate well, or (2) when used by lessee off said land or in the manufacture of gasoline or other products, the market value, atthe-mointrofthe eel{ . • 2. 44 ': onefifth (1/50) (feich gas and eas ingicadgas' (o)rer ensorarrellelherainerelemieuel istrefi fiCrerCe 4_ • e• •: 1710en or-atetlitewell ,,.iii c t iciae.!.refeetiore-cireseptili et Js • • :.1ebeessaceilontreqie00)-preiioneeton If, at the expiration of the prireary termer at any time er times therea , there is any well on said land or on lands with which said land or any portion thereof has been pooled, capable of producing oil or gas, end all such wells are . shut-in, this lease shell, nevertheless, continue in force as though operations were being conducted on said land for so long as said wells are shut-in, and thereafter this lease may be continued in fame as if no shut-in had occurred. Lessee covenants and agrees to use reasonable diligence to produce, utilize, or market the minerals capable of being produced from said wells, but in the exercise of such diligence, lessee shall not be obligated to install or furnish facilities other than well facilities and ordinary lease facilities of Bow lines, separator, and lease tank, and shall not be required to settle labor trouble or to market gas upon terms unacceptable to lessee. If, at any time or times after the expiration of the primary term, all such wells are shut-in for a period of ninety (90) censecut(ve days, and during such time there arc no operations on said land, then at or before the expiration of said ninety(90) day period, lessee shall pay or tender, by checksoreeirefl-of lessee, as royalty, a sum equal to tee doper (51.00) twenty-five dollars (525,00) for coal acre of land then covered hereby. Lessee shall make like payments or tenders et or before the end of each anniversary of the expiration of said ninety (90) day period if upon such anniversary this lease is being continued in force solely by reason of the provisions of this paragraph. Each suoh payment or tender shell be made to the parties who at the time of payment would be entitled to receive the royalties which would be paid under this lease if the wells were producing, and may be deposited in the PAY DIRECTDy TO LESS Q11 Berate-ate , of its successors, which shal continue as the depositories, regardless of changes in the ownership of shut-in royalty. If at any time that lessee pays or tenders shut-in royalty, two or more parties are, or claim to be, entitled to receive same, lessee may, in lieu of any other method of payment herein
Arl.vo• SMOG/ ,hiss 3111 Lexabor
AT T 150 provided, pay or tender such shut-in royalty, in the manner above specified, eithereeindy-to-sectrpartieseerseparately to each in accordance with their respective ownerships thereof, as leseee Lev sleet. Any payment hereunder may be made by check or dreftsof lessee deposited in the mail or delivered to the party entitled to receive payment or to a depository bank provided for above an or before the last date for payment. Nothing herein shall impair lessee's right to release as provided in paragraph 5 hereof, In the event of assignment of this lease in whole or In part, liability for paymenthereunder shall rest exclusively on the then owner or owners'of this lease, severally as to acreage owned by each. 3A. "Gross Proceeds", as used herein, shall mean the total proceeds received by Lessee for any non- affiliated third-party Salo of seek oil, gas or other substance; provided, however, If any contract covering oll, gas or other substance produced Irons the lands covered hereby, or any contract used for the purpose of establishing the price of Lessor's royalty oil or gas, provides for rely deduction for Use expenses of production (except for Lessor's proportionate share of actual costs of extricating-the sulphur, if any, from the gas and shrinkage, if any, resulting from such extraction), post production, gathering, dehydration, compression, transportation, manufacturing, treating, or marketing of such oil or gas, then such deduction shall be added to the price received by Lessee for such oil or gas so that Lessor's royalty shall not be charged directly or indirectly with any such expenses. Provided, however, should said gas contract 'provide for a deduction for transportation, shrinkage, or treating to make gas marketable downstream fro in Lessee's tales meter, and such deduction be levied by a bona fide non-efaliated third party, then In such event, Lessor's Royalty Share shall bear Its proportionate share o f non-afell feted third party transportation shrinkage and treating deductions, but no other post production costs shall be deducted teem Lessor's Royalty Share. 3D. Thephrase "free of cost(s)" or "free of all costs", as used Iserohnshall mean that Use royalty Interest shall not be charged and shall not bear any costs whatsoever In connection with the exploration, production, gethering, compression, transportation (except "Third Party Treasnorietion costs", as hereinafter defined, actually incurred by Lessee), marketing or "Treating", as hereinafter defined, of oil, gas or other substance produced hereunder. Provided, how ever, that Lessor's royalty shall bear Its proportionate share of applicable production, windfall profits and severance taxes properly assessable against and attributable to said royalty interest. "Treating" shall mean those methods used by Lessee at the lease to remove contaminants from the wellhead hydrocarbons as may be necessary to place the hydrocarbons In a merchantable condition. Provided, however, should It be necessary for Lessee to Install an amine unit on the leased premises In order to make said gas marketable, Lessor shall bear Its prorate share of shrinkage of such gas es contaminants are removed from the gas stream processed by said amine plant. However, Lessor shall sot 'near ifs nrorate share of feel ges, amine, compression or other costs necessary to operate said amine plant. 'Titled Per'tvTritesnortatien costs" shall mean the tariff rate based transportation costs Incurred by Lessee In an term's length transaction with a bona fide third pasty that Is not a subsidtery or affiliate of Lessee hi order to take gas and/or liquid hydrocarbons from the point that such hydrocarbons have been separated, treated (if necessary), processed (if performed) and placed in a merchantable condition. 4. Lessee is hereby granted the right, at its option, to pool or unitize any land covered by this lease with any other land covered by this lease, and/or with any other land, lease, or leases, as Many or all minerals or horizons, so as to establish units containing not more than 80 surface acres, plus 10% Acreage tolerance; provided, however, units -may be established as to any one or more horizons, or existing unitsmay be enlarged es to any ono or more horizons, so as to contain not more than 640 surface aore,s plus 10% acreage tolerance, if limited to one or snore of the following: (1) gas, other than ezeinghead gas, (2) liquid hydrocarbons (condensate) which are not liquids In the subsurface reservoir, (3) minerals produced from wells classified as gas wells by the conservation agency having jurisdiction. Merger tmits than any of those herein permitted, either at the time established, or atter enlargement, are prescribed by specie. geld rules or permitted by statewide Rule 86 for horizontal wells for the drilling or operation of a well at a regular location, or for obtaining mtudinum allowable from any:. well to be drilled, drilling, or already drilled, any such unit be established or enlarged to conform to the aim presoribed 'by special field rules or permittedily statewide Rule 86 for herizontal wele. Lessee shall exercise said option as to cash desired unit by executing an hastrnMesat identifying such euit and filing it forreeord in thepublio office in which this lease is recorded. Each of said options may be exercised by Lessee at any time end front tune to time while this lease is in force, and whether before or alter production has been established either on said land, or on the. portion of said land included in the unit, or on other hind unitized therewith. A unit establishedhercunder shall be valid and effective for all purposes of this lease oven though there may be mineral, royalty, or leasehold interests in lands within the unit which arc not effectively pooled or unitized. Any.operations conducted on any part of such unitized land shall be considered, for all purposes, except the payment of royaltyt operations conducted upon said land under this lease. There shall be allocated to the land covered by this lease within each such unit (or to each separate tract within the unit if this lease covers separate tracts within the unit) that proportion of the total production of unitized minerals from the unit, after deducting any used In lease or unit operations, which tbo number of surface acres in such land (or In each such separato tract) covered by this lease within the unit beats to the total number of surface acres in the unit, and the production so allocated shall be considered for all purposes, including payment or delivery of royalty, overriding royalty and any other payments out of production, to be the entire production of unitized mmerals from the land to width allocated in the same manner as though produced therefrom under the terms of this lease. The owner of the reversionary estate of tray term royalty or mineral estate agrees that the accrual of royalties pursuant to this paragraph or of shut-in royalties from a well on the unit shall satisfy any limitation of term requiring production of oil or gas. The formation of any unit hereunder which Includes land not covered by this lease shall not have the effect of exchanging or transferring any interest under this lease (including, without limitation, any shut-iu royalty which may become payable under this lease) between parties owning interests hi land covered by this lease and parties owning interests in land not covered by this tease. Neither shall it impair the right of Lessee to release as provided in paragraph 5 hereof, except that Lessee may not so release as to lands within a unit while there are operations thereon for unitized minerals unless all pooled leases are released as to lands within the unit, At any time while this lease is In force Lessee may dissolve any unit established hereunder by filing for record in the public office where this lease isle-corded a declaration to that effect. if at that time no operations are being conducted thereon for unitized minerals. Subject to the provisions of this paragraph 4, a unit once established hereunder shall remain in force so long as any lease subject thereto shall remain in force. If this lease now or hereafter covers Separate tracts, no pooling or unitization of roy aky interests as betwe en any such separate tracts is intended or shall be implied or result merely from
AG+. Skip Wrist 382 sa Lag u Bxrctslar 2
151 the inolusion of such separate tracts within this lease but Lessee shall nevertheless have the right to pool or unitize as provided in this paragraph 4 with consequent allocation ofproduetion as herein provided. As used in this paravaph 4, the words "separate tract" mean any tract with royalty ownership differing, now or hereafter, either as to parties or amounts, from that as to any other part of the leased premises. 5. Lessee may at any time and from time to time execute and deliver to Lessor or file for record a release or releases of this lease as to any part or all of said land or of any mineral or horizon thereunder, and thereby be relieved of all obligations, as to the released acreage or interest. 6. Whenever used in this lease tho word"operations" shall mean operations for and any of the following: drilling, testing, completing, reworking, reeompleting, deepening, plugging back or repairing of a well in search for or in an endeavor to obtain production of oil, gas, sulphur or other minerals, excavating a mine, production of oil, gas, sulphur or other mineral, wiretherornotin paying quantities,
7. Lessee shall have tho use, free from royalty, of water, other than from Lessor's water wells, and of oil and gas produced from said land in all operations hereunder. Lessee shall have the right at any time to remove all machinery and fixtures placed on said land, inclUding the right to draw and remove casing. No well shall be drilled nearer than 200 feet to the house or barn now on said land without the consent of the Lessor. Lessee shall pay for damages caused by its operations to growing crops and timber on said land. 8. The rights and estate of any party hereto may be assigned from time to time in whole or in part and as to any mineral or horizon. All of the covenants, obligations, and considerations of this lease shall extend to and be binding upon the parties hereto, their heirs, successors, assigns, and successive assigns. No change or division in the ownership of said land, royalties, or other moneys, or any part thereof howsoever effected, shall increase the obligations or diminish the rights of Lessee, including, but not limited to, the location and drilling of wells and the measurement of production. Notwithstanding any other actual or constructive knowledge or notice thereof of or to Lessee, its successors or assigns, no change or division in the ownership of said land or of the royalties, or other moneys, or the right to receive the same, howooever effected, shall bo binding upon the then reoord owner of this lease until thiry (30) days a tier there has been furnished tp such record owner at his or its principal place of business by Lessor or 'Lessor's heirs succesors, or assigets, notice of such change or division, supported by either originals or duly certified copies of the instruments which- have been properly, filed for record and which evidence suoh change or division, and of such court records and proceedings, transcripts, or other documents as shall be necessary in the opinion of such record owner to establish the validity of such change or division. If any such change in ownership occurs by reason of death of the owner, Lessee may, nevertheless pay or tender suoh royalties, or other moneys, or part thereof, to the credit of the decedent in a depository bank provided for above. • 9. in the event Lessor considers that Lessee has not complied with all its obligations hereunder, both express and implied, Lessor shall notify Lessee in Writing, setting out specifically in what respects Lessee has breached this contract, Lessee shall then have sixty (60) days after receipt of said notice within which to meet or commence to meet all or any part of the breaches alleged by Lessor. The service of said notice shall be precedent to the bringing of any action by Lessor on said lease for any cause, and no such action shall be brought until the lapse of sixty (60) days after service of such notice on Lessee. Neither the service of said notice nor the doing of any acts by Lessee aimed to meet all or any of the alleged breaches shall be deemed an admission or presumption that Lessee has failed to perfonn all its obligations hereunder. If this lea-se is cancelled for any cause, it shall nevertheless remain in force and effect as to (I) sufficient acreage around each well as to which there are operations to constitute a drilling or maxinium allowable unit under applicable governmental regulations, (but in no event less than forty acres), such acreage to be deSignated by Lessee as nearly as practicable in the form of a square centered at the well, or in with shape as then existing spacing rules require; and (2) any part of said laud included in a pooled unit on which there are operations. Lessee shall also have such easements on said land as aro necessary to operations on the acreage so retained.
10. Lessor hereby warrants and agrees to defend title to said land by, through and under Lessor, but not otherwise. Lessor's rights and interests hereunder shall be charged primarily with any mortgages, taxes or other liens, or interest and other charges on said land, but Lessor agrees that Lessee shall have the right at any time to pay or reduce same for Lessor, either before or after maturity, and bo subrogated to the rights of the holder thereof end to deduct amounts so paid from royalties or other payments passable or which may become payable to Lessor andior assigns under this lease. If this lease covers a less interest in the oil, gas, sulphur, or other minerals in all or any Lic rt of said lend than the entire and undivided fee simple estate (whether Lessor's interest is herein specified or not) or no interest therein, then the royalties and other hmneys accruing from any part as to which this lease covers less than such full inthrest, shall be paid only in the proportion witioh the interest therein, if any, covered by this lease, bears to the whole and undivided fee simple estate therein. All royalty interest ccrvered by this lease (whether or not owned by Lessor) shall be paid out of the royalty herein provided. This lease shall be binding upon eaohparty who executes it without regard• to whether it is exeouted by all those named-herein as Lessor.
11. Iii-avligs-iisErket%I. Is ;rics-aft?r:the-expiration-c-frirrt- Jrr . ristreofrit-is-notheing cerstiur4 . -in-forr,vittiessot Fol., Oa. sinthrfirsrefilace-rrsocres-sof-ps.rogrepL .3-har.ufreed Lorseels-nedst*rsci ase this operatiourearraki-iand ic,ssvn of (I:)4..y leyorriertryle-in-regulationstrlastheroestottitbseqntafirdettarnintxl t&beirtvelic1)-orf2)-thy-othertia= Hisinifivrr(tmrcotnEricieybcybrtaiirt-tremzi,,Cugtstil I ••••• • • .1 • • • . • • • • WO1-theitrit 4tutivcitatf chlt,3 ethers (90)es risore7claftfollissairLg•thespisnovelsofattueird. it ;IA ttri4,44stueetrotiac3 rA.,r.ti, itinViretrezthnsioueati+jusarfiferarat tse svi thin tlsh ao) &as ectisin:eutiareatt ntrFimied- Ifs0 Dells, s (52a0 ) sec nLiety (90-dayrsaiti-leaseris-exh.c&d, a) In the event any party is rendered unable, wholly or in part, by Force Majeure (as hereinafter defined) to carry out its obligations under this agreement, then the party relying on such Force Majeure (or its or their representatives) shall give thirty (30) days written notice of the Force Majeure with reasonably full particulars concerning it to the other party. rile obligations of the party relying on the Force Majeure, insofar as they aro affected
Maim, Slarlq H.t' 3n lat.. to [tun:mbar L 3
152 by the Force Majeure, shall be suspended during the continuation of all the Force Majeure and fora reasonable period thereafter not to exceed thtrty (30) days. b) The term "Force Majeure" as here employed shall include ants of Ood, strikes, lookouts, or the public enemy, wars, blockade, insurrections, riots, epidemics, landslides, lightning, fires, floods, tornadoes, hurricanes, explosions, acts or requests, inability or unavoidable delay in obtaining governmental permits or authorizaton for drilling or other operations to be controlled hereunder, any other governmental action, governmental delay, restraint, inaction, rules or orders of federal, state ormunielpal goverrenents or of any federal, state or municipal officer or aaent purporting to act under duly constituted authority, interruptions of transportation, freight embargoes, unavailability of drilllngrigs, e9uipment or essential personnel, any other cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of the party claiming Force Majeure. BFWEEMSS-WIEEMW-thirietstrumentireseecuted-on-thertiate lust-Owe mittat SEE ADDENDUM CONTAINING PARAGRAPHS 12 THROUGH 51 ATTACHED HERETO AND MADE A PART HEREOF FOR ALL PURPOSES.
Alias 0.1A7 /trawl 302 bo lugs Lc. na,nr.tar 4
153 ADDENDUM NOTWITHSTANDING anything to the contrary hereinabove provided, it is expressly agreed and stipulated by and between the Lessor and Lessee that: 12.) Reference in this lease to "other minerals" shall be deemed to include, In addition to oil and gas, only such related suiphurand hydrocarbons as maybe produced therewith and extracted therefrom and shall not include coaLlignite, uranium, fissionable materials, other sulphur, or any unrelated or hard minerals.
13.) The right to maintain this lease in force and effect beyond the expiration of the primary term by the payment of shut-in royalties web set out in paragroph 3 supra, is a recoiling right which maybe exercised by Lessee• from time to time but shall not exceed an aggregate or cumulative period of.tune of more than three (3) years. . 14.) The right of Lessee to pool the acreage covered by this lease with other acreage, as is provided for in paragraph 4 supra, Is hereby limited to the extent that if a well is drilled on the leased acreage and thisoling po privilege is exercised, then at least ono-half (g) of the unit must be land covered by this lease, or one-half (Yi) of this lease must be inoluded within the unit, and if the well is drilled on the acreage pooled with this lease, then at leas tone- third (1/3rd) of the unit must bo land covered by this lease, or one-third (1/3rd) of this lease must be included within the unit, at Lessee' a discretion; provided, however, if the =aunt of acreagOretnaining whieh has ace theretofore been inoluded in a peolexi unit or Allocated to a producing well Is insufficient to satisfy the above requirement, then all such remaining available acreage shall be included within such unit. Anything herein to the conhary notwithstanding it is understood and agreed that the provisions of this paragraph 14.), shall not apply to the poolhig of this lease with any other Oil, Gas and Miami Leases dated August 14, 2009, executed by Mary Ann Herbst May, Helen Loufie Hetbst, William Alb en Herbst, Charlene A/111E0nm, Shirley WO Herbst Adruns, Susan G. Herbst or William Albert Herbst and wife, Susan 0.11erbst, as Lessor to Alvin M. Barlett & Assoolate.s Inc., as Lessee that covers other acreage not covered by this lease. 15.) In the event a pooled unit is created under the provisions of paragraph 4 supra, production, drilling, or reworking operations on said unit shall not be effectiVe to maintain this lease in force as to acreage outside of such unit beyond the end of the primaryterrn. However, this lease maybe maintained in force as to such unpooled acreage in any other manner provided heroin. • 16.) In the event Lessee exercises any pooling privilege granted, lessee agrees to furnish Lessor with a copy of any unit designation within thirty pa) days after the same is filed for record. 17.) The royalties which aro to bepaid under the terms of this lease for the production of oil or gas after the end of the Ornery term or continuous-development, whichever later occurs, shall never bo less than FIFTY AND NO/100 DOLLARS (550:00) pernetroineral acre per annum for the.number of acres which are being held under each well, and the riecormUng period for such royalties shall be from January 1st through Decomber3Istof each year during the tenure ofthie -lease, commencing with January 1st following the first produebion of oil and/or gas from the leased promisee, and in the event that there has Iteem a deficiency ofroyalty payments made duffing the accounting period for which aueh minimuentoyalty payments are due, the Lessee shall have a period of ninety (90). days within which to makeup such deficienoy foonroeil after isavieg received writtennotice from the Lessor of such deficiency, and Lessee shall be deemed conclusively to have received such notice as of the date that same was mailed in a United State,s l'ost Office by certified Mail, return receipt requested, addressed solely to the Operator as designated at the Railroad Commission, irrespective of the ownershipof this lease. Evidence of such mailing shall be by Postal Receipt Form P.S. 3811. Should Lessee fail to make up such deficiency within theprescribed time, this lease shall terminate as to ell parties, but such terreination shall not relieve Lessee of the obligation ofpaying a minimumroyalty in accordance with the terms of this lease to Its date of termination, It Is provided, however, that such lease termination In the preceding sentence Shall not apply to BOPCO EMT O&G TX L.P., KEYSTONE O&G TX, L.P., LMBI P&G TX, L.P., SABI 084G TDC„ L.P., THRU LINE O&G TX, L.P., and any affiliates thereof, but any unpaid minimum royalty shall bear interest at the rite-of ten percent (10%) per annum or the maximum lawful rate of interest for such sums, whichever is the lesser amount Lessee is in nowise obligated to maintain this entire lease in force and effect, and upon releasing a portion of the acreage covered hereunder shall be relieved of this minimum royalty provision as to the aoreage so released from and after the date of mob release, and if released on other then an anniversary date, Lessee shall be liable for a Fromm part of the annual mjnimum royalty up to the date of said release. This minimum royalty provision shall not be applicable to the period of time for which the shut-In royalties have been paid under the terms of this lease. • 18.) Lessee agrees to pay fee any mewl surface damages caused by its operations on the leased promises to growing crops, grass, cattle, roads, fences, and improvemenis on said lend; and flintier, within 120 days after the •completion of any well, weather permitting, to fill and level all slash pits used in connection therewith and stock pile base material brought in to said site for Lessor, and upon abandonment of any well or other structure or facility on said land, to reasonably restore the surface of said land so occupied by such well, structure or feollity to as near its natural state neeossible.. Lessee further agrees to pay Lessor the sum of THREE THOUSAND FIVE HUNDRED AND NO/100 DOLLARS ($3,500.00) per acre for the site location- eletereesei,je t may be drilled on the leased prereises, suoh payment to be made prior to movin=e location, errnore, to pay the sum of THREE THOUSAND FIVE HUNDRED AND NO/100 DO ($3,500.00) per acre for each acre to be regularly used by Lessee for roadways, tankbatteries, or other above ground facilityplaced on the land by Lessee. Lessee shall consult with surface owner or Lessor prior to cutting, erecting or altering arty fence. Any changes to any fence such as, but not limited to erecting new fence, cutting any existing fence, altering any existing fence, etc. shall be done by a fence contractor mutually acceptable to Lessor and Lessee or surface owner, to Lessor or surface owner's reasonable specifications and at Lessee's expense. When requested by Lessor, Lessee will fence, with a good and substantial fence capable of turning livestock of ordinary demeanor, or in a high fenced Area, a like kind fence, all permanent type facilities it places on the leased premises. All roadways to be regular/y used by Lessee must be improved with base material with a minimum of six (6) inch compacted and regularly maintained.
SIGNED FOR IDENTIFICA
A/Am/M.1.y Ital. 101.c 41. to Blneslaf 5
154 19.) Lessee, his agents, servants, employees, contractors, or sub-contractors shall not be permitted to early firearms on to the leased premises, nor to fish or hutithereon, and any breach of this covenant such person shall not again be permitted to come on to the leased premises. 20.) The parties recognize that it is difficult to control fishing or the hunting of game on the leased premises and to ascertain the monetary damages to Lessor's surface rights caused by any such unauthorized activity. Lessee therefore covenants that If any of Its officers, agents, employees, servants or invitees bring on to the leased premises a dog or firearms of any description without the expressed written potmission of Lessor, Lessee will immediately pay to Lessor the sum of $1,000.00 for each of such incidents as agreed liquidated damages. Such payment is in addition to any fine or fines which might be imposed under the appropriate statutes or to any injunctive relief to which Lessor may be entitled from a court of equity. 21.) Lessee shall not have the right to use water from Lessor's water wells or surface water without Lessor's written consent. Lessee's right to take and use water from Lessor's wells not drilled by Lessee on the leased premises shall not include the right to use fresh water from any fresh water sands or strata underlying the leased premises for any secondary recovery operations-that may be conducted on the leased premises. 22..) Lessor shall have the right, at Lessor's owo risk and expense, and in accordance with the regulations of the Railroad Commission of Texas, to utilize for fresh water well purposes the well bore of any well drilled by Lessee on the leased promises prior to the parrument plugging and abandoning of any such oil or gas well. In the event that, prior to the time Lessee permanently plugs and abandons any such well, Lessee is furnished an approved (by the Railroad Commission of Texas) copy of Porrn P13, Lessee, instead of permanently plugging any such well, will plug the well at the base of the fresh water sand and install a cap on the surface end of the casing, following which I f Ste C will file, in the appropriate Railroad Commission District Office, the approved copy of Form P13, with two copies of Form W3, Plugging Record, In accordance with the statewide Rules 14(a) and 80 of the Railroad Commisiion of Texas. If Lessor assumes ownership of the well bore Lessor also assumes all liability for said well bore. . It is further agreed that Lessee will contact Lessor via telephone or facsimile to advise Lessor that Lessee is ready to abandon said well, and Lessor will hive twenty-four(24) hours from such time he is advised of such plugging decision to advise Lessee whether Lessor wishes to take over said welt bore to produce fresh water. • If Lesseo drills a separate water well on the leased premises and when the Lessee's need for the same has ens ,zed, the water well will be left open and become the property of Lessor, illessor so desires and so notifies Lessee, subject to the mles and regulations or laws promulgated by any state,' federal or local regulatory body 'having jurisdiction over the same. Lessorthrther agrees, from. and after the date of the turnover of a well, to indemnify, defend and hold harmless Lessee from any andall liability that may arise relative to Lessee's takingover said well. Lessor will not indemnify Lessee for any acts it did to the well bore or casing prior to turning over the well bore, 23.) a) VERTICAL WELLS: At the expiration of the primary term or the extended term hereof, or upon the expiration of the continuous operations as provided below, this lease shall terminate except insofar as it covers the following, end the amount of acreage which may be included in pooled units under Paragraph 4 above shall be limited to the acreage amounts prescribed by the government regulatory body having authority, but in no event shall the retained acreage be larger than 640.0 acres. • b) HORIZONTAL WELLS: The maximum authorized size of pooled units and retained units for horizontal wells (either oil or gas) shall be calcidated according to the following formula A (acreage) ss (L (actual lateral length drilled) x .11488) + 320, or such larger unit prescribed by special field rules or permitted by statewide Rule 86 for horizontal wells, but in no event larger than 640 acres. 24.) As used in the terms of this lease, the, words "if operations for drilling arc not commenced" or "commencement of drilling operations" shall be defined as the date on which the drilling of a well has actually commenced and commonly called 'spudded in'; and the "completion of a well' shall be defined as the first date on which the completion rig has actually moved off the leased premises, or the date on which oil and/or gas Is first produced from the well, whichever event occurs first. Any subsequent work done on the well will be deemed reworking operations. 25.) It is hereby specifically agreed and stipulated that in the event a well is completed as a producer of oil and/or gas on land adjacent and contiguous to the leased pmmises, and -velthitl 467 feet of the premises covered by this . lease, that Lessee herein is hereby obligated to, within 120 days after the completion date of.the well or wells on the adjacent acreage; as follows:
(1) to commence drilling operations on the leased acreage and thereafter continue the drilling of such off set well or wells with due diligence to a depth adequate to test the same formation from which the well or wells are producing from on the adjacent acreage; or
(2) pay the Lessor royalties asprovided for in this lease as if an equivalent amount of production of oil and/or gas were being obtained from the off-set location on these leased premises as that which is being produced from the adjacent well or wells; or (3) release an amount of acreage sufficient to constitute a spacing unit equivalent in size to the spacing unit that viould be allocated under this lease to such well or wells on the adjacent lands, as to the zones or strata producing in such adjacent well. •
SIGNED FOR IDENTIFICATIONelA 6 1,,Gam.rtItr'1.7 Hot At). .,k... ,o Marit.r
155 -a
26.) In the event Lessee does not remove all property and fixtures placed on the leased premises within ONE HUNDRED EIGHTY (180) DAYS after the termination of this lease, and does not make suitable arrangements with the Lessor within said period of time to leave such property on the premises for a set additional period of time, title to all of suoh property so left on the leased premises shall pass to and vest in Lessor. 27.) Once royalty checks have commenced being tendered, the mineral owner will be paid within sixty (60) days after the end of the month the production leaves the leased premises. Ifpayments are not forthcoming within the designated period, interest will again accrue on the unpaidlialance at the statutory rata If more than twelve (12) months transpire between royalty payments the lease shall expire as to those lands within the retained tract or pooled unit for such well, except where delay was caused by title problems or force majcure per Paragraph 11, or unless this lease is otherwise held in effect in any other manner provided herein. 28.) The mineral owners' royalty shall bear no cost or expense (direct or indirect) encountered by the Lessee or Lessee's subsidiaries prior to or subsequent to production. This nil° is to apply regardless of where the royalty is fact!, in the lease or division order and until title to enysuch oil or gas has changed from:Lessee to its purchaser. In any event, the Lessee assumes all risk of loss. for the oil or gas once it leaves the leased premises. 29.) Should Lessee have title to said lands, or any portion thereof, examined and have a title report or opittion(s) rendered, Lessee shall furnish to Lessor a copy of each such title report or opinion and any supplements thereto. A copy of each suoh report or opinion rendered shall be mailed to Lessor at the above address widen ninety (90) days after the receipt by Lessee of each report or opinion. Lessee shall not be liable In any way for the contents of any such report or opinion rendered and delivered tsLessor. 30.) Lessee shall promptly close all gates which Lessee, Lessee's agents, servants and/or employees may use in Lessee's operations on the leased premises, to prevent the escape of cattle or stook of Lessor through any open gates. Lessee further agrees to comply with all reasonable rules and regulations imposed by Lessor with regard to opening and closing and looking all such gates. If es a result of Lessee's failure to keep all gates locked any of the Lessor's cattle or livestock escape, then Lessee shall promptly reimburse to the Lessor all expenses incurred in rounding up such cattle or livestock and transporting dunt° the pasture from which they escaped. Additionally, if this paragraph Is violated, Lessee shall pay to Lessor, at Lessor's address not given above, a penalty of Five Hundred Dollars ($500.00) per violation, within 15 days of such violation. If Lessor so specifies, any gate installed over a cattle guard will be a sliding gate. All cattle guards will be wide enough to easily accommodate farm equipment 31.) Before building any pipelines upon saidpremises, Lessee is required to consult with Lessor or the Surface Owner as to the location of same end such mutual agreement will not be unreasonably withheld. It is the intention of the Lessor to assist operator in selecting the route that will cause the least amount of damage or interruption to the Lessor's operations. Lessee must also bury all pipelines at least thirty-six (36") inches below the surface. Standard farmland double-ditching method will be used_ by Lessee in construction of the pipeline by separating the topsoil from the subsoil dunng exoavallon and during the heeler:Ill operation, said subsoil mustbe placed in the open ditch first and then the toPsoll will be placed in the ditch to complete the backfilling operation. The width of the trench to be excavated Is limited to twelve (12") inches unless the pipeline is greater than six inches (6") in dianseter. All pipelines across the leased premises will be permanently idenefied and located by markings at all fence lines or roads traversed by such pipelines. In the event the premises is not subject to production from this tract or a pooled unit, or in the event Lessee transports ges from lands in which Lessor has no interest, then Lessee must not install or lay a pipeline across these lands without &dowering an easement for such pipeline, Should a gas pipeline from wells on the premises or lands pooled therewith he built, Lessee is not required to obtain an easement, but will nevertheless be liable for all surface damages. Lessee, at all times while this lade is in effect, is required to maintain the pipeline right-of-way in order to prevent or correct amkaige, Settlement and erosion of the soil as occasioned by its pipelines. No compressor shall be located within one-half (%) mile of a dwelllig, but in any event, Lessee shall have the right to hive at least one compressor at a mutually acceptable site on premises, perrnission for which shall not be unreasonably 32.) Lessee shall have the right to drill such water wells as maybe necessary for its operations on the premises. Fresh water use shall be restricted to the actual drilling for oil or gar on the leased premises or lands pooled therewithand shatinot bo used in.ny manner for secondary recovery flooding of any productive oil reservoir. Any water well drilled by Lessee on the leased premises shall be drilled in a workmanlike manner and completed in accordance with the general praetices in the area for the completion of water wells to be used for the production of water for livestock and:domestic, purposes (using windmills or other down hole pumping equipment normally used • in the area). Any water well so drilled shall be drilled in order to aecept a minimum of 4.5-inch 0.D. casing. In the event Lessee shall drill a water well on Lessor's premises, then upon Lessee's permanent cessation of use of such -water well, the Lessee shall leave the water well and the easing therein for the use of the Lessor, et Lessor's option and at Lessor's risk, however, the Lessee may remove any pump and motor installed by the Lessee. 33.) Lessee agrees to furnish Lessor a daily report for each day that drilling completion or reworking operations arc being conducted ma a well or wells located on said lands. The report will be transmitted via facsimile to Lessor's representative, if requested. Lessee further agrees to give Lessor at least twelve (12) hours advance notice of any logging, testing and coring operations to be conducted in any well drilled on said lands in order that Lessor may have a representative present at such operations. At Lessee's office and during Lessee's regular office hours, Lessor shall have access to all Information concerning the drilling, coring, testing and completing of all wells, including the driller's log and all elecnioal logs and surveys, and to all accounting books and records, production charts, records and information, concerning the Production. processing, transportation, sale and marketing of oil and gas from said lands. Lessee agrees to furnish Lessor with one (1) final print of all drillers logs; electrical logs and surveys obtained in the drilling of all wells on said lands, and one (1) copy of all core analyzes and test results obtained from all wells. One (1) copy of all applications and reports filed by Lessee with the Texas Railroad Commission or other regulatory
SIGNED FOR IDENTIFICATION:
Aden Adliq H.1.30134 Iwo to narreoSor
156 agencies In connection with Lessee's operations hereunder shall also be mailed to Lessor. Lessor has the right to be present and observe measurement of all production from each producing well. All information, data and copies to be funtished by Lessee under the provisions of this paragraph shall be furnished to Lessor until Lessee is advised in writing to the contrary. Any data submitted to Lessor shall be time delayed by at least sixty (60) days from completion and/or plugging and abandoning of the subject well. Lessee shall have no liability to Lessor or to any party for their reliance upon eisch information unless the information furnished is intentionally false or misleading. Should Lessor segue:Amore than one (1) copy of the information to be finished by Lessee under the provisioes of this paragraph, Lessee agrees to furnish, at Lessor's cost and expense, such additional copies as may be requested by Lessor. Lessor agrees to maintain In confidence ell information finished by Lessee pursuant to the provisions of this paragraph for so.long as this lease is maintained in force end affect as to the lands and depths on which producing wells located and information is furnished with respect thereto, and Lessor agmestot to divulge such information to any third party during such period of confidentiality. It is agreed and provided, however, that if Lessee or Lessee's agent or subcontractors release any such Informationto the indus, or if any such information is otherwise released through no fault of Lessor, Lessor shall not be thither bound by this agreement of confidentiality as to the information released by Lessee or Lessee's agents or subcontractors or otherwise. 34.) Within one hundred twenty (120) days (weather permitting) after the completion or abandonment of any well drilled or worked over on the leased premises, Lessee agrees that it will fill and level all slush pits, holes, ruts, ditches and drains andremove all non-water based drillingmud, shale and chemicals from said premises and will restore the surftioe of the leased premises, as nearly as possiblo, to its condition prior to the commencement of such operations. Lessee will cut the banks' of all slush pin; and let them drain and dry before leveling to insure no bog hole willibe created. In the event of failure of Lessee to comply with this paragraph, within the time specified as aforesaid; Lessor shall notify'Lessee by Certified Mail, Return Receipt Requested, of non-compliance of this paragraph. If Lestee does not comply with this paragraph within 30 days of said notification, Lessee shall pay to Lessor one and one-luilftimes the actual cost to Lessor for makingsaid repairs as agreed as liquidated damages =account of Lessee's failure to carry out its obligation as provided in this paragraph. Nothing hereth shall release Lessee from any liability for damages suffered by Lessor as a result of a blow-out or other damages occurring during Lessee's operations hereunder, and Lessee shall bo fully responsible for any and all damages resulting therefrom. 35.) Salt water must not be disposed of on the premises without the written consent of Lessor. 36.) The provide= contained herein regarding acreage covered by this lease to be held by drilling.operations on or production from any pooled unit or units shalinot be•altered or amended by any- pooling,, unitization or like agmenresst or instrurnent, or any ainenelmentthereto or ratification oracknowledgoient thereof, unless the same shall be specifically designated as en amendment of such paragraph for soh purpose. It 1 sthrther agreed that neither this leaSe norany terms orprovIsionshereof Will be altered, ainencled, extended orratified by any division order or transfer order execntedby Lessor, Lessor's successors, heirs, agents, or assigns; but that any dittision order or transfer order willbe solely for the purpose of Confirming the'extent•of Lesaoi's interest in production of oil and gas from the herein described preraises, or"any land Or lands pooled therewith,. and to comply wifirstatutory requirements. In the event of.Produetion, alt 'division orders prepared bY Lessee and its assigns will eliminate all references to ratification of Lessee's eats, ratilloation Of them* and ratification Ofges moil purchase contracts. lima statements are contained theroinonehratifieritinsare void and ofro effect. Anyansendment, alteration, extension or ratifleation of this lease, or of any term or provision of this lease, will be made only by an instrument clearly denominating its purpose and effect, describing the specific teems or provisions affected and the proposed change at modification thereof, and executed by the party against whomany such amendment, alteration, extension. or ratification is sought to be enforced, and any purported amendment, alteration, extension or,ratification not so drafted will be of no force or effect. 37.) Lessee shall furnish Lessor copies of all assignments of working interests within ninety (90) days from recording said assignment. Any assignee shall also provide Lessor with a name, address and telephone number for the oontact person for the assignee. 38.) All notices and information to be given hereunder shall be in writing and shall be sent by United States Mail or fax, postage prepaid and addressed to the party to whom such notice is given as folloy2L4, 780 If to Lessor: Shirley Mac Herbst Adams, P. 0. Box 37, Karnes City, Texas, telephone go-,784—,..9./5.7 If to Lessee: Alvin M. Barrett & Associates Inc., a Texas Corporation, 11202 Sandstone Street; A II- cle..." Houston, Texas 77072, 281/498.5878 • 39.) Within ninety (90) days after this lease has expired or any portion thereof has been forfeited and upon written request by Lessor, Lessee or any assignee thereof must thraish.Lesser, or Lessor's heirs or assigns, with a recordable release of this lease or such portions which have been forfeited by Lessee or its assigns under the terms . Of this lease agreement If Lessee or Lessee's assigns fail to.rovide the Release in the time required, Lessee will immediately pay to Lessor the sum of $500.00 as agreed liquidated damages. • 40.) Notwithstanding the termination of this lease as to part of the leased premises under the above provisions, Lessee shell have and retain such easements of ingress end egress over the remainder of the leased premises as shill be necessary to enable Lessee to develop and operate the portion or portions of this lease then In effect for the production of oil and gas therefrom, and it is Anthec agreedthat it shall not be necessary for Lessee to remove or relocate any pipe lines, tank batteries or other surface equipment or installations from any portions of the leased promises as to which thfilease has terminated for so long as same remain necessary for the development and operation of such portions of this lease as continue in force and effect, It is provided however, in no event shall Lessee be permitted to have more than one road leading to the location of a drilling Qiproddeing well. Upon the occurrence of any partial termination of this kale; Lessor shall have, and expressly reserves, an easement through the said lands and the depths and formations retainedbyLesseoin order to enable the exploration and/or production of oil, gas and/or
SIGNED FOR IDENTIFICATION:
11:4,11cebn 1/1 k .b Marsenbsi 8
157 other minerals in and from any depths and lands which are not thereafter subject to this Lease. The easement reserved herein shall be fully assignable by Lessor to any party, including any other oil, gas and mineral lessee, of depths or lands not then subject to this lease, and in the eventLessor assigns such easement to any third party, Lessee herein shall look only to =oh third party, provided Lessor gives Lessee notice of said casement and its assipment, and not to Lessor, for any claims, costs, expenses or damages occasioned by such third p s use of the easement herein reserved, specifically including, but not limited to, any claims that such third p s activities interfered with or damaged Lessee's wells, reserves, equipment, operations or other rights hereunder. 41.) LESSEE SHALL INDEMNIFY AND HOLD LESSORHARMLESS FROM AND AGAINST ANY AND ALLCLAIMS, ACTIONS, LIABILITY, LOSS, DAMAGE OR EXPENSE OF EVERY KIND AND NATURE, INCLUDING,BUTNOTLEMITED TO, REASONABLE ATTORNEY'S FEES AND COSTS, FOR DAMAGE TO PROPERTY OF ANY PERSON, FIRM. OR CORPORATION OR FOR INJURY TO OR DEATH OF ANY PERSON, INCLUDING, BUT NOT LIMITED% THE EMPLOYEES OF LESSEE, ITS SUCCESSORS, ASSIGNS, CONTRACTORS OR SUBCONTRACTORS, WHICH MAY, IN WHOLE OR IN PART, BE CAUSED BY OR RESULT FROM OPERATIONS CONDUCTED HEREUNDER OR THE ENJOYMENT OF THIS LEASE OR THE EXERCISE OF ANY RIGHT GRANTED HEREUNDER OR ANY OBLIGATION IMPOSED HEREBY. IN THE EVENT THIS LEASE 12 HELD OR INTERPRETED TO BE WITHIN THE SCOPE OF AN AGREEMENT AS DEFINED AND PROHIBITED BY CHAPTER 127 OF. THE TEXAS CIVIL PRACTICE AND REMEDIES CODE ("CHAPTER 127'), THE INDEMNITYPROVIDED INSHALL HERE BBAIVIENDED AND CONSTRUED TO LIMIT AND TO EX(.EYT FROM ITS APPLICATION ANY INDEMNITY FOR ANY LOSS OR. LIABILITY OCCURRING UNDER CIRCUMSTANCES THAT SUCH INDEKNITY IS PROHIBITED ORLIMITEDBY I HE APPLICATION .OF CHAPTER 127 AND LESSEE SHALL INDEMNIFY AND HOLD HARMLESS LESSOR, TILE SURFACE OWNER AND THEIR. RESPECTIVE SUCCESSORS LEGAL REPRESENTATIVES, ASSIGNS, AGENTS, CONDUCTORS, AND EMPLOYEES, ONLY TO THE rxrErrr OF MAXIMUM COVERAGES AND DOLLAR LIMITS OR LIABILITY PERMITTED BY CHAPTER 127; AND THIS LIMITED INDEMNITY OBLIOA.T1ON SHALL BEE9PPORTEDBY AVAILABLE LIABILITY INSURANCE FURNISHED BYLBSSEE (AND LESSEE SHALL FURNISH TO LESSOR CERTIFICATES OR OTHER EVIDENCE OF LIABILITY INSURANCE BEING IN Kam AND EFFECT). TO THE EXTENT THAT THE INDEMNITY PROVIDED HEREIN IS LIMITED OR INAPPLICABLE UNDER CHAPTER, 127, THE LAW OF CONTRIBUTION SHALL APPLY. 42.) Lessee, at Lessee's own expense, will provide and maintain in force during the existence of this Lease a commercial general liability insinence inthe amount of at least S3,000,000.00, covering L.., well as Lessee, for any liability for property damage or personal Wiry arising as a result of Lessee's ocmduoting operations on or off theta premises pursuant to this Lease, the exercise of any right granted hereunder or any obligation imposed hereby or associated in any way with activities conducted by Lessoo on or impacting the premises. This insurance is to be carried by one or More hunnance companies authorized to trim:set business in Texas. Lessee will Ruttish Lessor with certificates of all required by this Lease. LESSEE MUST COMPLY WITH ALL VALID LAWS, ORDINANCES AND REGULATIONS, wan& STATE, FEDERAL, .OR MUNICIPAL, APPLICABLE TO THE PREMISES.. T'HE USE WHICH LESSEE MATI:ES AND INTENDS TO MAKE OF THE mow sr.s WILL NOT RESULT IN THE DISPOSAL OR CYTIM, RELEASE OF ANY. HAZARDOUS SUBSTANCE OR SOLID WASTE ON OR TO THEYREMISES. IN THE SVENT THAT ANY HAZARDOUS SUBSTANCES, SOLID WASTES, OR OTHER POLLUTANTS ARE DISPOSED OR RELEASED ON AND/OR UNDER. THE PRE-MISES, RESULTINGIN THE CONTAMINATION OR POLLUTION TO ITIE PREMISES OR ANY ADJOINING PROPERTY, ARISING OUT OF SAID CONTAMINATION OR POLLUTION, CAUSED BY OR CONSENTED TO BY THE LESSEE, THE LESSEE SHALL INDEMNIFY AND HOLD HARMLESS THE LESSOR AND LESSOR'S HEIRS, EnarroRS, ADMINISTRATORS, SUCCESSORS, AND. ASSIGNS, FROM AND AGAINST ANY AND ALL LIABILITY FROM THE RULES AND REGULATIONS OE TILE TEXAS RAILROAD COMMISSION, THE COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION, AND LIABILITY ACT OF 1980, THE RESOURCE CONSERVATION AND RECOVERY ACT OF 1976, OR ANY OTHER STATE OR FEDERAL STATUTE, RULE OR REGULATION NOW INEXISTENCE OR HEREINAFTER ENACTED RELATING TO SUCH SUBSTANCE OR.WASTE ANDY RSSEE HAS THE Al3SOLUTE REspoNsuarry FORALL CLEANUP OF SAID POLLUTION OR CONTAMINATION ORJLECLAMATION OF THE PREMISES AND ALL COSTS AND EXPENSES THEREOF. 44.) rris AGREED THAT ANY gum ATLAW WELLBE INITIATED INTIM COURT OF PROPER JURISDICTION OF THE STATE OF TEXAS IN THE COUNTY WHERE THE LAND OR ANY ' PART THEREOF. BB LOCATED WITH APPEALS TO THE APPELLATE. COURT OF THE STATE OF TEXAS AND THAT THE LAW OF TEXAS WILL CONTROL IN CONSTRUING THIS LEASE. • 45.) Lessor hereby warrants title to Lease premises against claims by, through or under Lessor, but not otherwise, and Lessor's liability on such warranties shall in no event exceed the value of bonus paid to Lessor herein for any portion having defective title. 46.) Lessee shall promptly pay the owner of the surface of the leased premises a reasonable sum for any damages resulting to the surface of said premises and the mops and improvements located thereon which may be caused by or result from the operations of Lessee hereunder or pursuant to any grants hereunder, and Lessee will restore same to substantially their present condition, so far as can be reasonably bo done, as concerns any material (Mange in the surface of such premises caused by orresulting from operations of Lessee hereunder. Lessee agrees that if any oil based mud or drilling compound containing hydrocarbon base or any material which is harmful to the soil is Used in Lessee's operations of the Leased Premises, Lessee shall dispose of all such mud, compounds andMaterials from the Leased Premises in strict compliance with the applicable rules of the Railroad Commission of Texas before
SIGNED FOR IDENTIFICATION:
.. Okla It.eu )O2 .1.s 9 . 1
158 filling in thepit(s), leveling and restoring the surface, and all such harmful materials shall be disposed of by the Lessee. Drilling mud not containing any of said harmful substances may be disposed of in accordance with Texas AdministratiVe Code, Title 16, Part 1, Chapter 3, Rule 3.8 "Water Protection”, Lessor herein grants to Lessee permission to landfarna all water base drilling mud with a chloride concentration of 31000 milligrams per liter (mg/I.) or less; drilled cuttings, sands, and fiats obtained while using water based drilling fluid with a chloride concentration of 3,000 (inFaL) er less; and wash water used for cleaning drill pipe and other equipment from the drill sites used by Lessee on lands covered by this Oil and Gas Lease. 47.) Lessee Is hereby given. the option to extend the primary term of this lease for an additional three (3) years from the expiration of the original primary term. This option may be exercised by Lessee at any time during the last year of the original primary term by paying the sum of Five Hundred and No/100 Dollars ($500.00) per net mineral acre to the Lessor, or their heirs end assigns. This payment shall be based upon the number of net mineral acres then covered by this lease, and all of the provisions of this lease shall apply equally to this payment including, but not limited to, the provisions regarding changes In ownership. Should this option be exorcised as herein provided, it shall be considered for all purposes as though this lease originally provided for a primary term of six (6) years. In the event this lease is being maintained by any provisions hereof at the expiration of the original primary term, Lessee shall have a period of thirty (30) days front the data this lease ceases to be so maintained within which to exercise this option. 48.) Lessee is hereby granted all rights necessary to eonduct seismic operations upon the leased premises. If Lessee elects to conduct 3D seLmic operations upon the leased premises, Lessee agrees to pay the surface owner $15.00 per acre for each acre of the leased premises covered by said 3D seismic operation. After completion of such seismic operations, Lessee must restore the land to its original epn dition jutt prior to such operations and shall pay the surface owner and any tenants the actual amount of extraordinary damages, if any, not customarily caused by seismic operations, all normal and customary damages being Included within the sum of $15,00 per serce acre provided above. 49.) All covenants, obligations and liabilities of Lessee contained in this Lease shall survive the termination or expiration of this lease and Lessee shall remain wholly responsible and liable for the performance thereof notwithstanding such termination or expiration. 50.) Lessee agrees to provide a gate guard to control access to Lessor's property while drilling any oil or acs well. Lessor must consent to the location of any roads, which consent may not be unreasonably withheld. 51.) The parties agree that they may record a Memorandum atilt LBW in lieu ofrccording this Lease. IN WITNESS WHEREOF, this instrument Is executed oa the date first above wi
LESSOR
ALVIN M. BARRETT & ASSOCIATES INC. BY: Its LESSEE THE STATE OF TEXAS § COUNTY OP ATASCOSA § This instrument was acknowledged before-me on this .1/ ST day of August, 2009, by SEITItLEY IVIAB BER/3ST ADAMS,
crt. (4, ACFRED ALLEN VEIRil N eta ry P ubtlo, stem el Iloce s My commission Expltos '1/2 fl.ak 11, March II, 2913.
TILE STATU OF TEXAS COUNTY OF•IIARRIS This instrument was acknowledged before me on this day of 2009, by of ,CE----"E—TafiRETr ASSOCIATES, INC., a Texas Corporation, on its behalf.
NOTAItY Pt)BLIC, STATE, OP TEXAS
Prepared in the Law Office of: Alfred A. Steinle P. 0. Box 400 Jourdanton, Texas 78026
Mora 7774y Wk. 702.E Lu.e 20 6.W-bar 10
159 Notice of confidentiality rights: If you are a natural person, you may remove or strike any or all of the following information from any instrument that transfers an. interest in real property before it is filed for record in the Public Records: Your social security number or your driver's license number. te=121:tru rgaaa. OIL, GAS AND MINERAL LEASE
THIS AGREEMENT made this 14th day of August , 2009, between WILLIAM ALBERT HERBST, whose address is 23385 FM 791, McCoy, Texas 78113, Lessor (whether one or more), and
ALVIN M. BARRETT & ASSOCIATES INC., a Texas Corporation, 11202 Sandstone Street, Houston, Texas 77072, Lessee,
WITNESSETH: 1. Lessor, inconsiderationofTenandNo/100 Dollars and other good and valuable consideration, receipt of which is hereby acknowledged, and of the covenants and agreements of Lessee hereinafter contained, does hereby grant, lease and let unto Lessee: the land covered hereby for the purposes and with the exclusive right of exploring, drilling, mining and operating for, producing and Owning oil, gas, sulphur and all other minerals (whether or not similar to those mentioned), together with the right to make surveys on said land, lay pipe lines, establish and utilize facilities for surface or subsurface disposal of salt water, construct roads and bridges, dig canals, build tanks, power stations, telephone lines, \ ..molop-ohoeas4 and other structures on said land, necessary oruseful in Lessee's operations in exploring, drilling for, producing, treating, storing end transporting minerals produced from die land covered hereby or any other lanel adjacent thereto. The land covered hereby, herein called "said land, is located in the County of Ate ueosa • State of Texas , and is described as follows: 302.0 acres of land, more or less, in the Mark H. Moore Survey No.185, A-559 and the Octavius A. Cook Survey No. 195, A-176 in Atascosa County, Texas, and being the Same land set aside to William Albert Herbst in Division No.4 In an Agreement on DIvisionof Estate dated October 20, 1993, recorded in Volume 865, Page 506 of the Deed Records of Ataseosa County, Texas.
6 , ...!..400.14.0%-afi*nStt -cm lira% 111 •141 • • • • • • 4 .1 • 4 • I • 4 • • • I •• • • • • •••• • • • It/ t47003*Pr il.,601ii 1,034-C45ANI•
ao )1a: a p=a titrfillid& k Isi-ofeeqUiantiect. Lessor agreei to exceme any supplemental instrument requested by Lessee for a more complete or accurate description of said land. For the purpose of determining the amount of any bonus or other payment hereunder, said land shall be deemed to contain 30 . acres, whether actually containing more or less, and the above recital of acreage in any tract shall be deemed to be true acreage thereof. Lessor aneepts the bonus as lump sum consideration for this lease and all rights and options hereunder. 2. Unless sooner terminated or longer kept in force under otherprovisions hereof, this lease shall remain in force for a term of three (3) years from the date hereof, hereinafter called "prirnwy term", and as long thereafter as operations, as hereinafter defined, arc conducted upon said !and with no cessation r more than ninety (90) consecutive days. 3. As royalty, lessee covenants and a CCs: (a) To deliver to the credit of lessor, in the pipe line to which lessee may connect its wells, the equal oneeei 8) ono-fifth (1/5th) part of all oil produced and saved by lessee from.said land, or from time to time, at the option of lessee, to pay lessor the average posteci market price of such one- eighth-68) one-fifth (1/5th) part of such oil at the wells as of the day it is Inn to the pipe line or storage tanks, lessor's interest, in either case, to bear onc•eighdr(1-9 one-fifth (1/5th) of the cost of treating oil to render it marketable ippline oil; (b) To payiessor on gas and casmghead gas produced from said land (1 when ;old by lessee, . ' . 'one-fifth (1/5th) of the amount realized by leasee, computed at the mouth of,the well, or () when used by lessee off said land or in the manufacture of gasoline or other produots, the market value, at ti a.. mouth of the weitofolettleadettiti) one-fifth (1/5th) of such gas and casinghead as; (o)TtmTosioz : It444Y.- (101"Xia71 • '';'" , 44 an • .44 • • • •
kneeiradViii:116t 4M./t; stil¢ 147•Tan /,*icai t, ritrr CH.:611'6u
If, at the expirationof the primary term or at any time or times the er, there is any well on said land or on landS with which said land or any portion thereof has been pooled, capable of piriducing oil or gas, and all such wells are shut-in, this lease shall, nevertheless, continue in force es though operations were being conducted on said land for so long as said wells are shut-in, and thereafter this lease may be continued in force as if no shut-in had occurred. Lessee covenants and agrees to use reasonable diligence:to produce, utilize, or market the minerals capable of being produced from said wells, but In the exercise of such diligence, lessee shall not be obligated tee install or furniSh facilities other than well facilities and ordinary lease facilities of flow lines, separator, and lease tank, and shall not be required to settle labor trouble or to market gas upon terms unacceptable to lessee. lf, at any time or times after the expiration of the primary term, all such wells are shut-in for a period of ninety (90) consecutive days, and during such tune there arc no operations on said land, then at or before the expiratibn of said ninety 90) day eriod, p lessee shall pay or tender, by check or draft of lessee, as royalty, a sum equal to . . twenty-five dollars ($25.00) for each acre of land then covered hereby. Lessee shall make like payments or tenders at or before the end of caoh anniversary of the expiration of said ninety (90) day period if upon such anniversary this lease is being continued, in force solely by reason of the provisions of this paragraph. Each such payment or tender shall be made to the parties who at the time of payment would be entitled toreceive the royalties which would be paid under this lease if the wells were producing, and may be deposited in the PAY DIREcox TO LOSOR fiardr-st , or its successors, which shall continue as the depositories, regardless of changes In the ownersfilp orshut-in royalty. If at any time that lessee pays or tenders shut-in royalty, two or more parties are, or claim to be, entitled to receive same, lessee may, in lieu of any other method of payment herein
Hata Win Ka be Issse batrembe
ATTACH M 161 provided, pay or tender such shut-in royalty, in the manner above specified, eithaejointhpus-suelspaesiee-or separately to each in accordance with their respective ownerships thereof, as4eseeeenay-eleete Any payment hereunder may be made by check-oe-drefteof lessee deposited in the mail or delivered to the party entitled to receive payment or to a depository bankprovided for above on or before the last date for payment. Nothing herein shall impair lessee's right to release as provided in paragraph 5 hereof. In the event of assignment of this lease in whole or in part, liability for payment hereunder shall rest exclusively on the then owner or owners of this lease, severally as to acreage owned by each. 3A. "Gross Proceeds", as used herein, shall mean the total proceeds received by Lessee for any non- affiliated third-party sale of such oil, gas or other substance; provided, however, if any contract covering oil, gas or other substance produced from the lands covered hereby, or any contract used for the purpose of establishing the price of Lessor's royalty oil or gas, provides for any deduction for the expenses of production (except for Lessor's proportionate share of actual costs of extricating the sulphur, If any, from the gas and shrinkage, if any, resulting from sneh extraction) post production, gathering, dehydration, compression, transportation, manufacturing, treating, or marketing of such'oil or gas, then such deduction shall be added to the price received by Lessee for such oil or gas so that Lessor's royalty shall not be charged directly or indirectly with any such expenses. Provided, however, shoUld said gas contract provide for a deduction for transportation, shoe knee, or treating to 13381C0 gas markotabb downstream from Lessee's series meter, and such deduction be levied by a bona fide non-affiliated third party, then In such event, Lessor's Royalty Share shall bear Its proportion ate share ofnon-affillated third party trausirtatio a shrinkage and frosting deductions, but no other post production costs shoe n deducted from Lessor's Royalty Share. 3/3. The phrase "free of cost(s)" or "free of all costs", as used herein, shall mean that the royalty Interest shall not be charged and shall not bear any costs whidseever in connection with the exploration, production, gathering, compression, tranaportation (except "Third Party Transportation Costs", as hereinafter defined, actually Incurred by Lessee), marketing or "Treating', as hereinafter defined, of oil, gas or other substance pro duce d hereun der. Provided, however, thatLessor's royalty shall bear Its proportlenate share of applicable production, 'windfall profits and severance taxes properly assessable against and attributable to said royalty fewest, "Treating" shall mean those methods used by Lessee at the lease to remove contaminants from the wellhead hydrocarbons as may be necessary to piece the hydrocarbons In a merchantable condition. Provided, however, should it bo necessary for Lessee to Install an amine unit on the leased premises in order to make said gas marketable, Lessor shall bear its prorate share of shrinkage of such gas as contaminants are removed from the gas stream processed by said amino plant. However Lessor shall net bear its erorata share of fuel gas, amine, compression or other costs !accessary to operate said amine plant, "l'hird Party T rMisoortatlpn Costa" shall mean the tariff rate based transportation costs incurred by Lessee in an arm's length transaction with a bona fide third party that is not a subsidiary or affiliate of Lessee in order to take gas and/or liquid hydrocarbons from the point that-such hydrocarbons have been separated, treated (if necessary), processed (if performed) and placed in .a merchantable condition. 4. Lessen is hereby granted the right, at its option, to pool or unitize any land coveredby this lease with any other lend covered by this lease, and/or with any other land, lease, or leases, as to any or all minerals or horizons, so as to establish Units containing not more than 80 surface acres, plus 10% acreage tolerance; provided, however, units may be established as to any one or more horizons, or existing units may be enlarged as to any one or more horizons, so as to contain not more than.640 surface acres plus 10% acreage tolerance, if limited to one or more of the following: (1) gas, other thin casinghead gas, (2) liquid hydrocarbons (condensate) which are not liquids in the subsurface reservoirs (3) minerals produced from wells classified as gas wells by the conservation agency having jurisdiction. If larger units than any ofthese herein permitted, either at the time established, or after enlargement, are prescribed by special field rules' or permitted by statewide Rule 86 for horizontal wells for the drilling or operation of a well at a regular location, or for obtaining maximum allowable from any well to b; drilled, drilling, or already drilled, anysuch unit may be established or enlarged to conform to the size prescribed by special field rules or permitted by statewide-Rule 86 for horizontal wells. 1,essee shall exercise said option as to caoh desired unit by executing an Instrument Identifying suchunit end filingit forrecord in the public office in which this lease is recorded. Each of said options may be exercised by Lessee at any time and from time to time while this lease is in force, and whether before or after production has been established either on said land, or on the portion of said land included in the unit, or on other land unitized therewith. A unit established hereunder shell be valid end effective for all purposes of this lease even though there may be mineraI, royalty, or leasehold interests in lands within the unit which are not effectively pooled or unitized. Any operations conducted on any part of such unitized land shall be considered, for all purposes, except the payment of royalty, operationsconducted upon sold land under this lease. There shall be allocated to the land coveredby this lease within each such unit (or to each separate tract within the unit if this lease covers separate tracts within the unit) that proportion of the total production of unitized minerals from the unit, after deducting any used in lease or unit operations, which the number of surface acres in such land (or In each such 'separate tract covered by this lease within the unit bears to the total number of surface acres in the unit, and the produotion so alibcated shall be considered for all purposes, including payment or delivery of royalty, overriding royalty and any other payments out of production, to bo the entire production of unitized minerals from the land to which allocated in the same manner as though produced therefrom under the terms of this lease. The owner of the reversionary estate of any term royalty or mineral estate agrees that the accrual of royalties pursuant to this paragraph or of shut-in royalties from a well on the unit shall satisfy any Ihnitation of term requiring production of oil or gas. The formation of any unit hereunder which includes land not covered by this lease shall not have the effect of exchanging or tron.sferring any interest under this lease (including, without limitation, any shut-in royalty which may become payable under this lease) between parties owning interests in land covered by this lease and parties owning interests in land not covered by this lease. Neither shall it impair the right of Lessee to release as provided in paragraph 5 hereof, except that Lessee may not so release as to lands within a unit while there arc operations thereon for unitized minerals unless all pooled leeses are released as to lands within the unit. At any trifle while this lease is in force Lessee may dissolve any unit established hereunder by filing for record in the publics office -where this lease is recorded a declaration to that effect, if at that time no operations are being conducted thereon for unitized minerals. Subject to the provisions of this paragraph 4, a unit once established hereunder shall remain in force so long as any lease subject thereto shall remain in force. If this lease now or hereafter covers separate tracts, no pooling or unitization of royalty interests as between any such separate tracts is Intended or shall be implied or resul t merely from 2 Hal. Wm 141 Ica, U4r.Lba
162 (A l the inclusion of such separate tracts within this lease but Lessee shall nevertheless have the right to pool or upitize as provided in this paragraph 4 with consequent allocation ofproduction as herein provided. As used in this paragraph 4, the words "separate tract" mean any tract with royalty ownership differing, now or hereafter, either as to parties or amounts, from that as to any other part of the leased premises. ' 5. Lessee may at any time and from time to time execute arid deliver to Lessor or file for record &release or releases of this lease as to any part or all of said land or of any mineral or horizon thereunder, and thereby be relieved of all obligations, as to the released acreage or interest. 6. Whenever used in this lease the word "operations"shall mean operations for and any of the following: drilling, testing; completing, reworking, recompleting, deepening, plugging back or repairing of a well in search for or in an endeavor to obtain production ofoil, gas,.suiphur or other minerals, excavating a mine, preiduction of oil, gas, sulphur oeother mineral, whether or aet in paying quantities. 7. Lessee shall have the use, free from royalty, of water, other than from Lessor's water wells, led of oil and gas produced from said land in all operations hereunder. Lessee shall have the rot at any time to remove all machinery and fixtures placed on said land, including the right to draw and remove casing. No well shall-be drilled nearer than 200 feet to the house or barn now on said land without the consent of the Lessor. Lessee dill pay for damages caused by its operations to growing crops and timber on said land. 8. The rights and estate of any party hereto may be assigned from time to demist whole or in part and as to any mineral or horizon. All of the covenants, obligations, and considennious of this lease shall extend to and be binding upon the parties hereto, their heirs, successors, assigns, and successive assigne. No change or division in the ownership of said land, royalties, or other moneys, or any part thereof, howsoever effeoted, shall increase the obligations or diminish the rights of Lessee, including, but not limited to, the location end drilling of wells and the measurement of production.. Notwithstanding any other actual or constructive lmowledge or notice thereof of or to Lessee, its successors or assigns, no change or division in the ownership of said land or of the royalties, oriother moneys, or the right to receive the same, howsoever effected, shall be binding upon the then record owner of this lease until thirty (30) daYs after there has been furnished to such record owner at his or its principal place of business by Lessor or Lessor's heirs, successors, or assigns, notice of such change or division, supported by either orieinals or duly certified copies of the instruments which have been properly filed for record and which evidence such change or division, and of such court records end proceedings, transoripts, or other documents as shall be necessary in the opinion of such record owner to establish the validity of such change or division. If any such 'change in ownership occurs by reason of death of the owner, Lessee may, nevertheless pay or tender such royalties, or other moneys, or part thereof to the credit of the decedent in a depository bank provided for above. 9. In the event Lessor considers that Lessee has not complied with all Its obligations hereunder, both express and' implied, Lessor shall notify Lessee in writing, setting out specifically hi what respects Le,ssde has breached this contract. Lessee shall then have sixty (60) days alter receipt of said notice within-which to meet or commence to meet all or any part of the breaches alleged by Lessor. The service of said notice shall-be precedent to the bringing of any action by. Lessor on said lease for any cause, and no such action shall be brought until the lapse of sixty (60.) days after service of such notice on Lessee. Neither the service of said notice nor the doing of any acts by Lessee aimed to meet all or any of the alleged breaches shall be deemed an admission or presumption that Lessee has failed to perform all its obligations hereunder. If this lease is cancelled for any oause, It shall nevertheless remain in force and effect as to (1) sufficient acreage around each well as to which there are operations to constitute a drilling or maximum allowable unit under applicable governmental regulations, (but in no event less than forty acres), arch acreage to be designated by Lessee as nearly as practicable in the form of a square centered at the well, or in such shape as then existing spacing rules require; and (2) any past of said land inoluded in a pooled unit on which there are operations. Lessee shall also have such easements on said land as areneoessary to operations on the acreage so retained. 10. Lessor hereby warrants and agrees to defend title to said land by, through and under Lessor, but not otherWise. Lessor's rights and interests hereunder shall be charged primarily with any mortgages, taxes or other liens, or interest and other charges on said land, but Lesser agrees that Lessee shall have the right at any time to pay or redUce same for Lessor, either before or after maturity, and be subrogated to the rights of the holder theroOf and to deduct amounts so paid from royalties or other payments payable or which may become paysble to Lessor and/or assigns under this lease. If this lease covers a less interest in the oil, gas, sulphur, or other minerals in all or anypart of said land than the entire and undivided fee simple estate (whether Lessor's interest is herein specified or not) or no interest therein, then the royalties and other moneys accruing from any part as to which this lease covers less suoh full interest, shall be paid only in the proportion which the interest therein, if ant, covered by this lease; bears to the whole and undivided fee simple estate therein. All royalty interest covered by this lease (whether or not owned •bY Lessor) shall be paid out of the royalty herein provided. This lease shall be binding upon each party who exCeutes it without regard to whether It is executed by all those named herein as Lessor.
a) In the event any party is rendered unable, wholly or in part, by Force Majeure (as hereinafter defined) to carry out its obligations under this agreement, then the party relying on such Force Majeure (or its or their representatives) shall give thirty (30) days written notice of the Force Majeure with reasonably full particulars concerning it to the other party. The obligations of the party relying on the Force Majeure, insofar as they arc affected 3 02ISI01 a I..No Barrto.t.
163 by the Force Majeure, shall be suspended during the continuation of all the Force Majeure and for a reasonable period thereafter not to exceed thirty (30) days. b) The term "Force Majeure" as here employed shall include nets of God, strikes, lockouts, or the public enemy, wars, blockade, insurrections, riots, epidemics, landslides, lightning, fires, floods, tornadoes, hurricanes, explosions, acts or requests. inability or unavoidable delay in obtaining governmental permits or authorizaton for drilling or other operations to be controlled hereunder, any other governmental action, governmental delay, restraint, inaction, rules or orders of federal, state or municipal governments or of any federal, state or municipal officer or agent purporting to act under duly constituted authority, interruptions of transportation, freight embargoes, unavailability of drilling rigs, equipment or essential personnel, any other cause, whether of the kind specifically enutnerated above or otherwise, which is not reasonably within the control of the party claiming Force Majeure.
SEE ADDENDUM CONTAINING PARAGRAPHS 12 THROUGH 51 ATTACHED HERETO AND MADE A PART HEREOF FOR ALL PURPOSES.
itcrawa 4N:1161 1-• Icad, 6,www_haw 4
164 ADDINDUM NOTWITHSTANDING anything to the contrary hereinabove provided, it is expressly agreed and stipulated by and between the Lessor and Lessee that: 12.) Reference in this lease to "other minerals" shall be deemed to include, in addition to oil and gas, only such related sulphur and hydrocarbons as may be produced therewith and extracted therefrom and shall not include coal, lignite, uranium, fissionable materials, other sulphur, or any unrelated or hard minerals. 13.) The right to maintain this lease in force and effect beyond the expiration of the primary term by the payment of shut-in royalties as is set out in paragraph 3 supra, is a recurring right which maybe exercised by Lessee fromtime to time but shall not exceed an aggregate or cumulative period of tune of more than three (3) years. rightof Lessee to pool the acreage covered by this lease with other acreage, as is provided for in 14.) The right Paragraph 4 supra, hereby limited to the extent that If a well is drilled on the leased acreage arid thisoling po privilege is exercised, then at least one-half (4) of the unit must be land covered by this lease, or one-half (Yr) of this lease must be included within the unit, andif the well is drilled on the acreage pooled with this lease, then at least one- third (1/3rd) of the unit must be land covered by this lease, or one-third (1/3rd) of this lease must be included within the unit, at Lessee's discretion; provided, however, if the amount of acreage remaining which has not theretofore been included in a pooled unit or allocated to a producing well isinsufficient to satisfy the above requirement, then all such remaining available acreage shall be included within such unit. Anything herein to the contrary notwithstanding, it is understood and agreed that the provisions of this paragraph 14.), shall not apply to the pooling of this lease with any other Oil, Gas and Mineral Leases dated August 14, 2009, executed by Mary Ann Herbst May, Helen Louise Herbst, William Albert Herbst, Clunlen e Ann I3urgess, Shirley Mao HerbstAdams, Susan G. Herbst or William Albert Herbst and wife, Susan G. Herbst, as Lessor to Alym M. Barrett & Associates Inc., as Lessee that covers other acreage not covered by this lease. 15.) In the event a pooled unit is created under the provisions of paragraph 4 supra, production, drilling, or reworking operations on said unit shall not be effective to maintain this lease in force as to acreage outside of such unit beyond the end of the primary term. However, this lease maybe maintained in force as to such unpooled acreage M any other manner provided herein. . 16,) In the event Lessee exercises any poolingprivilego granted, Lessee agrees to fltrnish Lessor with a copy of any unit designation within thirty (30) days after the same is filed for record. 17,) The royalties which are to be paid under the terms of this lease for the production of oil or gas after the end of the primary term or continuous development, whichever later occurs, shall never be less than FIFTY AND NO/100 DOLLARS ($50.00) pernet mineral acre per annum forte number of acres which arc being held under each well, and the accountingperiod for suoli royalties shall be from January 1st through December 31st of each year during the tenure of this lease, commencing with January 1st following the first production of oil and/or gas from the leased premises, and in the event that there has been a deficiently of royalty payments made during the accounting period for which such minimum royalty payments are due, the Lessee shall have a period of ninety (90) days within which to makeup such deficiency from and after having received written notice from the Lessor Of such deficiency, and Lessee shall be deemed conclusively to have revolved such notice as of the date that same was mailed in a United States Post Office by certified mail, return receipt requested, addressed solely to the Operator as designated at the Railroad Commission, irrespective of the ownership of this lease. Evidence of such mailing shall be by Postal Receipt Form P.S. 3811. Should Lessee fail to make up such deficiency within the prescribed time, this lease shall terminate as to all parties, but such termination shall not relieve Lessee ofthe obli gatIon, of paying a minimum royalty in accordance with the terms of this. lease to its date of termination. It is provided, however, that such lease termination in the preceding sentence shall not apply to 13Q.PCO,L.P., BMT Q&O TX L.P., KEYSTONE O&G TX, L.P., LMBI 08c0 TX, L.P. 0840 TX, LP., THRU O&G TX, L.P., and any affiliates thereof, but any unpaid minimum royalty shall bear interest at the rate of ten percent (10%) per annum or the maximum lawful rate of interest for such sums, whichever is the lesser amount Lessee is in nowise obligated to maintain;this entire lease in force and effect, and upon releasing a portion.Of the acreage covexed hereunder shall be relieved of this minimmnroyalty provision as .to the acreage so released from and after the date of such release, and if released on other than an anniversary date, Lessee shall be liable for a prorate part of the annual minimum royalty up to the date of said release. This minimum royalty provision shall not be applicable to the period of time for which the shut-in royald es have been paid under the terms of this lease. • 18.) Lessee agrees to pay for any actual surface damages caused by its operations on the leased premises to growing crops, grass, cattle, roads, fences, and improvements on said land; and further, within 120 days after the •completion of any well, weather permitting, to fill and level all slush pits used in connection therewith and stock pile base material brought in to said site for Lessor; and upon abandonment of any well or other structure or facility on said land, to reasonably restore the surface of said land so occupied by such well, structure or facility to as near its natural state as possible. Lessee thrther agrees to pay Lessor the sum of THREE THOUSAND FIVE HUNDRED AND NO/100 DOLLARS (53,500.00) per acre for the site location for each well that may be drilled on the leased premises, such payment to be made prior to moving on the location; and, furthermore, to pay the stun of THREE THOUSAND FIVE HUNDRED AND NO/100 DOLLARS (S3,500.00) per acrd for each acre to be regularly used by. Lessee for roadways, tank batteries, or other above ground facility placed on the land by Lessee. Lessee shall consult with surface owner or Lessor prior to cutting, erecting or altering any fence. Any changes to any fence such as, but not limited to erecting new fence, cutting any existing fence, altering any existing fence, etc. shall be done by a fence contractor mutually acceptable to Lessor and Lessee or surface owner, to Lessor or surface owner's reasonable specifications and at Lessee's expense. When requested by Lessor, Lessee will fence, with a good and substantial fence capable of turning livestock of ordinary demeanor, or in a high fenced area, a like kind fence, ell permanent type facilities it places on the leased premises. All roadways to be re ularly used by Lessee st be improved with base material with a minimum of six (6) inch co d and regul rintained.
SIGNED FOR IDENTIFICATION:
6.1 5 these
165 19.) Lessee, his agents, servants, employees, contractors, or sub-contractors shall not be permitted to can-y firearms on to the leased premises, nor to fish or hunt thereon, and any breach of this covenant such person shall not again be permitted to come on to the leased premisei. 20.) The.parties recognize that it is difficult to control fishing or the hunting of game on the leased premises and to ascertain the monetary damages to Lessor's surface lights caused by any such unauthorized activity. Lessee • therefore covenants that if any of its office rs, agents, employees, servants or invitees bring on to the leased premises a dog otfireamis of any description without the expressed written permission of Lessor, Lessee will immediatelypay to Lessor the =no( S1,000.00 for each of such incidents as. agreed liquidated damages. Such payment is in addition to any fuicor fines which might be imposed under the appropriate statutes or to any Injunctive relief to which Lessor may be entitled from a..court of equity. • • 21.) Lessee shall not have the right to use water from Lessor's water wells or surface water without Lessor's written consent. Lessee's right to take and use water from Lessor's wells not drilled by Lessee on the leasedprentises shall not include the right to use freshwater from any fresh water sands or strata underlying the leased premises for • any secondary recovery operations that may be conducted on the leased premises. 22.) Lessor shall have the right, at Lessor's owrr risk and expense, and in accordance with the regUlations of the Railroad Commission of Texas, to utilize for fresh water well purposes the well'bore of any well drilled by Lessee on- the leased premises prior to the permanent plugging and abandoning of any such oil or gas well. In the event that, prior to the time Lessee pennaneetlyplugs and abandons any such well, Lessee is furnished an approved (by the Railroad Commission of Texas) copy of Form P13, Lessee, instead of permanently plugging any such well, will plug the well at the base of the fresh water sand and install a cap on the surface end of the casing, following which Lessee will file, in the appropriate Railroad Conunissien District Office, the approved copy of Form P13, with two copies of Form W3, Plugging Record, in accordance with the statewide. Rules 14(a) and 80 of the Railroad Commission of Texas. If Lessor assumes ownership of the well bore Lessor also assumes all liability for said well bore. dt is further agreed that Lessee will contact Lessor via telephone or facsimile to advise Lessor that Lessee is ready tonbandon saldwell, and Lessor will have twenty-four(24) hours from such time he is advised of such plugging decision to advise Lessee whether Lessor wishes to take over said well bore to produce fresh water. iIt Lessee drills a separate water well on the leased premises and when the Lessee's need for the same has ceased the water well will be loll open and become the property of Lessor, IfLessor so desires and sonotifies Lessee, subject to the rules and regulations or laws promulgated by any state, federal or local regulatory body having jmisdietion over the same. • Lessorfrtrtheragreel,frontand.afGerthedateofthetumover(if>3we11,toindemnify, defend and hold harmless Lessee froth any and all liability diet may arise relative to Lessor's taking over said well. Lessor will not indemnify Lessee for any rusts it did to the well here or easing prior to turning overtire well bore. :23.) a) VERTICAL WELLS: At the expiration of the primary term or the extended term hereof, or upon the expiration Of the continuous operation as provided below, this lease shell terminate except insofar as it covers the following, and theeimount of acreage which may be included in pooled:units under Paragraph 4 above shall be limited,to the acreage amounts prescribed by the government regulatory body having authority, leut in no event shall the: retained. acreage be larger than 640.0 acres. b) HORIZONTAL WELLS: The maximum authorized size of pooled units and retained units for horizontal wells (either oil or gas) shall be calculated according to the following formula A (acreage) p [L (actual lateral length drilled) x .11488] -17320, or such larger unit prescribed by special field rules or permitted by statewide Rule 86 for horizontal wells, but in no event larger than 640 acres. 24.) As used in the terms of this lease, the words "If operations for drilling are not commenced" or 'commencement of drilling operations' shall be defined as the date on which the drilling of a well has actually commenced and commonly called *spudded to'; and the "completion of a well" shall be defined as the first date on which the completion rig has actually moved off the leased premlees, or the date on which oil and/or gas is first • produced from the well, whichever event occurs first. Any subsequent work done on the well will be deemed reworking operations.
25.) It is hereby specifically agreed and stipulated that in the event a well is completed as a producer of oil and/or gas on land adjacent and contiguous to the leased premises, and within 467 feet of the premises covered by this 'lease, that Lessee herein is hereby obligated to, within 120 days after the completion date of the well or wells on the adjacent acreage; as follows: (I) to commence drilling.operations on the leased acreage and thereafter continue the drilling of such off-set well or wells with duo diligence to a depth adequate to test the same formation from which the well or wells are producing from on the adjacent acreage; or (2) paythe Lessor royalties as provided for in this lease as if an equivalent amount of production of oil and/or gas were being obtained from the off-set location on these leased premises as that which is being produced from the adjacent well or wells; or • (3) release an amount of acreage sufficient to constitute a spacing unit equivalent in size to the spacing unit that would be allocated tinder this lease to such well or wells on the adjacent lands, as to the zones or strata producing hi such adjacent well.
SIGNED FOR IDENTIFICATION: t2if/ 6 }wea1.A."1,21.1..4 es Mesous142
166 26.) In the event Lessee does not remove all property arid fixtures placed on the leased premises within ONE HUNDRED EIGHTY (180) DAYS after the termination of this lease, and does not make suitable arrangements with the Lessor within said period of time to leave such property on the premises for a set additional period of time, title to all of such property so left on the leased premises shall pass to and vest in Lessor. 27.) Once royalty cheeks have commenced being tendered, the mineral owner will be paid within sixty (60) days after the end of the month the production leaves the leased premises. Ifpayments are not forthcoming withm. the designated period, interest will again accrue on the unpaid balance at the statutory rate. If more than twelve (12) months transpire between royalty payments the lease shall expire as to those lands within the retained tract or pooled unit for such well, except where delay was caused by tido problems or force majeure per Paragraph 11, or unless this lease is otherwise held in effect in any otherraanner provided herein. 28.) The mineral owners' royalty shall bear= cost or expense (direct or indirect) encountered by the Lessee or Lessee's subsidiaries prior to or subsequent to production. Misrule is to apply regardless of where the royalty is fixed in the lease or division order and until title to any such oil or gas has changed from Lessee to its purchaser. In any event, the Lessee assumes all risk of loss for the oil or gas once it leaves the leased:premises. 29.) Should Lessee have title to said lands, or any portion thereof, examined and have a title report or opinion(s) rendered, Lessee shall furnish to Lessor a copy of each such title report or opinion and any supplements thereto. A copy of each such report or opinion rendered shall be mailedto Lessor at the above address within ninety (90) days after the receipt by Lessee of each report or opinion; Lessee shall not be liable in anyway for the contents of any such report or opinion rendered and delivered to Lessor. 30.) Lessee shall promptly close all gates which Lessee, Lessee's agents, servants and/or employees may use in Lessee's operations on the leased Premises, to prevent the escape of cattle or stook of Lessor through any open gates. Lessee further agrees to comply with all reasonable rules and regulations imposed by Lessor with regard to opening and closing and locking all such gates. If as a result of Lessee's failure to keep all gates locked any of the Lessor's cattle or livestock escape, then Lessee shall promptly reimburse to the Lessor all expenses incurred in rounding up such cattle orlivestook and transporting them to the pasture from which they escaped. Additionally, if this paragraph is.eriolated, Lessee shall pay to Lessor,. et Lessor's address Cast given above, a penalty of Five Hundred Dollars (S500.00) per violation, within 15 days of such violation. If Lessor so specifies, any gate installed over a cattle guard .will be a sliding eate. All cattle guards will be wide enough to easily accontroodate fart eripermet. 31.) Before building any pipelines upon seid premiees, Lessee is required to consult with Lessor or the Surface Owner as to the location of seine and such mutual agrkement will not be unreasonably withheld. It is the intention of the Lessor to assist operator in selecting the route that will cause the least amount of damage or interruption to the Lessor's operations. Lessee must also bury all pipelines at least thirty-six (36") inches below the surface. Standard farmland double-Ittobing method will be used by Lessee in construction of the pipeline by separating the topsoil from the subsoil during excavation and during thabaekfilloperation, said subsoil musthe placed in the open ditch first and then the topsoil willbe placed in the ditch to emarpletathe baekfaling operation. The width .of the trench to be excavated is limited to twelve (12") Inches unless the pipeline is greater than six inches (6") in diameter. All pipelines across the:leased premises will be peamanently idenufied and looted by markings at all fence •lines or roads traversed by such pipelines. In the event the premises is not subject to production from this tract or a pooled unit, or In the event Lessee transports gas from lands in which Lessor has no interest, then Lessee must not install or lay a pipeline across these lands without first eceurhig an easement' or such pipeline. Should a gas pipeline from well; 0.11 the.premises or lands peoled therewith be bilk, Lessee is net required to obtain an easement, but will nevertheless be liable for all surface damages. Lessee, at all times while this lease is in effect, is required to maintain the pipeline right-of-way in order to prevent or correct sinkage, settlement and erosion of the soil as occasioned by its pipelines No compressor shall be located within ono-half ('h) mile of a dwelli, but in any event, Lessee• shall have the right to have at least one compressor at a mutually acceptable site on premises, permission for which shall not be unreasonably withheld. 32.) Lessee shall have the right to drill such water wells as may be necessary for its operations on the premises. Fresh water use shall be restricted to the actual drilling for oil or gai on the leased premises or lands pooled therewith and shall not be used in any manner for secondary recovery flooding of any productive oil reservoir. Any water well drilled by. Lessee on the leased premises shall be drilled in a workmanlike manner and completed in accordance with the general practices in the area for the completion of water wells to be used for the production of water for livestock and domestic purposes (using windmills or other down hole pumping equipment normally used In the area). Any water well so drilled shall be drilled in order to accept a minimum of 4.5-inch O.D. casing. In the event Lessee shall drill aWater well on Lessor's premises, then upon Lessee's permanent cessation of use of such. -water well, the Lessee shall leave the water well and the casing therein for the use of the Lessor, at Lessor's option and at Lessor's risk, however, the Lessee may remove any pump and motor installed by the Lessee. 33.) Lessee agrees to furnish Lessor a daily report for each day that drilling completion or reworking operations are being.conducted on a well or was located on said lands. The report will he transmitted via facsimile to Lessor's representative, if requested. Lessee further agrees to give Lessor at least twelve (12) hours advance notice of any logging, testing and coring operations to be conducted inany well drilled on said lands ill order that Lessor may have a representative present at such operatibns. At Lessee's office arid during Lessee's regular office hours, Lessor shall have access to all information concerning the drilling, coring, testing and completing of all wells, including the driller's log and all electrical logs and surveys, and to all accounting books and records, production charts, records and information, concerning the production, processing, transportation, sale and marketing of oil and gas from said lands. Lessee agrees to furnish Lessor with one (1final print dell driller's logs, electrical logs and surveys obtained in the drilling of all wells on said lands, and one1) copy of all core analyses and test results obtained from all wells. One (1) copy of all applications and reorts d file by Lessee with the Texas Railroad Commission or other regulatory agencies in connection with Lessees ' openitio 's is er shall als be a led to Lesser Loss brie tic right to be
SIGNED FOR IDENTERCATION: eee/
2,..enafJae 7 Ilesbal rn3C1 se 1.1.
167 present and observe the measurement of all production from each producing well. All information, data and copies to be famished by Lessee under the provisions of this paragraph shall be furnished to Lessor until Lessee is advised in writing to the contrary. Any data submitted to Lessor shall be time delayed by at least sixty (60) days from completion and/oz plugging and, abandoning of the subject well. I Pcsee shall have no liability to Lessor or to any third party for their reliance upon such Information unless the Information furnished is intentionally false or misleading. Should Lessor request more than ono (1) copy of the information to be furnished by Lessee under the provisions of this paragraph, Lessee agrees to furnish, at Lessor's cost and expense, such additional copies as may be requested by Lessor. Lessor agrees to maintain ht confidence all information furnished by Lessee pursuant to the provisions of this paragraph for so long as this lease Is maintained in force and effect as to the lands and depths on which producing wells ITV located and, information is furnished with respect thereto, and Lesser agrees not to divulge such Information to any third party during such period of confidentiality, It Is agreed and provided, however, that if Lessee or I esoae's agent or subcontractors release any such information to the industry, or if any such information is otherwise released through no fault of Lessor, Lessor shall not be further bound by this agreement of confidentiality as to the information released by Lessee or Lessee's agents or subcontractors or otherwise. 34.) Within one hundred twenty (120) days (weather perraittiug) after the completion or abandonment of any well drilled or worked over on the leased premises, Lessee agrees that it will fill and level all slush pits, holes, ruts, ditches and drills emir= ove all non-water based drilling mud, shale and chemicals from said premises and will restore the surface of the leased premises, as nearly as possible, to its condition prior to the commencement of such operations. Lessee will cut the banks of all slushpits and letthera drain and dry before leveling to insure no bog hole will be created. In the event of failure ofLessee to complywith this paragraph, within the time specified as aforesaid, Lessor shall notify Lessee, by Certified Mail, Return Receipt Requested, of non-compliance of this paragraph. If Lessee does not comply with this paiagraph within 30 days of said notification, Ilessee shall pay to Lessor one and one-half times the actual cost toLessor for maldng said repairs as agreed as liquidated damages on account of Lessee's failure to carry out its obligation as provided in this paragraph. Nothing herein shall release Lessee from any liability for damages suffered by Lessor as a result of a blow-put or other damages occurring during Lessee's operations hereunder, and Lessee shall be fully responsible for any and all damages resulting therefrom 35.) Salt water must not be disposed of on the premises without the written consent of Lessor. 36.) The provisions contained herein regarding acreage covered by this lease to be held by drilling operations on or production from any pooled unit or units shall not be altered or amended by tiny pooling, unitization or like agreement or instrument, or any amendment thereto or ratification or acknowledgment thereof, unless the same shall be speeifically designated as an amendment of such paragraph for such purpose. It is further agreed that neither this lease nor any terms or provisions hereof willbe altered, amended, extended orratified by any division order or transfer order executed by Lessor, Ireaor's successors, heirs, agents, or assigns, but that any division order or transfer order will be solely for the purpose of confirming the extent ofLessar's interest in production of oil and gas from the herein described premises, or any land or lands pooled therewith, and to comply with statutory requirements. In the event of production, all division orders prepared by Lessee and Its assipi will eliminate all references to ratification of Lessee's acts, ratification of the unit and ratification of gas or oil purchase contracts. If stich statements are oentained therein, suoh ratifications aro Yoh:land ofno effect- AnYautendment, alteration, extension or ratifidation o f this lease, or of any term or provision. of this lease, will be made only by an instrument clearly denominating its purpose and ;effect, describing the specific terms orprovisious affected and the proposed change or modification thereof, and -executed by the partyagamst whom any such amendment, alteration, extension orratificatlon is sought to be enforoed, and any purported amendnient, alteration, extension or ratification not so drafted will be of no force or effect 37.) Lessee shall furnish Lessor copies of all assignments of working interests within ninety (90) days from recording said assignment Any assignee shall also provide Lessor with a name, address and telephone number for the contact person for the assignee. 38.) All notices and information to be given hereunder shall be in writing and shall be sent by United States Mail or fax, postage prepaid and addressed to the party to whom such notice is given as follows: Vaal If to Lessor: William Albert Herbst, 23385 FM 791, McCoy, Tr-f 78113, telephone 8-W-e.,25(9 .-- lite Lessee: Alvin M. Barrett Fs Aisoelates Inc., a Texas Corporation, 11202 Sandstone Street, Houston, Texas 77072, telephone 281/498-5878
39.) Within ninety (90) days after this lease has expired or any portion thereof has been forfeited and upon written request by Lessor, Lessee or any assignee thereof must furnish Lessor, or Lessor's heirs or assigns, with a recordable release of this lease or such portions which have. been forfeited by Lessee or its assigns under the terms 'of this lease agreement. If Lessee or Lessee's assigns fail to provide the Release in the time required, Lessee will immediately pay to Lessor the sum of 5500.00 as agreed liquidated damages. 40.) Notwithstanding the termination of this lease as to part of the leased premises under the above provisions, Lessee shall have and retain such easements of ingress and egress over the remainder of the leased premises as shall be necessary to enable Lessee to develop and operate the portion or portions of this lease then in effect for the production of oil end gas therefrom, and it is further agreed that it shall not be necessary for Lessee to remove or relocate any pipe lines, tank batteries or other surface equipment or installations fropa any portions of the leased premises as to which this lease has terminated-for so long as same remain necessary for the development and operation of such portions of this lease as continue in force and effect It is provided however, into event shall Lessee be permitted to have more than one road leading to the location of a drilling or producing well. Upon the occurrence of any partial termination of this lease, Lessor shall have, end expressly reserves, an easement through the said lends and the depths and formations retained byLessee in order to enable the exploration and/or pro uption of oil, gas and/or other minerals in and front any depths arid lands whit a not thereafter ' ' to t nentreserved
SIGNED FOR IDENTIFICATION: 111 (//
8 3,..4 1.1.1.4 V 11. roilear
168 herein shall be fully assignable by Lessor to any party, including any other oil, gas and mineral lessee, of depths or lands not then subj eat to this lease, and in the event Lessor assigns such easement to any third party, Lessee herein shall look only to such third party, provided Lessor gives Lessee notice of said casement and its assignment, and not to Lessor, for any claims, costs, expenses or damages occasioned by such third party's use of the easement herein reserved, specifically including, but not limited to, any claims that such third patty's activities interfered with or damaged Lessee's wells, reserves, equipment, operations or other rights hereunder. 41.) LESSEE SHALL INDEMNIFYAND HOLD LESSORHARMLESS FROM AND AGAINST ANY AND ALL CLAIMS, ACTIONS, LIABILITY, LOSS, DAMAGE OR EXPENSE OF EVERY KIND AND NATURE, INCLUI?ING, BUT NOT LIMITED TO, REASONABLE ATTORNEY'S FEES AND COSTS, FOR DAMAGE TO PROPERTY OF ANY PERSON, FIRM OR CORPORATION OR FOR INJURY TO OR DEATH OF ANY PERSON, INCLUDING, BUT NOT LIMITED TO, THE EMPLOYEES OF LESSEE, ITS SUCCESSORS, ASSIGNS, CONTRACTORS OR SUBCONTRACTORS, WHICH MAY, IN WHOLE OR IN PART, BE CAUSED EY OR RESULT FROM OPERATIONS CONDUCTLI..) HEREUNDER OR THE ENJOYMENT OF THIS LEASE OR THE EXERCISE OFANY' BIGHT GRANTED HEREUNDER OR ANY OBLIGATION IMPOSED BEREJ3Y, IN THE EVENT THIS LEASE IS HELD OR INTERPRETED TO BE WTIIIIN THE SCOPE OF AN Agnawr AS DEFINED AND PROHIBITED BY CHAPTER 127 OF THE TEXAS CIVIL PRACTICE AND REMEDIES CODE("CHAPTER 127"), THE INDEIvINTTY PROVIDED HEREIN SHALL 'MATO:ENDED AND CONSTRUED TO LIMITAND TO EXCEPT FROM ITS APPLICATION ANY INDEMNITY'FOR ANY LOSS OR LIABILITY OCCURRING UNDER CIRCUMSTANCES THAT SUCH INDEMNITY'S PROHIBITED OR LIMITED BY THE APPLICATION OF CHAFTER 127ANDLES3EE SHALL INDEMNIFYAND HOLD }LAWLESS LESSOR, THE SURFACE OWNER AND THEIR RESPECTIVE SUCCESSORS, LEGAL REPRESENTATIVES, ASSIGNS, AGENTS, CONTRACTORS, AND EMPLOYEES, ONLY TO THE EXTENT oF.Tng MAXIMUM COVERAGES AND DOLLAR LIMITS OR LIABILITYPERMITTED l3Y CHAPTER 127; AND THIS LIMITED INDEMNTEY OBLIGATION SHALL BE SUPPORTED BY AVAILABLE, LIABILITYINSURANCE FURNISHED BY LESSEE (AND LESSEE SHALL FURNISH TO LESSOR CERTIFICATES OR OTHER EVIDENCE OF LIABILITY INSURANCE BEING IN FORCE AND EFFECT). TO ME EXTENTTHAT THE INDEMNITY PROVIDED HEREIN IS LIMITED OR INAPPLICABLE UNDER CHAPTER 127, THE LAW OP CONTRIBUTION SHALL APPLY. 42.) Lessee, at Lessee's own expense, will provide and maintain in force during the existence of this Lease •a commercial general liability insurance in the amount of at least $3,000,000.00, covering Lessor as well as Lessee, for any liability for property damage or personal injury arising as a result of Lessee's conducting operations on or off these premises pursuant to this Leas; the exercise of any right granted hereunder or any obligation imposed hereby or asspoiated in any way with activities conducted by Lessee on or impacting the premises: This insurance is to be carried by one or more insurance companies authorized to transact business in Tem. Lessee will furnish Lessor with certificates of all insurance required by this Lease. 43.) LESSEE MUST COMPLY WEER ALL VALID LAWS, ORDINANCES, AND REGULATIONS, WHETHER STATE, FEDERAL, OR MUNICIPAL, APPLICABLE TO THE PREMISES. THE USE WHICH .LESSEE MAKES AND INTENDS TO MAKE OF tH1i PREMISES WILL NOT RESULT IN TEE DISPOSAL OR OTHER RELEASE OF ANY HAZARDOUS SUBSTANCE OR SOLID WASTE ON. OR TO THE PREMISES. IN THE EVENT THAT ANY HAZARDOUS SUBSTANCES, SOLID WASTES OR OTHER POLLUTANTS ARE DISPOSED OR RELEASED ON AND/OR LINDER Tilt PREMISES, RESULTING IN THE CONTAMINATION OR POLLUTION TO THE PREMISES OR ANY ADJOINING PROPERTY, MUSING OUT OF • SAID . CONTAMINATION OR POLLUTION, CAUSED BY OR CONSENTED TO BY THE LESSEF„ THE LESSEE SHALL INDEMNIFY AND HOLD HARMLESS THE LESSOR AND LESSOR'S 10)4, gnarroits, ADMINISTRATORS, SUCCESSORS, AND .ASSIGNS, FROM AND AGAINST ANY AND ALL LIABILITY FROM THE RULES AND REGULATIONS OF 'Tan TEXAS RAILROAD COMMISSION, TITS • CADMPEI31113EISIVE ENVIRONMENTAL RESPONSE, COMPENSATION, AND LIABILITYACTOF 1980, THE RESOURCE CONSERVATION AND RECOVERY ACT OF 1976, OR ANY OTHER. STATE OR FEDERAL STATUTE, RULE OP. REGULATION NOW IN EXISTENCE CRHEREINAFEER ENACTED RELATING0 SUCH SUBSTANCE OR WASTE AND LESSEEHAS THE AEtSOLUTEREaPONSIBILITY FORALL CLEANUP OF SAID POLLUTION OR CONTAMINATION OR. RECLAMATION OFTHE PREMISES AND ALL COSTS AND EXPENSES LtibREOF. 44.) rr IE AGREED THAT ANY SUITS AT LAW WILL BE minium Al Ta5 COURT OF PROPER JURISDICTION OF THE STATE OF TEXAS IN THE COUNTY WIIERE THE LAND OR ANY PART THEREOF 'BE LOCATED WITH APPEALS TO THE APPELLATE COURT OF THE STATE OF TEXAS AND THAT THE LAW OF TEXAS WILL CONTROL IN CONSTRUING THLS LEASE. 45.) Lessor hereby warrants title to Lease premises against claims by, through or under Lessor, but not Otherwise, and Lessor's liability on such warranties shall in no event exceed the value ofbonus paid to Lessor herein for any portion having defective title. 46.) Lessee shall promptly pay the owner of the surface of the leased premises a reasonable sum for any damages resulting to the surface of said premises and the crops and improvements located thereon which may be caused by or result from the operations of Lessee hereunder or pursuant to any grants hereunder, and Lessee will restore same to substantially their present condition, so far es can be reasonably be done, es concerns any material change in the surface of such promises caused by or resulting from operations of Lessee hereunder. Lessee agrees that if any oil based mud or drilling compound containing hydrocarbon base or any material which is harmful to the soil is used in T ern-c's operations of the Leased Premises, Lessee shall dispose of all such mud, compounds and materials from the I Psi led Premises in strict compliance with the applicable rules of the Railroad Commission of Texas before filling in the pit(s), leveling and restoring the surface, and all such harmful materials shall be disposed of by the Lessee. Drilling mud not containing any of saidh. MEE substances j, y be dispose elf in 'Coordance with Texas SIGNED FOR IDENTIFICATION:
Itvbs4 Ws* Barri.br 9
169 Administrative Code, Title 16, Part 1, Chapter 3, Rule 3.8 "Water Protection". Lessor herein grants to Lessee permission to landfarm all water base drilling mud with a chloride concentration of 3,000 milligrams per liter (mg/L) or less; drilled cuttings, sands, and silts obtained while using water based drilling fluid with a chloride concentration of 3,000 (rng/L) or less; and wash water used for cleaning drill pipe and other equipment from the drill sites used by Lessee on lands covered by this Oil and Gas Lease. 47.) Lessee is hereby given the option to extend the primary term of this lease for an additional three (3) years from the expiration of the original primary term. This option may be exercised by Lessee at any time during the last year of the original primary term by paying the sum of Five Hundred and No/100 Dollars ($500.00) per net mineral acre to the Lessor, or their heirs and assigns. This payment shall be based upon the number of net mineral acres then covered by this lease, and all of the provisions of th. s lease shall apply equally to this payment including, but not limited to, the provisions regarding changes in owneiship. Should this option bc exercised as herein provided, it shall be considered for all purposes as though this lease originally provided for a primary tam of six (6) years, In the event this lease is being maintained by any provisions hereof at the expiration of the original primary term, Lessee . shall have a period of thirty (30) days from the date this lease ceases to be so maintained within which to exercise this option. 46.) Lessee Is hereby granted ail rights necessary to conduct seismic operations upon the leased premises: If Lessee elects to conduct 3D seismic operations upon the leased premises, Lessee agrees to pay the surface owner $15.00 per acre for each acre of the leased premiss covered by said 3D seismic operation. After completion of such seismic operations, Lessee must restore the land to Its original condition just prior to such operations and shall pay the surface owner and any tenants the actual amount of extraordinary damages, if any, not customarily Caused by seismic operations, all normal and customary damages being Included within the sum of $15.00 per surface acre provided above, 49.) All covenants, obligations and liabilities of Leisee contained in this Lease shall survive the termination or expiration of this leaie and Lcsiee shall remain wholly responsible and liable for the performance thereof notwithstanding such termination or expiration, . . 50.) Lessee agrees to provide a gate-guard to control seams to Lessor's property while drilling any oil or gas well. Lessor must consent to the location of any roads, which consent may not be unreasonably withheld. . 51.) Tho parties agree that they mayrecord a Memorandum of the LEASE in.lieu of recording this Lease, t‘t) IN WITNESS WHEREOF, this instrument is executeda to first a t. 1) it
W • 21t7 LESSOR
ALVIN M. BARRETT & ASSOCIATES INC.
BY: Its LESSEE THE STATE OF TEXAS COUNTY OF ATASCOSA1 ..... , 51— This instrument was acknowledged before ma on this . •s. / da of Aut, t, 2009, by WILLIAM ALBERT HERBST.
------ .---4: PEutilAict, t1.'1S) rtoieMytryfcl--- t etoltHlir tei 2 Co mmIsslon Expires . zes) ggfeikA , Moic1131, 201.S _I 2
THE STATE OF TEXAS COUNTY OF HARRIS 'This instrument was acknowledged before me on this day of , 2009, by of ALVIN M. BARRETT & ASSOCIATES, INC., a Texas Corporistion, on its behalf.
NOTARY PUBLIC, STATE OIPMXAS
Prepared in the Law Office of: Alfred A. Steinle P. 0. Box 400 Jaurdanton, Texas 78026 10
170 TAB 4 RRC Field Rules for Eagle Ford Field • „RAILROAD COMMISSION OF TEXAS HEARINGS DIVISION
OIL AND GAS DOCKET IN THE EAGLEVILLE (EAGLE FORD-1) NO. XX-XXXXXXX FIELD, ATASCOSA, DIMMIT, GONZALES, LA SALLE, MCMULLEN, WILSON AND ZAVALA COUNTIES, TEXAS
FINAL ORDER
AMENDING THE FIELD RULES FOR THE EAGLEVILLE (EAGLE FORD-1) FIELD ATASCOSA, DIMMIT, GONZALES, LA SALLE, MCMULLEN, WILSON AND ZAVALA COUNTIES, TEXAS
The Commission finds that after statutory notice in the above-numbered docket heard on June 13, 2013, the presiding examiner has made and filed a report and recommendation containing findings of fact and conclusions of law, for which service was not required; that the proposed application is in compliance with all statutory requirements; and that this proceeding was duly submitted to the Railroad Commission of Texas at conference held in its offices in Austin, Texas.
The Commission, after review and due consideration of the examiner's report and recommendation, the findings of fact and conclusions of law contained therein, hereby adopts as its own the findings .of fact and conclusions of law contained therein, and incorporates said findings of fact and conclusions of law as if fully set out and separately stated herein.
Therefore, it is ORDERED by the Railroad Commission of Texas that the Field Rules adopted in Final Order No. XX-XXXXXXX, effective November 30, 2010, as amended, for the Eagleville (Eagle Ford-1) Field, Atascosa, Dimmit, Gonzales, La Salle, McMullen, Wilson and Zavala Counties, Texas, are hereby amended. The amended Field Rules are set out in their entirety as follows:
RULE 1: The entire correlative interval from 10,294 feet to 10,580 feet as shown on the log of the EOG Resources, Inc. - Milton Unit, Well No. 1 (API. No. 42-255-31608), Section 64, John Randon Survey, A-247, Karnes County, Texas, shall be designated as a single reservoir for proration purposes and be designated as the Eagleville (Eagle Ford- 1) Field.
RULE 2: No well for oil or gas shall hereafter be drilled nearer than THREE HUNDRED THIRTY (330) feet to any property line, lease line, or subdivision line. There is no minimum between well spacing requirement. The aforementioned distances in the above rule are minimum distances to allow an operator flexibility in locating a well; and the
98 OIL AND GAS DOCKET NO. XX-XXXXXXX
above spacing rule and the other rules to follow are for the purpose of permitting only one well to each drilling and proration unit. Provided however, that the Commission will grant exceptions to permit drilling within shorter distances and drilling more wells than herein prescribed, whenever the Commission shall have determined that such exceptions are necessary either to prevent waste or to prevent the confiscation of property. When exception to these rules is desired, application therefor shall be filed and will be acted upon in accordance with the provisions of Commission Statewide Rules 37 and 38, which applicable provisions of said rules are incorporated herein by reference.
In applying this rule, the general order of the Commission with relation to the subdivision of property shall be observed.
Provided, however, that for purposes of spacing for horizontal wells, the following shall apply:
a. A take point in a horizontal drainhole well is any point along a horizontal drainhole where oil and/or gas can be produced from the reservoir/field interval. The first take point may be at a different location than the penetration point and the last take point may be at a location different than the terminus point.
b. No horizontal drain hole well for oil or gas shall hereafter be drilled such that the first and last take point are nearer than ONE HUNDRED (100) feet to any property line, lease line or subdivision line.
c. For each horizontal drainhole well, the perpendicular distance from any take point on such horizontal 'drainhole between the first take point and the last take point to any point on any property line, lease line or subdivision line shall be a minimum of THREE HUNDRED THIRTY (330) feet.
For the purpose of assigning additional acreage to a horizontal well pursuant to Statewide Rule 86, the distance from the first take point to the last take point in the horizontal drainhole shall be used in such determination, in lieu of the distance from penetration point to terminus.
In addition to the penetration point and the terminus of the wellbore required to be identified on the drilling permit application (Form W-1H) and plat, the first and last take points must also be identified on the drilling permit application (Remarks Section) and plat. Operators shall file an as-drilled plat showing the path, penetration point, terminus and the first and last take points of all drainholes in horizontal wells, regardless of allocation formula.
If the applicant has represented in the drilling application that there will be one or
99 • • OIL AND GAS DOCKET NO. XX-XXXXXXX
more no perf zones or "NPZ's" (portions of the wellbore within the field interval without take points), then the as-drilled plat filed after completion of the well shall be certified by a person with knowledge of the facts pertinent to the application that the plat is accurately drawn to scale and correctly reflects all pertinent and required data. In addition to the standard required data, the certified plat shall include the as-drilled track of the wellbore, the location of each take point on the wellbore, the boundaries of any wholly or partially unleased tracts within a Rule 37 distance of the wellbore, and notations of the shortest distance from each wholly or partially unleased tract within a Rule 37 distance of the wellbore to the nearest take point on the wellbore.
A properly permitted horizontal drainhole Will be considered to be in compliance with the spacing rules set forth herein if the as-drilled location falls within a rectangle established as follows:
a. Two sides of the rectangle are parallel to the permitted drainhole and 33 feet on either side of the drainhole;
b. The other two sides of the rectangle are perpendicular to the sides described in (a) above, with one of those sides passing through the first take point and the other side passing through the last take point.
Any point of a horizontal drainhole outside of the described rectangle must conform to the permitted distance of the nearest property line, lease line or subdivision line measured perpendicular from the wellbore.
For any well permitted in this field, the penetration point need not be located on the same lease, pooled unit or unitized tract on which the well is permitted and may be located on an Offsite Tract. When the penetration point is located on such Offsite Tract, the applicant for such a drilling permit must give 21 days notice by certified mail, return receipt requested to the mineral owners of the Offsite Tract. For the purposes of this rule, the mineral owners of the Offsite Tract are (1) the designated operator; (2) all lessees of record for the Offsite Tract where there is no designated operator; and (3) all owners of unleased mineral interests where there is no designated operator or lessee. In providing such notice, applicant must provide the mineral owners of the Offsite Tract with a plat clearly depicting the projected path of the entire wellbore. In the event the applicant is unable, after due diligence, to locate the whereabouts of any person to whom notice is required by this rule, the applicant must publish notice of this application pursuant to the Commission's Rules of Practice and Procedure. If any mineral owner of the Offsite Tract objects to the location of the penetration point, the applicant may request a hearing to demonstrate the necessity of the location of the penetration point of the well to prevent waste or to protect correlative rights. Notice of Offsite Tract penetration is not required if (a) written waivers of objection are received from all mineral owners of the Offsite Tract; or, (b) the applicant is the only mineral owner of the Offsite Tract. To mitigate the potential for well collisions,
100 • • OIL AND GAS DOCKET NO. XX-XXXXXXX
applicant shall promptly provide copies of any directional surveys to the parties entitled to notice under this section, upon request.
RULE 3: The acreage assigned to the individual oil well for the purpose of allocating allowable oil production thereto shall be known as a proration unit. The standard drilling and proration units are established hereby to be EIGHTY (80) acres. No proration unit shall consist of more than EIGHTY (80) acres except as hereinafter provided. All proration units shall consist of continuous and contiguous acreage which can reasonably be considered to be productive of oil. No double assignment of acreage will be accepted. Additional acreage may be assigned to each horizontal drainhole well in accordance with Statewide Rule 86.
If after the drilling of the last well on any lease' and the assignment of acreage to each well thereon in accordance with the regulations of the Commission there remains an additional unassigned acreage of less than EIGHTY (80) acres, then and in such event the remaining unassigned acreage up to and including a total of FORTY (40) acres may be assigned as tolerance acreage to the last well drilled on such lease or may be distributed among any group of wells located thereon, so long as the proration units resulting from the inclusion of such additional acreage meet the limitations prescribed by the Commission.
An operator, at his option, shall be permitted to form optional drilling units of FORTY (40) acres. A proportional acreage allowable credit will be given for a well on a fractional proration unit.
For the determination of acreage credit in this field, operators shall file for each oil or gas well in this field a Form P-15 Statement of Productivity of Acreage Assigned to Proration Units. On that form or an attachment thereto, the operator shall list the number of acres that are being assigned to each well on the lease or unit for proration purposes. For oil or gas wells, operators shall be required to file, along with the Form P-15, a plat of the lease, unit or property; provided that such plat shall not be required to show individual proration units. There is no maximum diagonal limitation in this field.
RULE 4: The maximum daily oil allowable for a well in the field shall be determined by multiplying 2,000 barrels of oil per day by a fraction, the numerator of which is the acreage assigned to the well for proration purposes and the denominator of which is the maximum acreage authorized by these field rules for a vertical well for proration purposes, exclusive of tolerance acreage. Each oil well shall have unlimited net gas-oil ratio authority.
RULE 5: A flowing oil well will be granted administratively, without necessity of filing fees unless the Commission requires filing fees in the future for Statewide Rule 13(b)(4)(A) exceptions, a six month exception to Statewide Rule 13(b)(4)(A) regarding the requirement of having to be produced through tubing. A revised completion report will be filed once the
101 • • OIL AND GAS DOCKET NO. XX-XXXXXXX
oil well has been equipped with the required tubing string to reflect the actual completion configuration. This exception would be applicable for new drills, reworks, recompletions or for new fracture stimulation treatments for any flowing oil well in the field. For good cause shown, which shall include the well flowing at a pressure in excess of 300 psi, an operator may obtain administratively from the district director, without the necessity of filing fees unlessthe Commission requires filing fees in the future for Statewide Rule 13(b)(4)(A) exceptions, one or more extensions each with a duration of up to six months. If the request for an extension of time is denied, the operator may request a hearing. If a hearing is requested the exception shall remain in effect pendin2 final Commission action on the request for an extension.
RULE 6: An oil well will be granted administratively, without necessity of filing fees unless the Commission requires filing fees in the future for Statewide Rule 51(a) exceptions, a six month exception to the provisions of Statewide Rule 51(a) regarding the 10 day rule for filing the potential test after testing of the well. This will allow for the backdating of allowables on the oil wells without requiring a waiver to be secured from all field operators. This rule will grant the Commission the authority to issue an allowable back to the initial completion date for all oil wells in the field to prevent unnecessary shut- ins to alleviate potential overproduction issues related to the completion paperwork filings and producing the oil wells without tubing. If an extension of time is granted under Rule 5, the exception to Statewide Rule 51(a) under this rule is automatically extended for the additional lime.
The Eagleville (Eagle Ford-1) Field is a hydrogen sulfide field and shall be regulated pursuant to Statewide Rule 36.
Done this 6th day of August, 2013.
RAILROAD COMMISSION OF TEXAS
(Order approved and signatures affixed by Hearings Division's Unprotested Master Order dated August 6, 2013)
102 TAB 5 Affidavit of John McBeath CAUSE NO. 13-05-0466-CVA
SHIRLEY ADAMS, CHARLENE IN THE DISTRICT COURT BURGESS, WILLIE MAY HERBST JASIK, WILLIAM ALSBERT HERBST, HELEN HERBST and R. MAY OIL & GAS COMPANY, LTD., 218TH JUDICIAL DISTRICT
Plaintiffs, V.
MURPHY EXPLORATION & ATASCOSA COUNTY, TEXAS PRODUCTION CO.-USA A DELAWARE CORPORATION
Defendant.
AFFIDAVIT OF JOHN C. MCBEATH, P.E.
STATE OF TEXAS
COUNTY OF TRAVIS
Before me, the undersigned authority, on this day personally appeared John C. McBeath,
and stated the following:
1. "My name is John C. McBeath. I am over 18 years of age, of sound mind, and capable of
making this affidavit. The facts stated in this affidavit are.within my personal knowledge
and are true and correct.
2. I am a Vice President of Platt, Sparks & Associates, Consulting Petroleum Engineers,
Inc. ("Platt Sparks").
AFFIDAVIT OF JOHN C. McBEATH, P.E. Page 1
172 3. My employer, Platt Sparks is a petroleum engineering consulting firm that provides
consulting services to its clients in the oil and gas industry with regard to a wide array of
oil and gas related issues including, but not limited to, regulatory compliance and filings,
reservoir engineering studies, log analysis, reserve determination, economic analysis, fair
market value determinations, reservoir simulation, damage analysis, and lease royalty
provision analysis. A significant portion of my practice involves advising clients with
respect to Eagle Ford Shale ("EFS") formation exploration and development issues. I
have numerous clients involved in this trend and routinely advise them on issues such as
permitting wells, regulatory compliance, operational issues and other petroleum
engineering matters. As such, I am familiar with terminology and issues applicable to
operations within the EFS.
4. I am a 1987 graduate of the University of Texas at Austin with a Bachelor of Science
degree in Petroleum Engineering. I am a licensed Professional Engineer in Texas,
Wyoming, and California, a member of the Society of Petrophysicists and Well Log
Analysts, and a member of the Society of Petroleum Evaluation Engineers. A copy of
my resume is attached as Exhibit JCM 1.
5. I have reviewed PLAINTIFFS' MOTION FOR PARTIAL SUMMARY JUDGMENT
dated September 5, 2013.. I have been asked by counsel for Murphy to respond to
Plaintiffs' assertion that the Herbst B 1H Well is not an "offset well" under paragraph 25
of the leases at issue. ("Shirley Lease" and "William Lease") Specifically, I have been
asked whether the term "offset well" is a specialized term within the industry, and if so,
whether it has a commonly understand meaning within the industry.
6. The following is a list of information considered in my study:
AFFIDAVIT OF JOHN C. McBEATH, P.E. Page 2
173 a. Pleadings and court filings provided by Attorneys
b. Publically available data on EFS wells
c. Published Papers on technical aspects of the EFS
d. Publically available information from Investor Presentation materials of
Operators in the EFS.
e. Texas Railroad Commission ("RRC") rules and regulations
f. RRC hearing information, including proposals for decision and final
orders.
g. Affidavit of Mr. Kane Heinen
7. The EFS is a formation that underlies much of South Texas. It lies directly below the
Austin Chalk formation and has long been recognized as the hydrocarbon source rock for
the Austin Chalk. The EFS lies directly above the Buda Limestone formation. The EFS
varies in thickness from 20 feet to over 500 feet and in quality from top to bottom with
the Upper portion being carbonate-rich and the Lower portion shale-rich. The productive
part of the EFS is divided into oil, wet gas and dry gas areas. Exhibit ICM 1 contains a
map from the Energy Information Administration ("EIA") showing the different
producing areas of the EFS. Although a few wells historically produced from the
formation, development began in earnest in 2008 with the drilling of wells in La Salle
County by PetroHawk. These wells were the discovery of the Hawkville (Eagle Ford)
Field. Development has continued through current with most activity concentrated in the
oil and wet gas windows due to attractive liquids prices. Drilling efficiency has
improved significantly as well as the fine tuning of hydraulic fracture stimulation
treatments. Current development includes twenty-six Counties located in six RRC
AFFIDAVIT OF JOHN C. McBEATH, P.E. Page 3
174 districts. Exhibit JCM 3 is map from the RRC website showing the EFS development as
of January 2014.
8. The Lucas "A" 1H well was drilled by Comstock Oil & Gas, LP in December 2011,
targeting the EFS. The RRC well completion papers and directional surveys all indicate
that the horizontal lateral was landed in the EFS. The form W-2 filed by Comstock
indicates that the well was completed on February 23, 2012. Exhibit JCM 4 is a
collection of RRC forms relating to the Lucas "A" 1H well. I have also reviewed the
RRC completion papers and directional survey for the Murphy Herbst B 1H well.
Drilling was initiated on Murphy's Herbst B 1H well on June 8, 2012. The Herbst well
horizontal lateral was also completed in the EFS. Exhibit JCM 5 is a collection of RRC
forms relating to the Herbst B 1H well.
9. Drilling began on the Murphy Herbst 13 1H well less than 120 days after the Comstock
Lucas "A" 1H well was completed.
10. Based on the information contained in the Affidavit of Mr. Kane Heinen, it is clear that
the Herbst B 1H well was drilled by Murphy to fulfill their obligation under paragraph 25
of the Shirley and Williams leases.
11. The Murphy Herbst B 1H well was drilled to a depth adequate to test the same formatidn
from which the Comstock Lucas "A" 1H well produces.
12. Based on my review of Plaintiffs' petition and motion for summary judgment, it is my
understanding that Plaintiffs contend that the Murphy Herbst B 1H well is not an offset
well to the Lucas "A" 1FI well because it is not as close as legally possible to the lease
line of the Lucas "A" lease. Plaintiffs' use of the term "offset well" is not consistent with
the industry use of the term.
AFFIDAVIT OF JOHN C. McBEATH, P.E. Page 4
175 13. The term "offset well" is a specialized term within the oil and gas industry and is
commonly understood within the industry as describing any well drilled on an adjacent
lease or property. The term "offset well" can also refer to the closest well, even if it is
located on another lease. It is my opinion that Plaintiffs are viewing the term "offset
well," as used in paragraph 25 of the Lease, as "direct offset well". A direct offset well is
also a specialized term within the oil and gas industry, and is commonly understood to be
a well that is located directly across a lease line or other legal boundary. A direct offset
well can be located at the closest legal location or even closer if the operator applies for
and receives an RRC Rule 37 exception. A direct offset well is sometime called an
immediate offset well. Direct offset wells and immediate offset wells are included within
the term offset wells, but not all offset wells are direct or immediate offset wells.
14. The term "offset well" is used in RRC Rule 36 to define which wells can be used to
estimate the escape rate for use in calculating a radius of exposure for a well subject to
Rule 36. The RRC has never limited the wells available in this determination to wells
directly across the lease line, and Rule 36 is further evidence of how the term offset well
is understood within the industry.
15. RRC form H-1, related to RRC Rule 46, shows that the term "offset well" is understoOd
within the industry to describe any well drilled on adjacent property. The H-1 form
requires offset wells within Y2 mile of the subject well to be identified on a map.
16. Finally, RRC Proposals for Decisions ("PFD") and Final Orders ("FO") XX-XXXXXXX, 8A-
0211820, XX-XXXXXXX and 7C-0240684 contain further examples of the RRC's use of the
terms offset well, direct offset well and immediate offset well. These PFDs and FOs
further confirm that each of these specialized terms have a commonly understood
AFFIDAVIT OF JOHN C. McBEATH, P.E. Page 5
176 industry meaning, and that the term "offset well" is any well located on an adjacent
property, not just a well located directly across the lease line at the closest legal location.
That is a "direct offset well."
17. Based on my experience working with operators and other participants within the
industry, the usage of these terms by the RRC is consistent with how the terms are
commonly understood within the industry.
18. I have reviewed the Shirley lease, dated August 14, 2009, and it is my opinion that the
Lease was drafted specifically for horizontal drilling in the EFS. The lease contains
specific language regarding horizontal wells and the size of pooled units associated with
horizontal wells. By August 2009, there was significant EFS development activity
nearby in Live Oak and Karnes Counties.
19. Plaintiffs' contention that an offset well, as used in the Lease, exists to protect their
acreage from drainage is not correct. Due to the reservoir characteristics of the EFS, the
formation will not produce without large multi-stage hydraulic fracture jobs that provide
pathways between the formation and the wellbore. In the early development of the trend,
it was recognized that even with these hydraulic fracture stimulation jobs, a relatively
modest amount of reservoir is drained by each horizontal well. The RRC assigned leae
line spacing rules that reflect this reality. Recently, several operators have installed pilot
programs to test the sensitivity of well spacing to well recoveries. Early indications
confirm that spacing horizontal laterals as close as 225 feet results in well recoveries
comparable to much wider spaced laterals.
AFFIDAVIT OF JOHN C. McI3EATH, P.E. Page 6 177 20. The reservoir characteristics of the EFS further support my conclusion that the
specialized term "offset well," as used in Paragraph 25 of the Lease, is not commonly
understood as a well drilled within 350 feet of the Lease line, as Plaintiffs contend.
21. Plaintiffs refer to Williams and Meyers' Manual of Oil & Gas Terms for the definition of
Offset Clause. The definition of Offset Clause refers to Offset Well, another definition in
Williams & Meyers. Although Williams and Meyers states that the Offset Well is
intended to prevent drainage, neither definitions refer to a specific distance requirement
for an Offset Well. As stated above, the conventional concept of drainage across lease
lines has limited application in the EFS. Williams & Meyers offset well definition does
refer to "direct offsetting" when discussing wells that are directly across lease line on
equal-sized spacing units. Plaintiffs also refer to two on-line dictionaries having the same
definition of offset well. Before reading the Plaintiffs' motion I had not encountered
these sources. As stated above, it is my opinion that the term offset well encompasses the
more narrowly defined direct offset well. The on-line definitions used by Plaintiffs' more
accurately describe direct offset wells. My personal copy of "A Dictionary of Petroleum
Terms" 2" ed. contains the following definition:
offset well n: a well drilled on a tract of land next to another owner's tract on which there is a producing well.
22. Based on my review of the information discussed above and my professional experience
in the industry for the past 25 years, it is my opinion that the Herbst B 1H well drilled by
Murphy on the Shirley and William leases is an offset well as that term is commonly
understood and used in the industry and paragraph 25 of the leases.
AFFIDAVIT OF JOHN C. McBEATH, P.E. Page 7
178 Further, Affiant sayeth not.
C. 4 C. McBeath, P.E. exas Registered Engineering Firm F-1493
-•";::k0fTg,171111
11 1.* * f , JOHN C. McBEATH O 87813 4,E'd .... ...... "Ilk4II-YLt.. v." ci SUBSCRIBED TO AND SWORN before me this day of January 2014.
Not ry Public in and for the State of Texas
J.P47•4%, MICHELLE T. GILBERT •9'. • A Ncltary Public, State of Texas 1y Commission Expires May 09, 2014
AFFIDAVIT OF JOHN C. McBEATH, P.E. Page 8
179 TAB 6 RRC Form H-1 411111LROAD COMMISSION OF TEXAS. OIL AND GAS DIVISION Form H-1 05/2004 APPLICATION TO INJECT FLUID INTO A RESERVOIR PRODUCTIVE OF OIL OR GAS
1.0perator name 2. Operator P-5 No. (as shown on P-5, Organization. Report)
3.Operator Address
4. County 5. RRC District No.
6. Field Name 7. Field No.
8. Lease Name 9. Lease/Gas ID No.
10. Check the Appropriate Boxes: New Project ❑ Amendment ❑
If amendment, Fluid Injection Project No. F- Reason for Amendment: Add wells ❑ Add or change types of fluids ■ Change pressure ❑
Change volume 0 . Change interval ❑ Other (explain) RESERVOIR DATA FOR A NEW PROJECT
11. Name of Formation 12. Lithology (e.g., dolomite, limestone, sand, etc.) 13. Type of Trap 14. Type, of Drive during Primary Production (anticline, fault trap, stratigraphic trap, etc.)
15. Average Pay Thickness 16. Lse/Unit Acreage 17. Current Bottom Hole Pressure (psig)
18. Average Horizontal Permeability (mds) 19. Average Porosity (%)
INJECTION PROJECT DATA
20. No. of Injection Wells in this application . 21. Type of Injection Project: Waterflood ❑ Pressure Maintenance ❑ Miscible Displacement ■ Natural Gas Storage ❑
Steam ❑ Thermal Recovery ■ Disposal ❑ Other
22. If disposal, are fluids from leases other than the lease identified in Item 9? Yes ❑ No ❑
23. Is this application for a Commercial Disposal Well ? Yes ❑ No ❑
24. If for commercial disposal, will non-hazardous oil and gas waste other than produced water be disposed? Yes ❑ No ❑
25. Type(s) of Injection Fluid: Salt Water ❑ Brackish Water ❑ Fresh Water ❑ CO2 ❑ N2 0 Air ❑ H2S ■ LPG ❑ NORM ❑
Natural Gas ❑ Polymer ❑ Other (explain)
26. If water other than produced salt water will be injected, identify the source of each type of injection water by formation, or by aquifer and depths, or by name of surface water source:
CERTIFICATE I declare under penalties prescribed in Sec. 91.143, Texas Natural Signature Date Resources Code, that I am authorized to make this report, that this report was prepared by me or under my supervision and direction, Name of Person (type or print) and that the data and facts stated therein are true, correct, and complete, to the best of my knowledge. Phone Fax EXHIBIT For Office Use Only Register No. Amount $ II IR - 1.
See Reverse Side for Required Attachments • INSTRUCTIONS FOR FORM H-1 • 05/2004
1. Application. File the original Form H-1 application, including all attachments, with Assistant Director, Environmental Services, Railroad Commission of Texas, P. 0. Box 12967, Capitol Station, Austin, Texas 78711. File one copy of the application and all attachments with the appropriate Railroad Commission District Office. Include with the original application a non-refundable fee of $200, payable to the Railroad Commission of Texas. Submit an additional $150 for each request for an exception to Statewide Rule 46(g)(3) and/or (j)(5)(B).
2. Well Logs, Attach the complete electric log or a similar well log for one of the proposed injection wells or for a nearby well. Attach any other logging and testing data, such as a cement bond log, available for the well that supports this application.
3. (a) For a new project, attach a map with surveys marked showing the location and depth of all wells of public record within one-quarter (1/4) mile radius of the proposed injection well(s). (b) For an amendment to add wells to a previous authority, attach a map with surveys marked showing the location and depth of all wells of public record within one-quarter (1/4) mile radius of the additional wells, unless such data has been submitted previously for the project. (c) Table of Wells. For those wells in 3(a) or 3(b) that penetrate the top of the injection interval, attach a table of wells showing the dates drilled and their current status. The Commission may adjust or waive this data requirement in accordance with provisions in the "Area of Review" section of Statewide Rule 46 (Rule 46(e)).
4. Water Letter. Attach a letter from the Texas Commission on Environmental Quality (TCEQ) or its predecessor or successor agencies for a well within the project area stating the depth to which usable quality water occurs.
5. Form(s) H-1A. Attach Form H-1A showing each injection well to be used in the project. Up to TWO wells can be listed on each Form H-1A.
6. Use of Fresh Water. Attach Form H-7, Fresh Water Data Form, for a new injection project that includes the use of fresh water. An updated Form H-7 must be attached to Form H-1 for an expansion of a previously authorized fresh water injection project unless the fresh water is purchased from a commercial supplier, public entity, or from another operator.
• 7. Plat of Leases, Notice and Hearings
(a) Plat of Leases. Attach a plat of leases showing producing wells, injection wells, offset welts and identifying ownership of all surrounding leases within one-half (1/2) mile.
(b) Notice. (1) Send or deliver a copy of the application to the owner of record of the surface tract on which the well(s) is located; each Commission-designated operator of any well located within one-half (1/2) mile of the proposed injection well(s); and the clerk of the city and county in which the well(s) is located. If this is the initial application for fluid injection authority for this reservoir, send copies of the application to all operators in the reservoir. Attach a•signed statement indicating the date the copies of the application were mailed or delivered and the names and addresses of the persons to whom copies were sent.
(2) Attach an affidavit of publication signed by the publisher that notice of the application has been published in a' newspaper of general circulation in the county where the well(s) will be located. Notice instructions and forms may be obtained from the Commission's Austin Office, the Commission's website (www.rrc.state.tx.us) or the District Offices. Attach a newspaper clipping of the published notice.
(c) Protests and Hearings. An affected person or local government may protest this application. A hearing on the application will be held if a protest is received and the applicant requests a hearing, or if the Commission determines that a hearing is in the public interest. Any such request for a public hearing shall be in writing and contain: (1) the name, mailing address and phone number of the person making the request; and (2) a brief description of how the protestant would be adversely affected by the granting of the application. If the Commission determines that a valid protest has been received, or that a hearing would be in the public interest, a hearing will be held after issuance of proper and timely notice of the hearing by the Commission. If no protest is received within fifteen (15) days of publication or receipt in Austin of the application, the application may be processed administratively.
245 • •
r--
246 TAB 7 RRC Orders OIL AND GAS DOOKET NO. XX-XXXXXXX
THE APPLICATION OF REGENCY FS LP UNDER RULE 36 AND RULE 46 TO DISPOSE OF OIL AND WASTE CONTAINING HYDROGEN SULFIDE GAS INTO ITS TILDEN GPI WELL NO. 1, TILDEN, S. (WILCOX H2S DISPOSAL) FIELD, MCMULLEN COUNTY, TEXAS
Heard by: Donna Chandler on December 13, 2006
Appearances: Representing:
James Mann Regency FS LP Mike Donovan Michael Younger Clay Smith James Smith David Cantrell Rose Marie Hanks
EXAMINER'S REPORT AND RECOMMENDATION
STATEMENT OF THE CASE
Regency FS LP ("Regency") requests authority to inject sour gas in its Tilden GPI Well No. 1. Regency also requests that a new field, the Tilden,S. (Wilcox H2S Disposal) Field, be set up for this disposal well. A permit for injection pursuant to Statewide Rule 46 can be administratively granted. However, Statewide Rule 36(c)(10)(A) requires that a public hearing be held before the injection of fluid containing hydrogen sulfide (" H2S" or "sour gas").
The Commission's Field Operations section has reviewed the application and contingency plan and recommends approval of the application contingent on the following conditions:
1. That a new field designation is approved for the well, with such field name reflecting the potential presence of H2S in this area; and
2. That Regency demonstrates through plume analysis and offset well construction/plugging evaluation that the injected fluids will be confined to the proposed disposal zone.
EXHIBIT
247 • • Oil & Gas Docket No. XX-XXXXXXX Page 2
' This application was unprotested and the examiner recommends approval of the Rule 36 and Rule 46 authority.
DISCUSSION OF THE EVIDENCE
Regency's Tilden Gas Processing Plant has been in operation for many years, removing carbon dioxide ("CO2") and 112S from the gas stream produced by wells in the area. The waste CO2 and •H2S gas has been flared under TCEQ authority. Regency is proposing that this waste gas, or acid gas, be compressed into a liquid and disposed of into the proposed Tilden GPI No. 1. The Tilden GPI No. 1 has not yet been drilled, but is proposed to be located within the fenced area of the Tilden plant.
Regency requests authority to dispose of a maximum of 1,924 BPD of compressed acid gas. This is the equivalent of approximately 5,000 MCFD. The requested maximum surface injection pressure is 2,925 psig.
The Tilden GPI No. 1 will be drilled to a total depth of approximately 6,900 feet. The well will have three strings of casing cemented to surface: 13 3/s" to 350 feet, 9 %" to 5,200 feet and 5W' to total depth. The TCEQ recommends that useable quality water be protected to a depth of 100 feet and that the Carrizo be protected between 4,400 feet and 5,100 feet. Injection will be through tubing set on a packer at approximately 5,800 feet. All of the tubular equipment which may come in contact with H2S are H2S-resistant stainless steels and alloys that meet all Commission and industry standards for handling H2S.
The proposed disposal interval is the Wilcox between 5,870 feet and 6,800 feet. This zone has not been produced in any well within a /z mile radius but the application was filed pursuant to Rule 46 because Regency has not established that there is no production from this interval within. 21/2 miles. Establishing a new field designation called Tilden, S. (Wilcox H2S Disposal). Field will identify the proposed disposal zone as a formation now containing hydrogen sulfide. Any operators drilling in the area will be aware of the potential of H2S existing in an otherwise non-sour formation.
There are 11 wellbores within 1/2 mile of the proposed well. Three of the wells did not penetrate the proposed Wilcox disposal interval. Of the eight wells which penetrated the disposal interval, four were dry holes with no production casing set. All four of these wells have cement plugs across the base of useable quality water. The four remaining wells have production casing cemented to surface from deeper horizons. The completion and/or plugging of these wells is such that the proposed disposal will not affect useable quality water.
To estimate reservoir parameters at the location of the proposed Tilden GPI No. 1, Regency analyzed the log of the Vaughn Petroleum Company - J.M. Dickinson No. 2. This well is the closest well which penetrated the disposal interval and is approximately 1,600 feet to the southwest of the proposed disposal well. The Dickinson No. 2 was drilled in 1970 to a total depth of approximately 6,900 feet and was plugged and abandoned as a dry
248 • Oil & Gas Docket No. XX-XXXXXXX Page 3
hole. In the Dickinson No. 2, the average porosity of the Wilcox interval proposed for disposal is 17% over 117 feet of thickness. Average permeability is 10.8 md. The log of this well indicates the presence of at least 250 feet of shale overlying the disposal interval and at least 100 feet of shale below the disposal interval. These shale barriers will prevent the migration of acid gas from the disposal zone. Regency submitted two cross-sections of area wells demonstrating that both the proposed disposal interval and the confining shale barriers are continuous across the area.
Computer simulations of pressure and fluid migration were performed to predict the maximum probable extent of waste migrations. The numerical model SWIFT was used for the predictions. Input data included . the porosity and thickness determined from the Dickinson No. 2 well, a project life of 40 years, and an average daily rate of 2,100 BPD (which exceeds the requested rate of 1,924 BPD). This model has been accepted nationally for hazardous waste wells by the EPA and has been previously accepted by the Railroad Commission.
The initial pressure in the proposed disposal interval is assumed to be 3,400 psi. After 40 years.of injection, the pressure increase near the wellbore is calculated to be 3,975 psi. Approximately one mile away, the pressure is predicted to be 3,725 Psi after 40 years of injection.
The waste being disposed of consists of approximately 34% hydrogen sulfide, 64% carbon dioxide and 2% natural gas. Acid gas concentrations were calculated and mapped based on the modeling. The outer edge of the injection plume is represented by a. 1% contour line, where the fluid is 99% formation fluid and 1% acid gas. The maximum extent of this 1% line is 2,200 feet from the injection well after 40 years of injection. There are five vvellbores within 2,200 feet of the proposed well. Two of the five wells within 2,200 feet did not penetrate the disposal interval. Another two of the five wells have production casing cemented through the disposal.interval. The fifth well within 2,200 feet is the Dickinson No. 2 drilled in 1970 to a total depth of 6,913 feet. This well has no production casing but has a plug set at 4,960 feet and at 5,409 feet. The only interval open in the Dickinson No. 2 is the proposed Wilcox disposal interval, about 300 feet of shale above the disposal interval, and about 100 feet of shale below the disposal interval. Therefore, no existing wellbore within the injection, plume will be a conduit for migration of injected fluid outside the disposal interval.
To estimate maximum blowout release rate and pressures, Regency employed Fekete Associates, Inc. Fekete's study assumes that the acid gas injection well has been . drilled, completed and is actively injecting, prior to a loss-of-control incident at the wellhead. Worst case conditions are also assumed. The results of the study indicate a maximum escape rate through the 27/8" tubing of 14 MMCFD. Similarly, if the loss-of-control events occurs through the 5%" casing, the maximum escape rate would be 21.5 MMCFD.
Regency employed Quest Consultants, Inc. to perform gas dispersion modeling based on the results of the maximum escape rates previously determined by Fekete.
249 • • Oil & Gas Docket No. XX-XXXXXXX Page 4 Quest used a dispersion model called CANARY to determine the radius of exposure ("ROE") to. H2S. This model calculates release conditions, initial dilution of the vapor, and subsequent vapor dispersion. The model accounts for thermodynamics, mixture behavior, transient release rates, gas cloud density, initial velocity of the gas and heat transfer effects. This model has been previously accepted by the Railroad Commission. The calculated ROE for 100 ppm H2S, due to the maximum catastrophic release on the proposed injection well, is 2,655 feet. For 500 ppm, the calculated ROE is 1,495 feet. Both of these calculated ROE's are already within the area covered by the approved contingency plan for the Tilden Gas Processing Plant.
Regency has modified the contingency plan for the Tilden Gas Processing Plant to incorporate the proposed disposal operations. There are no residences or public places within the 100 ppm ROE for the disposal well and no public roads within the 500 ppm ROE for the well. The contingency plan for the plant covers a much larger area.
The injection system is designed with numerous safeguards. The wellhead will be equipped with emergency shut-down valves and down-hole check valves will be installed to prevent surface flow through the tubing. The tubing and casing pressure, tubing and casing temperature, injection rate, and H2S detection equipment will be continuously monitored. The gas processing plant is manned 24 hours a day with personnel trained in the recognition of and response to H2S alarms.
FINDINGS OF FACT
1. Notice of this application to inject fluid containing hydrogen sulfide was issued to all. surface owners and offsetting operators within % mile of the proposed well, and the McMullen County Clerk.on September 22, 2006. No protest was received.
2. Notice of the application was published in The Progress, a newspaper of general circulation in McMullen County, Texas, on September 20, September 27, October 4, and October 11, 2006.
3. The proposed injection well, the Tilden GPI Well No. 1, will dispose of compressed waste gas containing H2S. This waste gas is removed from hydrocarbon gas at Regency's Tilden Gas Processing Plant.
4. The Tilden GPI No. 1 will inject at rates up to 1,924 BPD of compressed acid gas. This is the equivalent of approximately 5,000 MCFD. This acid gas contains approximately 34% hydrogen sulfide, 64% carbon dioxide and 2% natural gas.
5. The proposed Tilden GPI No. 1 will be drilled, cased and cemented to confine the injected fluid to the proposed Wilcox disposal zone.
a. The requested injection interval is the Wilcox between 5,870 feet and 6,800 feet. This interval has not been completed in any well within 1/2 mile.
250 • • Oil & Gas Docket No. XX-XXXXXXX Page 5
b. The TCEQ recommends that useable quality water be protected to a depth of 100 feet and that the Carrizo be protected between 4,400 feet and 5,100 feet.
c. The well will have three strings of casing cemented to surface: 13 3/8" to 350 feet, 9 W to 5,200 feet and 5W to total depth.
d. Injection will be through tubing set on a packer at approximately 5,800 feet.
e. All of the equipment installed that might come in contact with H2S will be stainless steel and alloys that meet all Commission and industry safety standards.
f. If the injection fluid is not confined to the approved strata, then the disposal well permit will be suspended and disposal cease until the fluid 'migration from such strata is eliminated.
6. The field name of Tilden, S. (Wilcox H2S Disposal) should be approved for the disposal interval to alert other operators in the area to the possibility of encountering sour gas in this otherwise non-sour formation.
7. The disposal well is inside the fenced area which surrounds the Tilden Gas Processing Plant.
8. The requested maximum surface injection pressure is 2,925 psig.
9. The injection well, compressor and flow lines transmitting sour gas, will be designed to contain the sour gas, and monitoring devices will immediately shut down the system if any leakage of sour gas is detected.
10. The proposed disposal well is within the area covered by the contingency plan for the processing plant.
11. The calculated ROE for 100 ppm H2S due to a catastrophic release from the well is 2,655,2feet. The calculated exposure radius ROE for 500 ppm H2S due to a catastrophic release from the well is 1,495 feet.
12. There are no residences or public places within the 100 ppm ROE for the disposal well and no public roads within the 500 ppm ROE for the well.
13. No existing well will be a conduit for migration of injected fluid outside the disposal interval.
a. The maximum extent of the 1% acid gas plume is 2,200 feet from the
251 Oil & Gas Docket No. XX-XXXXXXX Page.6
injection well after 40 years of injection.
b. There are five wellbores within 2,200 feet of the proposed well.
c. Two of the five wells within 2,200 feet did not penetrate the disposal interval.
d. Two of the five wells within 2,200 feet have production casing cemented through the disposal interval.
e. The fifth well within 2,200 feet is the Dickinson No. 2 drilled in 1970 to a total depth of 6,913 feet. This well has no production casing but has a plug set at 4,960 feet and at 5,409 feet. The only interval open in the Dickinson No. 2 is the proposed Wilcox disposal interval, about 300 feet of shale above the disposal interval, and about 100 feet of shale below the disposal interval.
14. Regency has met the conditions for approval' set forth by the Field Operations section of the Railroad Commission.
CONCLUSIONS OF LAW
1. Proper notice was issued as applicable in all statutes and regulatory codes.
2. Altthings have.occurred and been accomplished to give the Commission jurisdiction in this matter.
3. The application of Regency FS LP to inject hydrogen sulfide gas into the Tilden GPI No. 1, Tilden, S. (Wilcox H2S Disposal) Field, McMullen County, complies with the applicable provisions of Statewide Rules 46 and 36, 16 T.A.C. §3.46 and §3.36.
EXAMINER'S RECOMMENDATION
Based on the above findings and conclusions, the examiner recommends that the application of Regency FS LP be APPROVED. A new field designation of Tilden, S. (Wilcox H2S Disposal) Field should be approved for the disposal interval.
Respectfully submitted,
Donna K. Chandler Technical Examiner
252 RAILROAD COMMISSION OF TEXAS OFFICE OF GENERAL COUNSEL
OIL AND GAS DOCKET IN THE TILDEN, S. (WILCOX H2S NO. XX-XXXXXXX DISPOSAL) FIELD, MCMULLEN. COUNTY, TEXAS
• FINAL ORDER APPROVING THE APPLICATION OF REGENCY FS LP FOR INJECTION OF FLUIDS CONTAINING HYDROGEN SULFIDE • IN ITS TILDEN GPI. WELL Nat TILDEN, S. (WILCOX H2S. DISPOSAL) FIELD MCMULLEN COUNTY, TEXAS •
The Commission finds that after statutory notice in the above-numbered docket heard on December 13, 2006, .the presiding examiner' has made and filed a report and recommendation containing findings of fact and conclusions of law, for which service was not required; that the, proposed application is in compliance with all statutory requirements; and that, this proceeding. was duly' submitted to the Railroad Commission of TeXas at conference held in its :offices in Austin, Texas.
The;Commission., after review and: due consideration of the examiner's report and recommendation, 'the findings of fact and conclubions of laW contained therein, hereby adopts as its own the findings of fact and conclusions of law contained therein, and incorporates said, findings of.fact and conClusionS of laW as.iffully set out and separately stated herein.
Therefore, it is ORDERED bY:the Rairroad CommiSsion of Texas that a new field designation known as the-Tilden, S. (Wilcox H2S Dispoial) Field, McMullen County, Texas, (Field No. 89960 575) be and it is hereby approved for the Tilden GPI Well No. 1.
It is further ORDERED by the Railroad Commission of Texas that Regency FS LP be and is hereby authorized to-dispose of fluids containing hydrogen sulfide into its Tilden GPI WeltNo. 1, Tilden, S. (Wilcox H2S Disposal) Field; McMillen County, Texas, pursuant to Statewide RUle 36(c)(10)(A).
It is further ORDERED by the Railroad Commissio'n of Texas that Regency.FS LP is hereby authorized to conduct dispotal Operations in the Tilden GPI Well No. 1, Tilden, S. (Wilcox H2S Disposal) Field, McMullen County, Texas, subject to the following terms and conditions:
SPECIAL CONDITIONS:
1. Waste shall only be injected into strata in the subsurface depth interval from 5870 feet to 6800 feet.
253 • OIL AND GAS DOCKET NO. XX-XXXXXXX Page 2
2. The injection volume shall not exceed 1924 barrels of acid gas per day.
3. The maximum operating surface injection pressure shall not exceed 2925 psig.
4. A permanent marker shall be placed on the wellhead of the Tilden GPI Lease Well No. 1 after injection ceases to notify persons of possible high hydrogen sulfide content in this wellbore.
STANDARD CONDITIONS:
1.. Injection must be through tubing set on a paCker. The packer must be set no higher than 100 feet above the top of the permitted interval.
2. The District Office must be notified 48 hours prior to: a. running tubing and setting packer; b. beginning any workover or remedial operation; c. conducting any required pressure tests or surveys.
3. The wellhead must be equipped with a pressure observation valve on the tubing and for each annulus.
4. Prior to beginning injection, and subsequently after any workover, an annulus pressure test must be performed. The test pressure must equal the maximum authorized injection pressure or 500 psig, whichever is less, but must be at least 200 psig. The test must be performed and the results submitted in accordance with the instructions of Form H-5.
5. The injection pressure and injection volume must be monitored at least monthly and reported annually on Form H-10 to the Commission's Austin Office.
6. Within 30 days after completion, conversion to disposal, or any workover which results in a change in well completion, a new Form W-2 or G-1 must be filed in duplicate with the District .Office to show the current completion status of the well. The date of the disposal well permit and the permit number must be included on the new Form W-2 or G-1.
7. Written notice of intent to transfer the permit to another operator must be submitted to the Commission at least 15 days prior to the date the transfer will occur by filing Form P-4.
8. This permit will expire when the Form W-3, Plugging Record, is filed with the Commission.
9. That the well be identified and operated according to Permit Number
254 I '
OIL AND GAS DOCKET NO. XX-XXXXXXX Page 3
Provided further that, should it be determined that such injection fluid is not confined to the approved strata, then the permission given herein is suspended and disposal operation must be stopped until the fluid migration from such strata is eliminated. The special permit conditions may be modified after notice and opportunity for hearing to prevent migration of injection fluid from the approved strata.
Done this 23rd day of January, 2007.
RAILROAD COMMISSION OF TEXAS
(Order approved and signatures affixed by OGC Unprotested Master Order dated January 23, 2007)
255 • • ************************************************* KEY ISSUES: CONFISCATION * * good faith claim to title * * faulting * * * * * FINAL ORDER: R37:GRANTED * ************************4************************
RULE 37 CASE NO. 0213270
APPLICATION OF COASTAL OIL & GAS CORPORATION FOR AN EXCEPTION TO STATEWIDE RULE 37 FOR THE ADAME GU LEASE, WELL NO. 2, WILDCAT (00008001) FIELD, JEFFRESS, N.E. (VICKSBURG, LO.) (46091450) FIELD, JEFFRESS, N.E. (T, LO.-FB,A) (46091400) FIELD, JEFFRESS, N.E. (VICKSBURG T) (46091500) FIELD, JEFFRESS, N.E. (VICKSBURG T LO) (46091550) FIELD, JEFFRESS, N.E. (VICKSBURG L) (46091430) FIELD, HIDALGO COUNTY, TEXAS
APPEARANCES:
FOR APPLICANT: APPLICANT:
Doug Dashieli (attorney) Coastal Oil « Gas Corporation Steve Salge R. E. Hilty Terry Payne
FOR PROTESTANT: PROTESTANT:
George C. Neale (attorney) Coates Energy Trust Sherrie Green
PROCEDURAL HISTORY
Date of Hearing: October 23, 1996 Transcript Received: December 1, 1996 Heard By: Meredith Kawaguchi, Legal Examiner Margaret Allen, Technical Examiner PFD Circulation Date: February 7, 1997 Current Status: Protested
EXHIBIT
258 I 76 Rule 37 Case No. 0213270 Page 2
STATEMENT OF THE CASE
Coastal Oil & Gas Corporation ("Coastal") has applied to drill a second well, Well No. 2, on its 170.52 acre Adame Gas Unit in Hidalgo County, Texas. Coastal requests a Rule 37 permit for the following fields: the Jeffress, N.E. (Vicksburg Lo) Field, which is the primary objective; the Jeffress, N.E. (T, Lo-FB,A) Field; the Jeffress, N.E. (Vicksburg T) Field; the Jeffress, N.E. Nicks. T-Lower) Field; the Jeffress, N.E. (Vicksburg L.) Field; and Wildcat (above 16,500').
Coastal proposes to locate the well 349' from its nearest lease line, whereas field rules for all applied-for fields require a distance of 467'. Therefore, a Rule 37 exception is necessary.
Coastal's application is protested by Coates Energy, Trust ("Coates"). Coates owns a royalty interest and appears to own an unleased mineral interest below 13,710' under an immediately offsetting tract. Initially, Coastal challenged Coates' standing to protest but withdrew its objection after conceding that Coates probably has mineral ownership below • 13,710' on the tract to the east of the Adame Gas Unit. Coates also claims ownership of a strip of land within the Adame Gas Unit on its eastern edge. .This claim has resulted in a title dispute between Coastal and Coates that is now before the courts. The proposed well is not located on this disputed strip.
Before presenting its technical case on the merits, Coastal established its good faith claim to title to the disputed strip through deeds, oil and gas leases, and an affidavit of adverse possession. Coates did not contend that Coastal failed to prove a -good faith claim to title. The parties recognize that the title question must be resolved by the courts.
DISCUSSION OF THE EVIDENCE
Coastal presented the only evidence concerning the merits of its Rule 37 application. Its case is based on conftcation; the issue of waste was not addressed.
The primary target, the Jeffress, N.E. (Vicksburg Lo) Field, was referred to throughout the hearing as the "W" sand. The lower Vicksburg in Hidalgo County is composed of a sequence of sands amid a series of down-to-the-basin and antithetic faults. Coastal designated four sand objectives in this area, the "W" sand being the deepest at approximately 13,400'.
The original recoverable reserves under the Adame Gas Unit in the "W" sand were 7.3 billion cubic feet ("BCF") of gas. Decline curve analysis indicates that the existing well, the Adame Well No. 1, will ultimately recover only 2 BCF. Because of faulting in the upper lobe of the "W" sand, approximately 240' of section is missing from the Adame Well No. 1. Therefore, the net pay that is characteristic of that upper lobe in surrounding wells is not available to the Adame Well No. 1. An offset well, the Coastal E-1, is draining the area of the proposed well on the Adame Gas Unit. Ultimately, if this drainage continues unchecked, the Coastal E-1 will recover
259 Rule 37 Case No. 0213270 Page 3
approximately 2.9 BCF from under the Adame Gas Unit. (Total recovery for the Coastal E-1 is estimated to be 10.5 BCF.) There remain current recoverable reserves under the Adame Gas Unit that will be unrecovered by Coastal if Coastal does not drill a second well on The unit. Royalty owners within the Adame Gas Unit do not participate in production in the "W" sand from any offset well.
There are no regular locations that will afford the mineral owners an opportunity to .recover their share of the hydrocarbons in the "W" sand. Due to extensive faulting in the area, a regular location to the east of the proposed location would encounter the downthrown side of Fault "E". All regular locations in the southern portion of the Adame Gas Unit fall in the middle of Fault "D".
If Coastal drilled at these regular locations, it would again lose a large section of the "W" sand, with significant. decrease in the well's recoverable reserves. This loss of a large section of the reservoir combined with reduced net pay (less than 50') as one moves west in the reservoir on the southern portion of .the tract make it impossible for applicant to recover its fair share from this portion of the tract. The net pay is approximately 50' at the proposed location.
EXAMINERS' OPINION
The examiners are of the opinion that an additional well on the Adame Gas Unit is necessary to protect the correlative rights of the Adame royalty owners, who do not share in production 'from the "W" sand from any offset well. Because of loss of a section of reservoir due to the fault, the existing well will recover only 2 BCF of the recoverable gas of 7.3 BCF under the Adame Gas Unit.
A Rule 37. location is necessary. Wells at regular locations would encounter the numerous faults and consequent loss of a portiori of the reservoir. At such locations Coastal and its royalty owners would not have an opportunity to recover the hydrocarbons under the Adame Gas Unit. The proposed_ Rule 37 location is reasonable. It is a location that offsets the Coastal El well and counters the ongoing drainage of. the Adame Gas Unit on the "W" sand. The proposed location is approximately 900' from the Adame Gas Unit's east lease line, which separates the applicant's and protestant's leases.
Coastal did not present any evidence of the amount of recoverable reserves under the Adame Gas Unit in the Jeffress, N.E. (T, LO.-FB,A), Jeffress, N.E. (Vicksburg T), Jeffress, N.E. (Vicksburg T Lo), and Jeffress, N.E. (Vicksburg L) Fields. Similarly, Coastal did not present any evidence that a well at a regular location could not produce Coastal's fair share of these reserves.
FINDINGS OF FACT
1. At least ten (10) days notice of hearing was sent to all designated operators,
260 Rule 37 Case No. 0213270 Page 4
lessees of record for tracts having no designated operator, and owners of record of unleased mineral interests, for each adjacent tract and each tract nearer than 467' to the applicant's proposed well.
2. Coastal Oil and Gas Corporation, the applicant herein, has requested on Form W-1 a Rule 37 exception to drill Well No. 2 on the Adame Gas Unit in Hidalgo County, Texas. The proposed well will be 349' from the nearest lease line, whereas field rules for the applied-for fields require a ,distance of 467'.
3. Coastal's application is for the following primary objective: Jeffress, N.E. (Vicksburg Lo) Field ("the "W" sand"). Secondary objectives are Jeffress, N.E. (T, LoFB,A), Jeffress, N.E. (Vicksburg T), Jeffress, N.E. Nicks. T-Lower), • Jeffress, N.E. (Vicksburg L.), and Wildcat (above 16,500') Fields.
4. The existing.. well, the Adame No. 1, is incapable of producing all of the recoverable gas under the Adame Unit in the "W" sand.
a. The Adame Well No. 1 is expected to produce ultimately approximately 2 BCF of gas. Ultimate recoveries by adjacent wells producing from the "W" sand range from 19 BCF to 10.4 BCF.
b. The poor performance of the Adame No. 1 relative to the other wells in the field is attributable to a fault cut in the "W" sand.
5. A well at any regular location on the Adame Gas Unit could also be expected to be cut by a fault, lose a portion of the reservoir, and not recover the tract's reserves.
6. There are recoverable gas reserves of approximately 7.3 BCF under the Adame Gas Unit. The existing well will not recover 5.3 BCF under the Adame Gas Unit.
7. A well at the proposed location is necessary to allow penetration of the entire "W" sand interval and is necessary to give the mineral interest owners of the Adame tract a reasonable opportunity to recover the reserves under the tract.
8. Royalty owners of the Adame Gas Unit do not participate in production in the "W" sand from any adjacent well.
9. Regular locations exist on the Adame Gas Unit, and there is insufficient evidence that a Rule 37 location "is necessary to recover the reserves, which were not quantified, in the Jeffress, N.E. (T, Lo-FB,A), Jeffress, N.E. (Vicksburg T), Jeffress, N.E. Nicks. T-Lower), and Jeffress, N.E. (Vicksburg. L.) Fields.
10. Applicant would not drill a well on the subject tract solely for the Wildcat (above 16,500').
261 • Rule 37 Case No. 0213270 Page 5
CONCLUSIONS OF LAW
1. Proper notice was issued timely to all persons legally entitled to notice.
2. All things have been done or have occurred to give the Railroad Commission jurisdiction to decide this matter.
3. The applicant proved that Well No. 2 at the proposed Rule 37 exception . location is necessary, to give the mineral owners of the Adame. Gas Unit an opportunity to recover their fair share of the hydrocarbons from the Jeffress N.E. (Vicksburg Lo) and Wildcat (above 16,500') Fields.
4. The applicant failed to establish that the applied-for location is necessary to recover the tract's reserves in the Jeffress, N.E. (T, Lo.-FB,A), Jeffress, N.E. (Vicksburg T), Jeffress, N.E. (Vicksburg T Lo), and Jeffress, N.E. (Vicksburg L) Fields.
RECOMMENDATION
The examiners recommend approval of Coastal's application to drill Well No. 2 at the proposed Rule 37 location on the Adame Gas Unit to encounter the. "W" sand and the Wildcat Field. We recommend denial of the application in all other applied-for fields.
Respectfully submitted,
Meredith Kawaguchi Legal Examiner
Margaret Allen Technical Examiner
MFK/ds
262 May 2, 2005
RULE 37 CASE No. 0240684 DISTRICT 7C
APPLICATION OF ENCORE OPERATING, L.P. FOR AN EXCEPTION TO STATEWIDE RULE 37 TO DRILL WELL NO. 2 ON THE VADA BEAN LEASE, OZONA (CANYON SAND) FIELD, CROCKETT COUNTY, TEXAS.
APPEARANCES:
FOR APPLICANT: APPLICANT:
Glenn Johnson Encore Operating, L.P. James Plemons Lee Peterson II
Ben Nivens, Jr.
FOR PROTESTANTS: PROTESTANT:
John Soule Devon Energy Production, L.P. Owen Broyles Arthur O'Neal, Jr.
PROPOSAL FOR DECISION
PROCEDURAL HISTORY
APPLICATION FILED: October 22, 2004 NOTICE OF HEARING: January 12, 2005 HEARING DATE: January 26, 2005 HEARD BY: Mark Helmueller - Hearings Examiner Margaret Allen - Technical Examiner TRANSCRIPT RECEIVED: February 7, 2005 PFD CIRCULATION DATE: May 2, 2005 STATEMENT OF THE CASE EXHIBIT
264 RULE 37 CASE NO. 0240684 Page 2
Encore Operating, L.P. ("Applicant" or "Encore") seeks an exception to Statewide Rule 37 to drill Well No. 2 on the Vada Bean Lease as a gas well in the Ozona (Canyon Sand) Field.' The Vada Bean Lease is a narrow rectangular shaped 63.30 acre tract with no locations regular to lease line spacing requirements in the Ozona (Canyon Sand) Field due to the configuration of the lease. Encore previously drilled the Vada Bean No. 1 Well on the southernmost 40 acres of the lease, 938 feet south of the proposed location for the Vada Bean No. 2. The proposed well will be located 275 feet from the eastern lease line and 2.54 feet from the western lease line on the remaining 23.30 acres.' The proposed well is regular to all other lease line boundaries. A copy of the plat filed with Applicant's W-1 Application for Permit to Drill, Deepen, Plug.Back or Re-Enter is attached. The Ozona (Canyon. Sand) Field is subject to spacing requirements of 467 feet minimum distance to the nearest lease line and 1200 feet minimum distance between wells for oil wells and 660 feet minimum distance to the nearest lease line and 933 feet minimum distance between wells for gas wells.
The application is protested by Devon Energy Production, L.P. ("Devon"), the offset • operator of the adjacent eastern tract. The offset operator to the west did not protest Encore's application.
APPLICANT'S POSITION AND EVIDENCE
Encore claims that the applied-for well is necessary to prevent confiscation as its existing Well No. '1 will not recover its fair share of the remaining recoverable natural gas underlying the Vada Bean Lease. Encore also claims that the proposed well would produce a significant volume of natural gas underlying the northernmost 23 acres of the Vada Bean Lease in the Ozona (Canyon Sand) Field which would not be recovered by either any existing wells or wells which would be located at any regular location, thereby warranting an exception permit to prevent waste.
With respect to its confiscation argument, Encore's volumetric analysis estimates that between 2.2 Bcf and .365 Bcf. f natural gas underlying its Vada Bean Lease will not be recovered from the existing Vada Bean No. 1 Well. For its high end estimate, Encore believes that the low permeability in the Ozona (Canyon Sand) Field, prevented any offsetting wells from draining reserves from the Vada Bean Lease. Encore therefore asserts that the original recoverable gas in place of 3.2 Bcf, less the estimated cumulative reserves which will be recovered from the Vada Bean No. 1 Well of .97 Bcf, is a proper measure for calculating its fair share of reserves currently underlying its lease.
t Field Rules for the Ozona (Canyon Sand) Field reference both the oil field rules and the gas field rules. Encore's presentation and all evidence was limited to the drilling of a gas well, accordingly the proposed final order is limited to a gas well at the proposed location. 2 The Field Rules for gas wells in the Ozona (Canyon Sand) Field allow for 320 acre units, with optional 40 acre units. Statewide Rule 38(c) allows for "tolerance wells", without a density exception, if the remaining acreage on a lease is equal or greater to 50% of the smallest amount established for an optional drilling unit.
265 RULE 37 CASE No. 0240684 Page 3
In support of the high estimate, Encore contends that its Vada Bean No. 1 Well came in at or near virgin reservoir pressure. Assuming virgin pressure of 2604 psig as the bottomhole pressure, the calculated recoverable reserves of the Veda Bean Lease under original conditions were 3.2 Bcf. Encore believes a well at the proposed location will also encounter virgin reservoir conditions due to the low reservoir permeability.
With respect to its low estimate of .365 Bcf, Encore's volumetric analysis uses a reservoir pressure of 1530 psig to calculate the remaining recoverable reserves. This pressure was calculated from the shut-in tubing pressure test measured in Encore's Vada Bean No. 1 Well after it had produced for three days. Encore does not believe that the shut-in tubing pressure test accurately reflects current reservoir conditions as the test was not performed over a long enough period of time. Encore suggests that an accurate test in such a tight formation would require a well to be shut in for several hundred hours. Using 1530 psig in Encore's volumetric calculations yields an estimate of recoverable gas in place of 1.336 Bcf. Subtracting the estimated cumulative recovery from the Vada Bean No. 1 Well of . 972 Bcf yields a remainder of .365 Bcf of recoverable reserves that will not be produced by the existing well.
Encore also relies on maps depicting the drainage patterns .of the existing wells on and adjacent to its Vada Bean Lease to support its case. Based on these maps, Encore asserts that the acreage in the northern end of the Vada Bean Lease has not and will not be drained by its existing well, other existing wells offsetting its lease, or any well which would be drilled at a regular location.
Encore's volumetric analysis relies on a phi h3 isopach map derived from its geologic interpretation of reservoir and digital log analyses estimating the total net pay encountered from a cross section of wells completed in the Ozona (Canyon Sand) Field, including its Vada Bean No. 1 Well. Encore contends that a high phi h value for the Vada Bean No. 1 Well is justified by the current production from that well, which came in among the top wells in the field. Encore also presented a decline curve analysis for its existing Vada Bean No. 1 well to show that the estimated cumulative recovery from that well will only be .972 Bcf. Finally, Encore further asserts that the location is reasonable because there are no regular locations on the tract and the location is roughly equidistant between the eastern and western lease lines.
Encore also claims that Devon's competing phi h isopach map does not accurately depict the Ozona (Canyon Sand) Field, pointing out several inaccuracies in contouring and reported phi h values for individual wells. Encore also asserts that Devon's volumetric analysis is flawed because it relies on an inaccurate 24 hour pressure test result reported from Devon's Vada Bean No. 12 well.
3 Phi h is a dimensionless number calculated by multiplying the number of feet of net pay by the estimated porosity in that net pay.
266 • RULE 37 CASE No. 0240684 Page 4
PROTESTANT'S POSITION AND EVIDENCE
Devon contends that Encore has.overestimated the amount of remaining recoverable natural gas underlying the Vada Bean Lease in the Ozona (Canyon Sand) Field. Devon argues that using Encore's own decline curve analysis with a volumetric analysis based on more current pressure data, Encore's Vada Bean No. I Well will ultimately recover more than its fair share of the remaining recoverable natural gas underlying the Vada Bean Lease.
Devon did not offer a competing geologic interpretation for the depositional environment or a top of structure map for the Ozona (Canyon Sand) Field. However, Devon challenges the precision of Encore's estimates of pay from the digital log studies and phi h values Encore assigns to the Vada Bean No. 1 Well.
Devon asserts that Encore overestimates the net pay for the Ozona (Canyon Sand) Field for its Vada Bean No. 1 Well. Devon claims that Encore's log analysis for its Vada Bean No. 1 Well erred because the porosity log was run on a limestone matrix instead of a sandstone matrix, thereby overestimating porosity by at least 4%. Devon further argues that Encore failed to account for spalling in its Vada Bean No. 1 Well, a common phenomenon during drilling in this area. Spalling occurs when rock particles break off into the borehole face of the wellbore, leading to an inaccurate and inflated porosity reading. Devon contends that Encore's estimates should have capped maximum porosity readings at 14%. Encore considered the log reading as accurate even where it indicated as much as 30% porosity, thereby leading to a significantly higher phi h value for Encore's Vada Bean No. I Well than Devon believes is correct. Devon urges that its own phi h isopach map is based on proper porosity cut-offs at both the upper and lower ends of the scale, thereby showing a more accurate depiction of the reservoir conditions on Encore's Vada Bean Lease.
Devon also contends that the bottomhole pressure tested in the Vada Bean No. 1 Well of 1530 psi in October 2004 was correct. Devon further asserts that Encore's volumetric calculations and decline curve analysis ignore recent pressure data from Devon's Vada Bean No. 12 Well which offsets the Encore acreage. This pressure data comes from a build up test in January 2005 from which the reservoir pressure can be calculated at 1395 psi. Using this reservoir pressure and its phi h isopach map, Devon's calculations find that the remaining recoverable reserves underlying the Vada Bean Lease total approximately .84 Bcf. Devon calculates that the remaining recovery from the Vada Bean No. 1 Well will be .86 Bcf, which exceeds what Devon asserts is its more accurate estimate of the remaining recoverable reserves underlying Encore's Vada Bean Lease.
EXAMINERS' OPINION
As discussed below, Encore asserts that an exception to the lease line spacing requirements is justified both to prevent confiscation and waste. It is the examiners' opinion that Encore has established that an exception permit is warranted under the confiscation test. Accordingly, no discussion is required on Encore's claim that an exception is necessary to prevent waste.
267 • • RULE 37 CASE No. 0240684 Pa.ge 5
To establish entitlement to an exception to Rule 37 to prevent confiscation, an applicant must show that, absent the applied-for well, it will be denied a reasonable opportunity to recover its fair share of hydrocarbons currently in place under the lease, or its equivalent in kind. The applicant must satisfy a two pronged test: 1) the applicant must show that it will not be afforded a reasonable opportunity to recover its fair share of hydrocarbons currently in place by drilling a well at a regular location; and 2) the applicant must show that the proposed irregular location is reasonable. Generally, the applicant must also provide a calculation of the current reserves underlying its lease.
As noted in Gulf Land Co. v. Atlantic Refining Co., 131 S.W.2d 73, 80 (Tex. 1939):
It is the law that every owner or lessee of land is entitled to a fair chance to recover the oil and gas in or under his land, or their equivalents in kind. Any denial of such fair chance would be 'confiscation' within the meaning of Rule 37 and the Rule of May 29th.
Encore presented volumetric evidence based on its interpretation of the geology and reservoir structure, determinations of net pay from .digital analysis of a cross-section, of well logs, and its phi h isopach map derived from the structural interpretation and the log analyses to estimate that, at the very least, approximately 1.336 Bcf of recoverable natural gas was present beneath its Vada Bean Lease at original conditions. Due to the low permeability in the Ozona (Canyon Sand). Field, the estimated recoverable reserves at original conditions, less the total cumulative recovery from the Vada Bean No. 1 well, is a sufficient measure to determine the current recoverable reserves underlying the Vada Bean Lease. Additionally, maps depicting the estimated drainage area of the wells on and offsetting the Vada Bean Lease establish that the northernmost 23.30 acres in the 63.30 acre tract have not been affected by any existing well.
Encore's decline curve analysis for its existing Vada Bean No. 1 well shows that the estimated cumulative recovery from that well will only be .972 Bcf, leaving a remainder of at least .365 Bcf of current recoverable reserves which will not be recovered by its existing well. Accordingly, this evidence satisfies the first element for an exception to prevent confiscation.
The examiners specifically note that while Encore's phi h value for its Vada Bean No. 1 Well may be higher than other wells in the field, the production history for this well supports its interpretation. Devon's proposed correction to the phi h value for the Vada Bean No. 1 Well would place it at or below the same capability as several wells drilled by Devon as direct offsets to Encore's Vada Bean Lease which are not reporting production capability at or near the reported production from the Vada Bean No. 1 Well. The examiners therefore believe that, while Encore's estimated phi h value for the Vada Bean No. 1 Well may be high in relation to the nearby offset wells, the empirical production data supports a higher value compared to the well's nearest neighbors.
Encore also presented evidence to establish that the proposed location is reasonable. The proposed well is located roughly equidistant from the lease lines on the narrow rectangular tract.
268 RULE 37 CASE No. 0240684 Page 6
Additionally, maps depicting the drainage pattern from the existing wells, including the Vada Bean No. 1, show that the proposed well will recover reserves from the northern portion of its lease which will not be recovered from any other existing well. This evidence satisfies the second element necessary to support an application for an exception to prevent confiscation. Accordingly, it is the examiner's recommendation that Encore's application be approved on this basis.
CONCLUSION
Encore is entitled to an exception to Rule 37 to prevent confiscation of natural gas underlying its Vada Bean Lease in the Ozona (Canyon Sand) Field. Accordingly, the application for an exception to Rule 37 should be granted.
Based on the record in this Docket,. the examiners recommend adoption of the following Findings of Fact and Conclusions of Law.
FINDINGS OF FACT
1. Encore Operating, L.P. ("Applicant" or "Encore") seeks an exception to Statewide Rule 37 to drill Well No. 2 on the Vada Bean Lease in the Ozona (Canyon Sand) Field, Crockett County. Encore appeared at the hearing and presented evidence in support of its application.
2. Encore's application is protested by Devon Energy Production, L.P., the operator of an offsetting tract to the east of the Vada Bean Lease. Devon appeared at the hearing and presented evidence in protest of Encore's application..
3. The Vada Bean Lease is a narrow rectangular shaped 63.30 acre tract with no locations regular to lease line spacing requireinents in the Ozona (Canyon Sand) Field due to the configuration of the lease. The proposed well will be located 275 feet from the western lease line and 254 feet from the eastern lease line. The proposed well is regular to all other lease line boundaries.
4. The Ozona (Canyon Sand) Field is subject to spacing requirements of 467 feet minimum distance to the nearest lease line and 1200 feet minimum distance between wells for oil wells and 660 feet minimum distance to the nearest lease line and 933 feet minimum distance between wells for gas wells.
5. Encore's Vada Bean No. 1 Well will not recover its fair share of current recoverable reserves in the Ozona (Canyon Sand) Field currently underlying its Vada Bean Lease.
a. Volumetric evidence based on a geologic interpretation of the depositional environment, maps depicting reservoir structure, determinations of net pay from digital analysis of a cross-section of well logs, and a phi h isopach map derived from the structural interpretation and the log analyses estimate that, at a minimum, approximately 1.336 Bcf of recoverable natural gas were underneath Encore's Vada
269 • • RULE 37 CASE No. 0240684 Page 7
Bean Lease in the Ozona (Canyon Sand) Field at original conditions.
1) Maps depicting the estimated drainage area of the wells on and offsetting the Vada Bean Lease establish that the northernmost 23.30 acres in the 63.30 acre tract have not been affected by any existing well.
c. Due to the low permeability in the Ozona (Canyon Sand) Field, the estimated recoverabld reserves.al original conditions, less the total cumulative recovery from the Vada Bean No. 1 well, is a sufficient measure to determine the current • recoverable reserves underlying the Vada Bean Lease.
d. A decline curve analysis for the Vada Bean No. 1 well shows that the cumulative estimated recovery will only be .972 Bcf, leaving a remainder of .365 Bcf of recoverable reserves underlying the Vada Bean Lease which•will not be recovered by the existing well.
CONCLUSIONS 01? LAW
1. Proper notice of hearing was timely given to all persons legally entitled to notice.
2. All things have occurred to give the Commission jurisdiction to decide this matter.
3. An exception to Statewide Rule 37 for a gas well at the applied-for location is necessary to prevent confiscation.
RECOMMENDATION
The examiners recommend that Encore's application be granted to drill Well No. 2 on the Vada Bean Lease as a gas well in the Ozona (Canyon Sand) Field in accordance with the attached final order.
Respectfully submitted,
Mark J. Helmueller 1 Margaret Allen Hearings Examiner Technical Examiner
270 • • ******************************************************* * KEY ISSUES: CONFISCATION Adjacent secondary recovery project Oil not recoverable by existing wells * * * * FINAL ORDER: R37 GRANTED *******************************************************
Rule 37 Case No. 0211820 District 8A
APPLICATION OF CANDLERIDGE OIL, INC., FOR AN EXCEPTION TO STATEWIDE RULE 37 TO DRILL ITS WELL NO. 1, SANDERS-HODGE "A" UNIT, LEVELLAND FIELD, HOCKLEY COUNTY, TEXAS
APPEARANCES: REPRESENTING:
APPLICANT -
William Osborn, Attorney Candleridge Oil, Inc. George Jackson
PROTESTANT -
Ana Maria Marsland, Attorney Texaco E&P, Inc. Richard A. Josefy Robert N. Goon
PROCEDURAL HISTORY
Application Filed: March 7, 1996 Notice of Hearing: March 29, 1996 Hearing Held: May 3, 1996 PFD Circulated September 13, 1996 Heard by: Colin K. Lineberry, Hearings Examiner Margaret Allen Technical Examiner
272 1 Proposal for Decision Page 2 Rule 37 Case No. 0211820
STATEMENT OF THE CASE
Candleridge Oil, Inc. ("Candleridge" or "applicant") seeks an exception to Statewide Rule 37 to drill its proposed Well No. 1 on the Sanders-Hodge "A" Unit for the Levelland Field. The application is protested by Texaco E&P, Inc., ("Texaco" or "protestant"). The Levelland field rules mandate spacing of 440 feet from unit lines and 880 feet between wells, with 42.5 acre regular units and optional units of 21.25 acres.
The applied-for location is regular as to between-well spacing but is only 100 feet from the nearest unit line. Accordingly, an exception to the Levelland Field Rules pursuant to Statewide Rule 37 is necessary. The Sanders-Hodge "A" Unit contains 21.25 contiguous acres and the proposed well will be the only well on the unit producing from the Levelland Field.
The hearing in this docket on May 3, 1996, was consolidated with Rule 37 Case No. 0211519, which was the application of Texaco for an exception to rule 37 for its Ira P. DeLoache Lease Well No. 85 in the Levelland Field. Candleridge protested Texaco's application but was deemed to be unaffected based on the evidence presented at the hearing. Rule 37 Case 0211519 was approved administratively on May 20, 1996.
UNCONTROVERTED EVIDENCE
The relative locations of the wells proposed by Texaco and Candleridge and the nearby existing wells are illustrated on Exhibit A to this Proposal for Decision. Exhibit A is a portion of Candleridge's Exhibit 1 annotated to highlight the location of Texaco's applied-for Well No. 85 and Candleridge's applied-for Well No. 1.
Candleridge operates six small leases on the northern end of the very large Levelland Field. Texaco operates much larger leases, including the Ira P. DeLoache Lease, adjacent and to the southwest of Candleridge's acreage. The Ira P. DeLoache lease has 45 producing wells and 32 injection wells. Immediately to the east of the Ira P. DeLoache Lease is Texaco's Montgomery Estate-Davies Lease which has 73 producing wells and 48 injection wells. The injection pattern on Texaco's two leases is approximately a forty acre line drive wherein rows of injection wells alternate with rows of producing wells. Texaco's application for its Ira P. Deloache Well No. 85 required a Rule 37 exception because the proposed well was closer than 440' to Texaco's Montgomery Estate- Davies Lease. Well 85 needed to be placed 175' from the Montgomery Estate-Davies Lease in order to complete Texaco's pattern flood.
The productive San Andres reservoir is porous and permeable and Texaco has been successfully water flooding the DeLoache Lease for some time. Prior to the administrative grant of Texaco's Rule 37 exception for Well No. 85, Texaco presented evidence that when it drilled two previous producing wells to fill in holes in the waterflood pattern, those wells had no effect on the production of their direct offset producing wells. The direct offset producing wells are only 900 - 1000' away from the infill producing wells. Texaco testified that its proposed Well No. 85 "would
273 Proposal for Decision • Page 3 Rule 37 Case No. 0211820
have no impact of its two immediate offsets." Texaco's witnesses testified that Well No. 85 will recover 129,000 BO from a 45' thick pay section and that this "129,000 BO ...would not be recovered by any other well due to the nature of the flood."
Candleridge's property is approximately 2900' north of Well No. 85 and there are four producing wells between the proposed location of Texaco's proposed Well No. 85 and Candleridge's acreage. In 1994, Candleridge's predecessor, S.K. Rogers Oil, converted four producing wells, the Hodge Estate No. 2, the Hodge "A" No. 1-A, and the Sanders Nos. 2 and 4 to injection.
APPLICANT CANDLERIDGE'S EVIDENCE AND POSITION
Candleridge protested Texaco's Rule 37 application after receiving notice as an offset operator. Candleridge did not present evidence to contradict Texaco's case but took the position that the Commission should not grant Texaco's Rule 37 application without granting the application of Candleridge:for a Rule 37. The examiners ruled on May 20, 1996, that Candleridge was unaffected by Texaco's proposed Well No. 85 and Candleridge did not contest the examiners' ruling.
Candleridge's injection wells are located to compliment Texaco's waterflood pattern as Candleridge hoped to make a co-operative lease-line waterflood arrangement with Texaco. Candleridge is now receiving response to its waterflood in its producing wells but, due to the absence of a co-operative waterflood agreement with Texaco, Candleridge is losing a large part of the benefit of the waterflood. The injection wells are pushing a substantial volume of oil off Candleridge's leases and onto Texaco's property.
Two of Candleridge's injection wells, the Sanders No. 2 and Hodge "A" No. 1A, are located 2200 feet apart and 440 feet north of the common lease line with Texaco. The square formed by lines between the two wells and the lease line covers about 22 acres. If the proposed well is not drilled any remaining oil within this square will be pushed to Texaco's acreage and will not be recovered by Candleridge.
Texaco's Well Nos. 25 and 27 are producing wells just to the south of the common lease line with Candleridge. They are on the pattern lines of Texaco's injection wells. Candleridge's injection wells are on the same pattern lines and extend the pattern established by Texaco's wells. Candleridge anticipated that Texaco would convert these two producing wells to injection which would, complete the pattern, facilitate the waterflood and thereby protect correlative rights across the lease line. Candleridge offered Texaco the same type of cooperative development agreement that Texaco has with its southern boundary offset operator but Texaco declined the offer. Candleridge claims that oil under the entire 72 acres between 440' and the lease line of its property cannot be recovered without a co-operative lease line waterflood pattern or lease line producing wells.
Candleridge assumed the same reservoir parameters as Texaco in its original application with the exception of reservoir thickness. Texaco assumed a reservoir thickness of 45 feet around its proposed No. 85, while Candleridge has assumed only 18 feet of net pay around its proposed well. Candleridge then calculated that about 70,000 barrels of oil were recoverable from the square
274 Proposal for Decision i • Page 4 Rule 37 Case No. 0211820
between the injection wells and the lease lines by both primary and secondary efforts. The water injected into the Candleridge Sanders No. 2 and Hodge "A" No. 1A has already swept the oil from about 8.9 of the acres in the square, which leaves 42,000 (70,000 - 28,000) barrels of recoverable oil in this square that Candleridge believes only its proposed Sanders-Hodge "A" Unit No. 1 can recover.
Candleridge believes that the oil which its injection wells are sweeping off its lease will be only partially recovered by Texaco's wells. About half of the oil swept off the lease will be unrecovered by either party unless the injection pattern is completed.
Texaco and the predecessor operator to Candleridge, S.K. Rogers had been discussing a co- operative lease-line injection program but Texaco had indicated in late 1993 that it would wait to decide on the agreement. Rogers made another offer for a lease-line injection agreement to Texaco by a letter written in January of 1995. There is no evidence of a written response from Texaco.
PROTESTANT TEXACO'S EVIDENCE AND POSITION
If Candleridge's proposed location is drilled only 100 feet• from Texaco's lease, and the producing well has an assumed square drainage area of 21.25 acres, then about 8 of those acres would be under lease to Texaco. According to Texaco, Candleridge could recover some of the reserves being pushed by the Candleridge's two injection wells by drilling in between the two injection wells at a distance of 440 feet from Texaco's lease. This location would be regular with respect to lease lines and Texaco agreed to waive any objection to a Rule 37 exception based on between well spacing.
Texaco also pointed out that Candleridge chose to convert to injection two of its producing wells that are closest to Texaco's leases. Texaco's witnesses testified that if Texaco had been in Candleridge's position and not had a co-operative lease-line agreement in writing, it would have protected its lease-line rather than maintaining the same waterflood pattern as an offset operator. Texaco's witnesses also testified that if they were protecting a waterflood lease from confiscation they would have drilled an additional five wells and used a five-spot injection pattern which maintained lease-line producing wells.
EXAMINERS' OPINION
Exceptions to Statewide Rule 37 may be granted to prevent waste or to protect correlative rights/prevent confiscation. An applicant seeking an exception to Rule 37 based on waste must establish three elements: 1) that unusual conditions, different from conditions in adjacent parts of the field, exist under the tract for which the exception is sought; 2) that, as a result of these conditions, hydrocarbons will be recovered by the well for which a permit is sought that would not be recovered by any existing well or by additional wells drilled at regular locations; and, 3) that the volume of otherwise unrecoverable hydrocarbons is substantial. The evidence of both parties indicates that a substantial volume of oil being swept by Candleridge's injection wells cannot be
275 Proposal for Decision • • Page 5 Rule 37 Case No. 0211820
recovered by any regularly located well. Applicant Candleridge did not, however, present any evidence of an unusual condition which would authorize granting an exception based on waste.
To obtain an exception to Statewide Rule 37 to protect correlative rights, the applicant must show that: 1) It is not possible for the applicant to recover its fair share of minerals under its tract from regular locations; and, 2) that the proposed irregular location is reasonable. Because Candleridge's Sanders-Hodge "A" Unit was formed after field rules were established, the size and shape of the pooled unit are not being considered in determining whether confiscation is occurring. See Tex. R.R. Comm'n, 16 TEX. ADMIN. CODE § 3.37(g)(1) (West Jan. 1, 1996) [Statewide rule 37(g)(1)].
Candleridge's evidence that, unless the application is granted, Candleridge's injection wells will sweep an additional 42,000 barrels of oil off of tracts operated by Candleridge and onto Texaco's lease was unrefuted. Texaco has deviated from its established line-drive pattern and has not converted any of its producing wells along its common lease-lines with Candleridge to injection. Texaco's six producing "border guard" wells along the lease-lines between Candleridge and Texaco insure that Texaco's injection wells will not sweep any significant volume of oil from Texaco's leases onto Candleridge's leases. A well located at a regular location 440 feet from lease-lines would be directly between the two injection wells and the same distance from the Texaco lease-line as the two injection wells and, as a result, would only recover a small fraction of the oil being swept onto Texaco's lease.
The proposed location is reasonable. Texaco's "border guard" producing wells will capture the secondary. oil being swept by Texaco's injection wells before it reaches Candleridge's leases and/or the proposed well location. Further, Texaco's evidence regarding its own Rule 37 application suggests that a well at the location proposed by Candleridge will not interfere with the production of Texaco's existing wells and will recover oil that cannot be recovered by existing Texaco wells. Texaco's witnesses testified that all or the great majority of the production to be recovered by Texaco's applied-for Well No. 85 would not be recovered by any other well. The producing wells nearest Well No. 85 are only about 900 feet from Well 85 yet Texaco expects the production from these wells to be unaffected by Well No. 85. Candleridge's applied-for location is more then 900 feet from the nearest Texaco prodUcing wells. Texaco's evidence that its well will recover oil that would not be recovered by any adjacent producing well indicates that the applied-for Candleridge well on the adjacent lease will similarly recover oil that would not be recovered by any existing well.
Texaco's own evidence indicates that a well at the location proposed by Candleridge will recover little, if any, oil from Texaco's tract. Conversely, it is undisputed that a well at the applied- for location would recover a substantial volume of "secondary" oil from the Candleridge leases that would otherwise be swept off the leases.
The examiners recommend adoption of the following proposed findings of fact and conclusions of law:
276 Proposal for Decision Rule 37 Case No. 0211820 • • Page 6
FINDINGS OF FACT
1. Notice of the hearing was given at least 10 days prior to the hearing to all designated operators, lessees of record for tracts that have no designated operator, and owners of record' of unleased mineral interests for each adjacent tract and each tract nearer to the well than the prescribed minimum lease-line spacing distance.
2. Candleridge Oil, Inc., ("applicant") has applied on Form W-1 for a permit to drill Well No. 1 on the Sanders-Hodge "A" Unit. Applicant proposes to drill its well at a location 100 feet from the south line and 962 feet from the east line of the unit, and -0- feet from the east line and 100 feet from the south line of the Reeves CSL, Lge 78, Lab 9 Survey (A-201). Applicant has applied to drill its proposed well for the Levelland Field.
3. The Levelland Field has field rules requiring spacing of 440 feet from unit lines and 880 feet between wells. The field rules further specify a density pattern of 42.5 acres per well with options of 21.25 acres per well.
4. Applicant's Sanders-Hodge "A" Unit is a tract containing 21.25 acres.
5. The volume of remaining primary recoverable reserves in the Levelland Field under the applicant's Sanders-Hodge "A" Unit and the surrounding tracts is insignificant.
6. There is a line pattern of injection and producing wells that extends•from the adjoining lease onto applicant's Sanders-Hodge "A" Unit.
7. Applicant's existing injection wells in the line pattern will sweep approximately 42,000 barrels of oil off of applicant's leases.
8. The injection wells on tracts adjacent to applicant's Sanders-Hodge "A" Unit will not sweep oil from other tracts onto the leases operated by applicant.
9. A well at the applied-for location will recover approximately 42,000 barrels of oil which no existing Candleridge well could recover.
10. A well a regular distance from the lease-line between the applicant's leases and the adjoining leases operated by Texaco would recover substantially less than 42,000 barrels of oil.
11. A well at the applied-for location will not interfere with existing producing wells on adjacent leases operated by protestant Texaco.
CONCLUSIONS OF LAW
1. Proper notice of hearing was timely given to all persons legally entitled to notice.
277 Proposal for Decision Page 7 Rule 37 Case No. 0211820
2. All things have occurred or have been done that are necessary to give the Commission jurisdiction to decide this matter.
3. An exception pursuant to Statewide Rule 37 to the Levelland Field rules regarding well spacing is necessary to permit drilling the applied-for well.
4. Approval of the requested permit to drill a well at the proposed location is necessary to give the owners of the Sanders-Hodge "A" Unit a reasonable opportunity to recover their fair share of oil underlying their leases from the Levelland Field.
5. The applied-for location is reasonable.
6. An exception to Statewide Rule 37 is necessary to prevent confiscation of oil from the Levelland Field currently in place under the Sanders-Hodge "A" Unit.
RECOMMENDATION
The examiners recommend that the subject application be approved in accordance with the attached final order.
Respectfully submitted,
Colin K. Lineberry • Margaret A. Allen Hearings Examiner Technical Examiner
GAdata\OG\wp\ckl\pfd\CandlerFt.370
278 November 7, 2008
RULE 37 CASE No. 0245869 DISTRICT 06
APPLICATION OF CHESAPEAKE OPERATING, INC. FOR AN EXCEPTION TO STATEWIDE RULE 37 TO DRILL WELL No. 4 ON THE GREEN GAS UNIT LEASE, OAK HILL (COTTON VALLEY) FIELDS, GREGG COUNTY, TEXAS.
APPEARANCES:
FOR APPLICANT CHESAPEAKE OPERATING, INC.: George Neale Robert Hilty Cary McGregor
FOR PROTESTANT ANADARKO E & P COMPANY, L.P.: Ana Maria Marsland-Griffith _ Andrew Mehlhop Rick Johnston
FOR OBSERVER TEXAS GENERAL LAND OFFICE: James Irwin
PROPOSAL FOR DECISION
PROCEDURAL HISTORY
APPLICATION FILED: January 1.2, 2006 NOTICE OF HEARING: June 13, 2008 HEARING DATES: July 30 and 31, 2008 August 6, 2008 RECORD CLOSED: September 18, 2008 HEARD BY: Mark Helmueller - Hearings Examiner Donna Chandler - Technical Examiner PFD CIRCULATION DATE: November 7, 2008
280 Rule 37 Case No. 0245869 Page 2 Proposal for Decision
STATEMENT OF THE CASE
Chesapeake Operating, Inc. ("Applicant" or "Chesapeake") seeks an exception to Statewide Rule 37 to drill Well No. 4 on the Green Gas Unit Lease, Oak Hill (Cotton Valley) Field. The Green Gas Unit is an irregularly shaped 683 acre pooled unit which includes land owned by the State of Texas and private lands. The 307.8 acres owned by the state is an approximately 10 mile long section of the Sabine River. The remaining 375.2 acres are privately owned tracts. This configuration is very atypical. A square 640 acre unit is one mile wide, but this unit is over 10 miles wide. The proposed well would be the fourth well on the unit. Chesapeake has also requested an exception to the maximum diagonal requirement for the proposed proration unit associated with the Green No. 4 well. The application is protested by Anadarko E & P Company, L.P. ("Anadarko"), the offset operator on both sides of the river tract where the proposed well is located.
The Oak Hill (Cotton Valley) Field is subject to spacing requirements of 467 feet minimum distance to the nearest lease line and 1200 feet minimum distance between wells. The proposed bottom hole location is in the center of the river tract, 75 feet from the offsetting property on both sides. A copy of the plat filed with Applicant's W-1 (Application for Permit to Drill, Deepen, Plug Back or Re-Enter) is attached for reference.
The maximum diagonal requirement for the Oak Hill (Cotton Valley) Field is 5500 feet for 160 acre units, 3250 feet for 80 acre units, and 2100 feet for 40 acre units. Chesapeake proposes two alternative proration units for its Green No. 4 Well. The first unit includes176 acres with a diagonal of approximately 58,000 feet. This lengthy diagonal is required because the proposed unit assigns a portion of the entire length of the Sabine River tract to the Green No. 4 Well. Alternatively, Chesapeake proposes a 40 acre proration unit with a diagonal of approximately 15,815 feet. The 40 acre proration unit assigns a portion of the river tract from the general vicinity of the proposed well to the easternmost terminus of the river tract, approximately 3 miles from the proposed location.
APPLICANT'S POSITION AND EVIDENCE
The Oak Hill (Cotton Valley) Field is productive from the lower Taylor sand, a uniform marine bar deposit, and from the Upper Cotton Valley, a group of independent sand lenses formed in a fluvial depositional environment. Both formations are recognized as tight and require fracture stimulation of the producing interval.
The Taylor sand is present throughout the Green Gas Unit. Chesapeake's structural cross section of wells over the entire area shows that the Taylor sand thins and becomes more water saturated on an east to west trend. The Upper Cotton Valley is described as "hit and miss" and does not exhibit a reliable trend within the Green Gas Unit.
281 Rule 37 Case No. 0245869 Page 3 Proposal for Decision
The Oak Hill (Cotton Valley) Field underlies the entire unit as shown by Chesapeake's net pay and isopach maps for the area. However, Chesapeake contends the Cotton Valley is thicker and less water saturated in the eastern portion of the Green Gas Unit. Chesapeake's maps and volumetric analysis of the Green Gas Unit reflect the entire Cotton Valley interval.
Chesapeake currently operates three wells on the Green Gas Unit. The Green Gas Unit No. 1 was completed in December 1995 on an 80 acre pooled unit comprised of 62.8 acres of the State's Sabine River lands and 17.2 acres of private property adjacent to the river. The Green No. 1 Well has produced over 1 Bcf since it was completed.
The Green No. 2 and No. 3 wells were drilled and completed in January 2006. Performance from both of these wells has been marginal. Cumulative production from the Green No. 2 is .091 Bcf while the Green No. 3 is .18 Bcf. These two wells were drilled under an amended unit agreement which increased the overall size of the unit to its present 683 acres by adding an additional 358 acres of privately owned land and 245 acres of the State's Sabine River lands. Additionally, the proration units for the Green No. 1, Green No. 2 and Green No. 3 were drawn so that each well included a portion of the complete 10 mile Sabine River lands, and a portion of the privately held land. Exceptions to the maximum diagonal requirements were approved administratively for these three wells.
The proposed Green No. 4 well would be located on a portion of the Sabine River acreage which was originally assigned to the Green No. 1 well. Chesapeake claims that the Green.No. 4 is necessary to prevent confiscation as the three existing wells will not recover a significant portion of the remaining recoverable natural gas underlying under the Green Gas Unit. As of the hearing date, the three existing wells cumulative production was 1.274 Bcf. The estimated ultimate recovery from the 3 existing wells is 1A68 Bcf of natural gas. Chesapeake's volumetric analysis shows 62.1 Bcf in currently recoverable reserves underlying the entire Green Gas Unit, and 23 Bcf underlying the easternmost 160 acres of the State's river lands. Chesapeake therefore urges that an exception is necessary because there are significant reserves which will not be recovered by the existing wells.
Chesapeake admits regular locations exist on the unit. However, it claims a well drilled at a regular location, while productive, would not be economic to drill. The nearest offset well to the portion.of the unit with regular locations is the Gibson "A" No. 2 Well. The Gibson "A" No. 2 Well first reported production in October 2007. Through April 2008, the cumulative production from the well is .094 Bcf. Chesapeake's EUR for the well ranges between .16 and .22 Bcf based only on the current completion in the Taylor sand. Chesapeake claims that with this EUR, the Gibson "A" No. 2 Well will never be profitable using current economic projections. Chesapeake therefore asserts that no reasonable regular locations exist on the Green Gas Unit.
Chesapeake also relies on maps depicting the drainage patterns of the existing wells as estimated by Anadarko. Based on these maps, Chesapeake asserts that some of the acreage in the river tract is being drained by offsetting wells. Chesapeake urges it therefore needs the well at the proposed location to protect its correlative rights.
282 Rule 37 Case No. 0245869 Page 4 Proposal for Decision
Chespeake also requests an exception to the maximum diagonal requirement in the field. Chesapeake proposes that the Green No. 4 well further split the Sabine River lands so that a portion is assigned to all four wells. This results in several "ribbons" necessary to create four proration units which will include all of the State's river acreage. Each ribbon is approximately 10 miles in length. Alternatively, Chesapeake requests that the acreage for the Green No. 1 well be split with the Green No. 4 well with exceptions to the maximum diagonal requirement consistent with the alternative proposed 160 acre unit.
PROTESTANT'S POSITION AND EVIDENCE
Anadarko contends that Chesapeake failed to submit the required evidence to support a well at the exception location because there are multiple regular locations available on the 683 acre Green Gas Unit. It is undisputed that regular locations on the Green Gas Unit will encounter both the Taylor and Upper Cotton Valley sands. While Chesapeake argues its proposed location is more reasonable due to the economic risk associated with developing the regular locations, Anadarko asserts that the proper standard for supporting an exception to prevent confiscation is whether the exception is necessary. Anadarko further notes that no prior Commission case has granted an exception to spacing rules on the basis of economic risk alone. Anadarko urges that until Chesapeake has developed its regular locations that it cannot seek exception locations on the basis of donfiscation.
Anadarko also questions the technical basis for Chesapeake's confiscation case. Anadarko first argued that Chesapeake's central premise of an east-west trend in the Oak Hill (Cotton Valley) Field was based on a flawed analysis. Anadarko claims that Chesapeake inappropriately evaluated the Oak Hill (Cotton Valley) Field in its hydrocarbon pore volume and net pay maps by aggregating the Upper Cotton Valley sand with the Taylor sand in its analysis. The Taylor sand is a structural trap while the Upper Cotton Valley is a series of laterally discontinuous sands which form stratigraphic traps. Stratigraphic traps are not likely to be affected by the syncline Chesapeake posits for the formation. Further, published studies of the Oak Hill (Cotton Valley) Field relied on by both parties specifically caution against using the Upper Cotton Valley as a predictive tool of estimated ultimate recovery (EUR) trends. Anadarko therefore urges that Chesapeake's maps are fatally flawed as the aggregate values do not establish a trend for all of the contributing sands and do not accurately reflect recoverable reserves.
Anadarko also challenges Chesapeake's assertion that the Gibson "A" No. 2 Well will never be profitable using current economic projections. Anadarko's own economic analysis predicts that the Gibson "A" No. 2 Well will be economic currently; and will be even more profitable if the well is later completed in the Upper Cotton Valley sand. Anadarko also notes that with the unpredictability of Upper Cotton Valley production in the field, it is inappropriate to rule out potential reserves from that formation contributing to production at the regular locations on the Green Gas Unit.
283 Rule 37 Case No. 0245869 Page 5 Proposal for Decision
Finally, Anadarko urges the additional acreage added to the Green Gas Unit was a deliberate attempt to support a drilling program for 16 additional wells on the easternmost river acreage without obtaining density exceptions. Anadarko notes that 358 acres were leased from the Eastman Chemical Company underlying a large facility it operates and added to the Green Gas Unit with additional State lands in the Sabine River. However, the Eastman lease agreements include covenants prohibiting the use of the surface or subsurface for development of the underlying mineral estate. Anadarko argues that the restrictions in the lease are an effective moratorium on the development of the Eastman acreage. It believes the only purpose of agreeing to such restrictions was to support drilling at greater density along the river acreage through gerrymandering the proration units to encompass the entire unit. Anadarko admits the proration units technically comply with Commission rules if a maximum diagonal exception is obtained. However, Anadarko argues that this process is designed to circumvent Commission's rules regarding density and double assignment of acreage.
EXAMINERS' OPINION
Chesapeake contends it is entitled to an exception at the proposed location for its Green No. 4 Well. Chesapeake argues that the proposed well is necessary to prevent confiscation on the full 683 acre unit. Alternatively, Chesapeake argues that the proposed well is necessary to prevent confiscation on the easternmost 160 acres of the unit. Finally, Chesapeake seeks an exception to the maximum diagonal requirement in order to assign a portion of the Sabine river acreage and the privately held acreage to each of its 4 wells on the 683. acre unit.
The examiners recommend that Chesapeake's application be denied because Chesapeake did not provide reliable evidence to support an exception at th6 proposed. location. Additionally, Chesapeake cannot subdivide the 683 acre unit identified in its drilling permit application to argue that it is entitled to a well on a portion of the unit.
Exceptions to Prevent Confiscation
To establish entitlement to an exception to Rule 37 to prevent confiscation, an applicant must show that absent the applied-for well, it will be denied a reasonable opportunity to recover its fair share of hydrocarbons currently in place under the lease, or its equivalent in kind. The applicant must satisfy a two pronged test: 1) the applicant must show that it will not be afforded a reasonable opportunity to recover its fair share of hydrocarbons currently in place by drilling wells at regular locations; and 2) the applicant must show that the proposed irregular location is reasonable.
It is the basic right of every landowner or lessee to a fair and reasonable chance to recover the oil and gas under his property as recognized by the Texas Supreme Court in Gulf Land Co. v. Atlantic Refining Co., 131 S.W.2d 73, 80 (Tex. 1939). Denial of that fair chance is confiscation within the meaning of Rule 37. Id. Because an application cannot seek redress for past drainage, an applicant must provide evidence that it will not be afforded an opportunity to recover the reserves currently in place under its lease - this is its "fair share".
284 Rule 37 Case No. 0245869 Page 6 Proposal for Decision
Chesapeake Failed to Establish the Necessity for an Exception to Prevent Confiscation.
Chesapeake failed to establish that it is entitled to a well at the proposed location to prevent confiscation on the Green Gas Unit. Chesapeake submitted a volumetric estimate of 62.1 Bcf in current recoverable reserves underlying the entire 683 acre Green Gas Unit. Chesapeake argues its existing three wells will only recover 1.5 Bcf and that the proposed well is therefore necessary to give it an opportunity to recover its fair share of reserves. As discussed below, Chesapeake's volumetric analysis is flawed and does not provide a reliable estimate of the remaining reserves underlying the unit.
Chesapeake's estimates of the current recoverable reserves underlying the full 683 acre unit are unreliable because it inappropriately consolidated the Upper Cotton Valley and Taylor when analyzing the remaining reserves. Because each interval has different characteristics, they must be analyzed separately. Chesapeake's own geologist confirmed this when describing the characteristics of the Upper Cotton Valley interval as a "hit or miss" play.
Chesapeake's analysis lumped the two intervals together and then mapped the cumulative total to provide the basis for the volumetric analysis. The proper methodology here would have been to separately map each interval, perform separate volumetric analyses and then add the volumetric results together to arrive at an accurate and reliable estimate of the remaining recoverable reserves. Because the proper methodology was not , followed, it is not reliable evidence to support an exception based on confiscation. In the absence of reliable volumetrics, there are insufficient facts upon which to base Chesapeake's application for an exception based on confiscation.
The examiners also question the reliability of Chesapeake's study based on the extrapolation of estimated reserves from the eastern 160 acres to the full 10 mile wide 683 acre Green Gas Unit. Normally, the issue of reservoir characteristics would not be an issue on a single pooled unit. However, the issue is relevant here to the unusual configuration of a 10 mile wide unit.
It is unquestioned that there has been heavy development in the Oak Hill (Cotton Valley) Field in the easternmost area of the Green Gas Unit. However, there have been very few wells drilled in the western area. Further, Chesapeake argues' that the closest well drilled to the regular locations on the Green Gas Unit, the Gibson "A" No. 2 Well, will only be a marginal well with .2 Bcf of production. The absence of well control in the western portion of the unit, coupled with the limited expected performance of the Gibson "A" No. 2 well indicate that Chesapeake's estimates of over 60 Bcf of recoverable reserves are speculative at best.
Chesapeake's witnesses claim they need the applied-for irregular location to allow them to have a commercial well. However, neither Chesapeake nor any other operator is guaranteed a well that meets its self-imposed criteria for economic viability - each mineral interest owner is entitled to a fair and equal opportunity to recover its fair share of the hydrocarbons under its tract. Economic requirements: 1) vary from company to company (applicant to applicant); 2) are not evenly applied; and, 3) are not specific to the property rights on a given tract. An operator's economic requirements
285 Rule 37 Case No. 0245869 Page 7 Proposal for Decision
therefore cannot be the basis for granting an exception to Statewide Rule 37 to protect correlative rights. See Rule 37 Case No. 0206334: Application of Enron Oil & Gas Company for an exception to Statewide Rule 37 to Drill Its No. 17 Well, Frank Reed 117 Lease, Sawyer (Canyon) Field, Sutton County, Texas.
Rule 37 is equally applicable to all operators. While the non-discriminatory application of Commission spacing rules may result in some economic loss by an operator, this loss does not amount to legal confiscation. See Railroad Commission v. Manziel, 361 S.W.2d 560, 565 (Tex. 1962); Railroad Commission v. Fain, 161 S.W.2d 498, 500 (Tex. Civ. App. -- Austin 1942, writ dism'd w.o.in.). The determination of what is a fair opportunity must be based on the relationship between potential drilisite locations and the currently recoverable reserves' under a tract, not on economic viability guidelines that each operator selects for itself.
Chesapeake's economic assessment that regular wells would not be commercial is not reliable evidence for ruling out the other regular locations on the Green Gas Unit. The claim 'that it would not be economic for Chesapeake to drill a regular well is not sufficient to establish that an. exception at the proposed location is necessary to afford it a reasonable opportunity to recover the reserves in the Green Gas Unit. Therefore, the examiners do not believe that this argument supports Chesapeake's request for a well at the proposed location.
Chesapeake cannot Legally Assert a Confiscation Exception on an Alternative 160 acre unit.
Chesapeake alternatively argued that it is entitled to a fourth well on the easternmost 160 acres to prevent confiscation. This argument should be rejected because Chesapeake has not applied for a well at an exception location on a 160 acre unit, and cannot carve out a portion of its Green Gas Unit for consideration of an exception based on confiscation.
When an operator voluntarily designates a pooled unit for the purpose of permitting wells or for subsequent production, any application for additional wells on the designated pooled unit must stand or fall on the basis of the existing unit. Chesapeake created the Green Gas Unit by pooling several tracts together for the purpose of cooperative development of 683 acres. When it formed the pooled unit, it assigned its one existing well, the Green No. 1 for production purposes. It then permitted and drilled two additional wells on the 683 acre unit. The current application for a fourth well therefore must be considered under the existing 683 acre pooled unit.
This is particularly relevant when considering the potential application of Statewide Rule. 38(d)(3).' The Commission Form P-12 (Certificate of Pooling Authority) filed with the permit applications for the Green No. 2 and No. 3 wells, as well as the proposed Green No. 4 well identifies 7 tracts which are substandard under the field rules for the Oak Hill (Cotton Valley) Field.
Statewide Rule 38(d)(3) requires Commission approval of the dissolution of a pooled unit where the pooled unit includes any tract composed of substandard acreage in the field.
286 Rule 37 Case No. 0245869 Page 8 Proposal for Decision
Chesapeake could potentially dissolve the existing pooled unit. After Commission approval of the unit dissolution under Statewide Rule 38(d)(3), it could then create a new pooled unit on 160 acres. However, until the Commission approves dissolution of the Green Gas Unit, any application for a new well must be evaluated on the basis of the 683 acre unit Chesapeake voluntarily identified when it assigned the Green No. 1 well to the unit, and permitted and drilled the Green No. 2 and No. 3 wells. Accordingly, Chesapeake's alternative argument that it is entitled to a well on the easternmost 160 acres of the Green Gas Unit is not a legally permissible basis to support an exception to prevent confiscation.
CONCLUSION
Chesapeake failed to establish that is entitled to an exception to Rule 37 to prevent confiscation of natural gas underlying the Green Gas Unit in the Oak Hill (Cotton Valley) Field. Accordingly, the application for an exception to Rule 37 should be denied.
Based on the record in this Docket, the examiners recommend adoption of the following Findings of Fact and Conclusions of Law.
FINDINGS OF FACT
1. Chesapeake Operating, Inc. ("Applicant" or "Chesapeake") seeks an exception to Statewide Rule 37 to drill Well No. 4 on the-Green Gas Unit Lease, Oak Hill (Cotton Valley) Field. Chesapeake has also requested an exception to the maximum diagonal requirement for the proposed proration unit associated with the Green No. 4 well."Chesapeake appeared at the hearing and presented evidence in support of its application.
2. The application is protested by Anadarko E & P Company, L.P. ("Anadarko"), the offset operator on both sides of the river tract where the proposed well is-located. Anadarko also appeared at the hearing.
3. The Green Gas Unit is an irregularly shaped 683 acre pooled unit which includes land owned by the State of Texas and private lands. The 307.8 acres owned by the state is an approximately 10 mile long section of the Sabine River. The remaining 375.2 acres are privately owned tracts. The proposed well would be the fourth' well on the unit.
4. The Oak Hill (Cotton Valley) Field is subject to spacing requirements of 467 feet minimum distance to the nearest lease line and 1200 feet minimum distance between wells. The maximum diagonal requirement for the Oak Hill (Cotton Valley) Field is 5500 feet for 160 acre units, 3250 feet for 80 acre units, and 2100 feet for 40 acre units.
5. The proposed bottom hole location is in the center of the river tract, 75 feet from the offsetting property on both sides.
287 Rule 37 Case No. 0245869 • Page 9 Proposal for Decision
6. . Chesapeake proposes two alternative proration units for its Green No. 4 Well. The first unit includesl76 acres with a diagonal of approximately 58,000 feet. This lengthy diagonal is required because the proposed unit assigns a portion of the entire length of the Sabine River tract to the Green No. 4 Well. Alternatively, Chesapeake proposes a 40 acre proration unit with a diagonal of approximately 15,815 feet. The 40 acre proration unit assigns a portion of the river tract from the general vicinity of the proposed well to the easternmost terminus of the river tract, approximately 3 miles from the proposed location.
7. Regular locations exist on the Green Gas Unit in the Oak Hill (Cotton Valley) Field.
8. Chesapeake did not provide evidence establishing that regular locations on the Green Gas unit would not afford it a reasonable opportunity to recover the reserves currently underlying the subject lease in the Oak Hill (Cotton Valley) Field.
9. Chesapeake did not provide reliable evidence of the estimated current recoverable reserves underlying the Green Gas Unit.
a. The Oak Hill (Cotton Valley)' Field is productive from the lower Taylor sand, a uniform marine bar deposit, and from the Upper Cotton Valley, a group of independent sand lenses formed in a fluvial depositional environment.
b. • The Taylor sand is a structural trap while the Upper Cotton Valley is a series of laterally discontinuous sands which form stratigraphic traps.
c. Both formations are recognized as tight and require fracture stimulation of the producing interval.
d. The Upper Cotton Valley is described as "hit and miss" and does not exhibit a reliable trend within the Green Gas Unit:
e. Chesapeake inappropriately evaluated the Oak Hill (Cotton Valley) Field in its hydrocarbon pore volume and net pay maps by aggregating the Upper Cotton Valley sand with the Taylor sand in its analysis.
f. Published studies of the Oak Hill (Cotton Valley) Field relied on by both parties specifically caution against using the Upper Cotton Valley as a predictive tool of estimated ultimate recovery (EUR) trends.
g. Chesapeake's analysis considered the two intervals together and then mapped the cumulative total to provide the basis for the volumetric analysis.
288 Rule 37 Case No. 0245869 Page 10 Proposal for Decision
CONCLUSIONS OF LAW
1. Proper notice of hearing was timely given to all persons legally entitled to notice.
2. All things have occurred to give the Commission jurisdiction to decide this matter.
3. Applicant failed to establish that an exception to Statewide Rule 37 for a well at the applied- for location is necessary to prevent confiscation or waste.
RECOMMENDATION
The examiners recommend that Chesapeake's application be denied in accordance with the attached final order.
Respectfully submitted,
Mark J. Helmueller Donna Chandler Hearings Examiner Technical Examiner
289 TAB 8 Affidavit of Gregg Robertson • CAUSE NO. 13-05-0466-CVA • SHIRLEYY ADAMS, CHARLENE IN THE DISTRICT COUNT BURGESS, WILLIE MAE HERBST JASIK, WILLIAM. ALBERT HERBST, HELEN HERBST and R. MAY OIL & GAS COMPANY, LTD., Plaintiffs, 218th JUDICIAL DISTRICT vs.
MURPHY EXPLORATION & PRODUCTION CO.-USA, A DELAWARE CORPORATION, Defendant. ATASCOSA COUNTY, TEXAS.
STATE OF TEXAS
COUNTY OF NUECES
Before me, the undersigned :authority, on this day personally appeared Gregg Robertson,
and stated the following:
1. "My name is Gregg Robertson. I am over 18 years of a0, .of sound mind, and
capable of making this affidavit. Except where indicated otherwise, tli.e facts stated in this
affidavit are within my personal knowledge and are mile and correct.
2. For the past thirty-five years I have worked in the family Oil and gas business in
Corpus Christi, Texas that was founded by my father in 1975. We hav'e provided consulting 1 geological services to other companies, operated a well service company for twenty years,
operated oil and gas production for thirty .years and have been partners with numerous other oil
and gas companies in various oil and gas exploration and production ventures. My father was
instrumental in providing geologic supervision to the early pioneers in the Austin Chalk Trend
beginning in 1974, and I joined with Petrohawk Energy to drill the initial discovery wells for the
Hawkville (Eagle Ford Shale) Field in 2008. EXHIBIT b
2O 3219.I 238 3. • My educational background includes a B.A. in English from Sewanee: The
University of the. South in 1978, followed by studies at the graduate school of Geology at the
University of Texas, Austin from 1979-1980.
4. 1 have reviewed the Plaintiffs' Motion for Partial Suminary Judgment in the
above-described and numbered cause, the Affidavit of John C. McBeathJ P.B., and the Railroad
Commission filings for the Comstrock Oil & Gas, LP #11-I Lucas "A". well. and the .Murphy
Exploration and Production #111 Herbst "B" well, as well as the relevant portion of the Oil, Gas
and Mineral Leases covering the land where the Herbst well is drilled. I have been asked whether
the term "offset well" is a specialized term within the industry, and what its 'commonly
understood meaning is within the industry. More specifically, I have Veen asked whether. the
Murphy OH Herbst '13" Well is an "offset well" to the Comstock #114 1i,ucas "A" Welt, as that
term is used in Paragraph 25 of the Herbst leases.
5. It is ray opinion that the Murphy -#1H. Herbst "B" Well is not an "Offset well" to
the Comstock #1.H. Lucas "A" Well, as that term is used in 'the industry] and in the oil and gas.
lease. An "offset well", as that term is used in the industry, is a. well drille4 as close as.possible to
the offending well in order 'to prevent or minimize drainage from -the feased premises by the,
offending well.
6. • It is my understanding that there is no dispute that the gioveming Oil, Gas, and
Mineral Leases are in effect and contain a Paragraph 25 with the "offset 4vell provision", that the
Comstock well was permitted and actually drilled closer than the 467' buffer provided by the
offset :Well provision, and that. Murphy is relying upon the Herbst "B" OH well to satisfy the
remedies .reqUired by the lease when. a well is drilled within. 467 feet of the leased premises.
2 208321.9:1
239 7. • • Mr. McBeath's affidavit has two arguments to support his opinion that the
Murphy CH Herbst "B" Well satisfies Murphy's obligations under Paragraph 25 of the Herbst
leases: First, Mr. McBeath makes a distinction between the term. "offset Well" and the conjecture
of a more specifically used term in the industry of "direct offset well". Second, Mr. McBeath
argues that the lease provision relating to. an offset well has nothing to do with the potential for
drainage of the leased premises by the Comstock well ("Plaintiffs contention that an offset well,
as used in the Lease, exists to protect their acreage from drainage is not! correct." — Mel3eath,
page 6). Neither of these arguments has any credibility based upon conventional oilfield usage,
traditional' construction. of the English language nor Common seti8e,
8. Regarding Mr. McBeath's argument as to the purpose or Paragraph 25 of the
leases: based upon my involvement in the 'construction of several hundredi' oil and gas leases, and
specifically over one hundred oil and gas leases in the past five years 4r the development of i Eagle Ford Shale reserves, the inclusion of a provision such as the one in Paragraph 25 requiring.
'remedies by the Lessee should a well be drilled on offset acreage has only one, sole purpose - to
prevent, compensate and mitigate the drainage of the leased premises ig the offending well.
Common sense precludes any other construction. In fact, Paragraph 25 requires .the lessee to drill
an "offset well" if an offending well is drilled, which is specifically defined in the lease as a well
drilled within 467' of the leased premises, Which at the time the lease was executed, defined a
well drilled closer to the lease than Railroad Commission rules would allOw. The stated distance
of a well from the leased premises defines the specific intent that the coriesponding location of
an "off-set well" drilled under Paragraph 2'5 (1) should be equally as close to the offending well
as possible to protect the Lessors' reserves from drainage by the offending well. For Murphy to
state that the Herbst well, located over 2100 feet away from the offending well and being also as
3 2083219.1 240 S far away as the configuration of the lease would allow, satisfies the Leases' offset remedy cannot
be. supported by standard oilfield practice, the intent of the parties in negotiating the lease, or
common sense.
9. Mr. McBeath's attempt to explain a presumed difference between "an offset well"
and "a direct offset well" has no basis in standard oilfield practices. I, Have never seen in any
written contract nor heard in any conversation, such a distinction being made. Asserting that
there is no connection between. the term "offset well" and a specific distance from a lease line is
a contrived and desperate attempt to explain .Mtuphy's actions in this !matter. It deserves no
further i:ebtittal.
10.. In the highly competitive and intense development setting ,of the Eagle Ford Shale
Trend, it has been my practice and that of my partners in the drilling of over 300 wells across-
265,000 acres, to contact offset operators prior to setting up a drilling pattern that begins 330 feet
from the common property boundary. There are numerous alternatives to; starting a development
program on an adjacent lease to another operator rather than drilling the losest offset.well first.
To do so without- attempting to contact the offset operator first is akin t4 dropping -the glove
start a duel. Likewise, should this event -occur, it is incomprehensibly that a Lessee would
unilaterally drill a. knowingly contentious location such as' the Iviurphyi #1-H Herbst "B" Well
without conducting transparent conversations with the Lessors first. If the Herbst tract of land
Merited the drilling of a well, there was no purpose served for either MUrphy or the Lessors by
leaving the potential for drainage by the offsetting Comstock well un4hallenged. in fact, the
proper development of the Herbst tract Will require at least two additional wells, which will both
be significantly closer to the Comstock well than the current Herbst "B" Well, There is nothing in
the facts, viewed through the' perspective of standard oilfield practices. nor in Mr.. McBeath's
4. 2083219.1 241 • • affidavit., (which become specious when viewed through the perspective of the standard
construction of the English language and by common sense); that supports Murphy's claim that
its # l H Herbst "B" Well is an adequate remedy to satisfy its obligations under Paragraph 25 for
protection froth an offending offset well. "
•FURTHER, AFFIANT SAYETH NOT
STATE OF TEXAS
COUNTY OFNUECES
•Subscribed and sworn to before me, the undersigned authority on this the:.ieday of April, 2014.
DOWANNVE$MER MYtOMMI$SION. EXPIRES Febtuatyl% 2018 TIe Pu lic in and for the/. State of Texas
5 2083219.1 242 TAB 9 Excerpt from Court Reporter's Record
2 VOLUME 1 OF 1
3 Trial COURT NO. 13-05-0466-CVA
CHARLENE BURGESS, WILLIAM ALBERT AND OIL AND GAS, ) ) 9 VS ) 218TH JUDICIAL DISTRICT ) PRODUCTION COMPANY USA )
14 MOTION FOR RECONSIDERATION 15 February 10, 2015
18 On the 10th day of February, 2015 the
19 following proceedings came on to be held in the
20 above-titled and numbered cause before the Honorable
21 Stella Saxon, held in Jourdanton, Atascosa County,
22 Texas by agreement.
23 Proceedings reported by computerized stenotype
24 machine.
(210) 415-6628 46
1 unsuccessful We thi nk i t' s total I y i nappropri ate to
2 have i t. Even i f they do succeed, we don' t
3 automati cal I y get fees. Al I we get i s a remand back
4 to Your Honor and an opportunity to prove our
5 damages.
6 THE COURT: Prove whatever you can
7 prove.
8 Okay. Wel I , I gave careful
9 consi derati on to your arguments, your authori ti es and
10 struggled with this issue of offset. And frankl y, my
11 rul i ng was and sti II is that Murphy compl i ed with the
12 speci fi c terms of the I ease. That Mr. Stei n1 e i f he
13 wanted and the parti es wanted to I i mi t where that
14 offset dri I I needed to be pl aced on the adj acent
15 property in terms of how many feet from the I ease
16 I i ne that coul d have been put i n the I ease, but i t
17 wasn' t. And so the wel I was dri I I ed wi thi n the
18 ti meframe requi red. And the Court has found i t to be
19 an offset wel I. And the Court of Appeal s may very
20 wel I tel I me that was i ncorrect. And I wel come that
21 fi ndi ng i f that i s the fi ndi ng. I am not a big fan
22 of I I mi ti ng parti es access to the courts. And
23 frankl y my thinking on not awarding attorney's fees
24 as a result of the tri al proceeding was that the
25 PI ai nti ffs were certai n1 y enti tI ed to thei r thoughts
(210) 415-6628 47
1 as to the offset well needing to be drilled closer
2 and had the right to present their arguments to the
3 Court for the Court to make a determination on that,
4 and should not be penalized by having to pay huge
5 amounts of attorney's fees. And so attorney's fees
6 were not awarded. And I will change my order to the
7 extent of reducing the amount of attorney's fees
8 reasonable and necessary on appeal. And the Court of
9 Appeals can then determine whether or not that's an
10 appropriate decision by this Court as well. So fix
11 me up something that comports with my ruling, y'all
12 both sign i t, and I will be happy to sign it as well.
13 MS. KEENEY: Well, Your Honor, I did
14 prepare something that does -- an amended final
15 judgment that does deny the appellate fees. And it
16 seems to me our rights to an appeal would be
17 consistent with that, that there would be no fees on
18 appeal , there would be no fees at trial.
19 MR. NEWMAN: I thought Your Honor just
20 said you were going to reduce them?
21 MS. KEENEY: I would submit that they
22 should be reduced to zero. That's what this judgment
23 does.
24 MR. NEWMAN: Well, Your Honor, I think
25 -- We would agree, again as we have said, we have
(210) 415-6628 TAB 10 January 21, 2015 Alfred A. Steinle Amicus Letter January 21, 2015
Ms. Margaret E. Littleton Atascosa County District Clerk #1 Courthouse Circle Drive Suite 4-B Jourdanton, Texas 78026
Re: Cause No. 13-05-0466-CVA; Shirley Adams, et al v. Murphy Exploration & Production Co. - USA, a Delaware Corporation; In the 218th Judicial District of Atascosa County, Texas
Dear Ms. Littleton:
This letter is intended as an amicus filing in support of the Plaintiffs' motion for reconsideration of the trial court's rulings on the partial summary judgment motions submitted in the above-described and numbered cause. A copy of this letter is also being mailed to the Honorable Russell Wilson, the district judge now presiding over this case.
I was the attorney who drafted the leases at issue in this case. In particular, I drafted the offset clause provision in both leases. I have prepared hundreds of leasps that contain this same offset clause provision for mineral interest owners in this -part of the State. The ruling in this case — which allows a well located anywhere on the leased property to constitute an offset well — effectively renders meaningless these offset clause provisioni and will -adversely impact all -of- these mineral interest owners. This offset well provision is intended to protect against drainage. I purposefully omitted the word drainage from the test for the offending well because of the difficulty and expense involved in proving that an offending well is draining the lease tract. By, using a stipulated distance of 467 feet from the lease line, the parties contractually agree that any well drilled within 467 feet of the lease line is draining the lease tract. However, to protect against drainage, the offset well should be drilled as close as reasonably possible; but in any event within the stipulated 467 feet from the lease line, next to the well it is intended to offset. To say, as a matter of law, that a well drilled more than three times this contractual drainage distance of 467 feet is an offset well completely negates the intent and contractual protection of this clause.
Respectfully submitted,
,FILED• . ) - O'CLOCK - M Alffed A. Steinle MARGARET E LITTLETON, DISTRICT CLERK Attorney at Law ..*.' State Bar No. 19137600 - JAN 2 6 2015
CIE TX BY 4F a. ATIs 1-Y
2241370.1
448 TAB 11 RRC ADMINISTRATIVE RULES <
(a) Applicability. Each operator who conducts operations as described in paragraph (1) of this subsection shall be subject to this section and shall provide safeguards to protect the general public from the harmful effects of hydrogen sulfide. This section applies to both intentional and accidental releases of hydrogen sulfide.
(1) Operations including drilling, working over, producing, injecting, gathering, processing, transporting, and storage of hydrocarbon fluids that are part of, or directly related to, field production, transportation, and handling of hydrocarbon fluids that contain gas in the system which has hydrogen sulfide as a constituent of the gas, to the extent as specified in subsection (c) of this section, general provisions.
(2) This section shall not apply to:
(A) operations involving processing oil, gas, or hydrocarbon fluids which are either an industrial modification or products from industrial modification, such as refining, petrochemical plants, or chemical plants;
(B) operations involving gathering, storing, and transporting stabilized liquid hydrocarbons;
(C) operations where the concentration of hydrogen sulfide in the system is less than 100 ppm.
(b) Definitions.
(1) Industrial modification--This term is used to identify those operations related to refining, petrochemical plants, and chemical plants. The term does not include field processing such as that performed by gasoline plants and their associated gathering systems.
(2) Stabilized liquid hydrocarbon--The product of a production operation in which the entrained gaseous hydrocarbons have been removed to the degree that said liquid may be stored at atmospheric conditions.
(3) Radius of exposure--That radius constructed with the point of escape as its starting point and its length calculated as provided for in subsection (c)(2) of this section. (4) Area of exposure--The area within a circle constructed with the point of escape as its center and the radius of exposure as its radius.
(5) Public area--A dwelling, place of business, church, school, hospital, school bus stop, government building, a public road, all or any portion of a park, city, town, village, or other similar area that can expect to be populated.
(6) Public road--Any federal, state, county, or municipal street or road owned or maintained for public access or use.
(7) Sulfide stress cracking--The cracking phenomenon which is the result of corrosive action of hydrogen sulfide on susceptible metals under stress.
(8) Facility modification--Any change in the operation such as an increase in throughput, in excess of the designed capacity, or any change that would increase the radius of exposure.
(9) Public infringement--This shall mean that a public area and/or a public road, or both, has been established within an area of exposure to the degree that such infringement would change the applicable provisions of this rule to those operations responsible for creating the area of exposure.
(10) Potentially hazardous volume of hydrogen sulfide--A volume of hydrogen sulfide gas of such concentration that:
(A) the 100 ppm radius of exposure is in excess of 50 feet and includes any part of a "public area" except a public road; or
(B) the 500 ppm radius of exposure is greater than 50 feet and includes any part of a public road; or
(C) the 100 ppm radius of exposure is greater than 3,000 feet.
(11) Contingency plan--A written document that shall provide an organized plan of action for alerting and protecting the public within an area of exposure prior to an intentional release, or following the accidental release of a potentially hazardous volume of hydrogen sulfide.
(12) Reaction-type contingency plan--A preplanned, written procedure for alerting and protecting the public, within an area of exposure, where it is impossible or impractical to brief in advance all of the public that might possibly be within the area of exposure at the moment of an accidental release of a potentially hazardous volume of hydrogen sulfide.
(13) Definition of referenced organizations and publications.
(A) ANSI--American National Standard Institute, 1430 Broadway, New York, New York 10018, Table I, Standard 253.1-1967. (B) API--American Petroleum Institute, 300 Corrigan Tower Building, Dallas, Texas 75201, Publication API RP-49, Publication API RP-14E, Sections 1.7(c), 2.1(c) 4.7.
(C) ASTM--American Society for Testing and Materials, 1916 Race Street, Philadelphia, Pennsylvania 19103, Standard D-2385-66.
(D) GPA--Gas Processors Association, 1812 First Place, Tulsa, Oklahoma 74120, Plant Operation Test Manual C-1, GPA Publication 2265-68.
(E) NACE--National Association of Corrosion Engineers, P.O. Box 1499, Houston, Texas 77001, Standard MR-01-75.
(F) DOT--Department of Transportation, Office of Pipeline Safety, 400 Seventh Street, S.W., Washington, D.C. 20590, Title 49, Code of Federal Regulations, Parts 192 and 195.
(G) OSHA--Occupational Safety and Health Administration, United States Department of Labor, 200 Constitution Avenue, NW, Washington D.C. 20270, Title 29, Code of Federal Regulations, Part 1910.145(c)(4)(i).
(H) RRC--Railroad Commission of Texas, Gas Utilities Division, P.O. Drawer 12967, Capitol Station, Austin, Texas 78711, Gas Utilities Dockets 446 and 183.
(c) General provisions.
(1) Each operator shall determine the hydrogen sulfide concentration in the gaseous mixture in the operation or system.
(A) Tests shall be made in accordance with standards as set by ASTM Standard D-2385-66, or GPA Plant Operation Test Manual C-1, GPA Publication 2265-68, or other methods approved by the commission.
(B) Test of vapor accumulation in storage tanks may be made with industry accepted colonnetric tubes.
(2) For all operations subject to this section, the radius of exposure shall be determined, except in the cases of storage tanks, by the following Pasquill-Gifford equations, or by other methods that have been approved by the commission.
(A) For determining the location of the 100 ppm radius of exposure: x = [(1.589) (mole fraction H2 S)(Q)] to the power of (.6258).
(B) For determining the location of the 500 ppm radius of exposure: x = [(0.4546) (mole fraction H2 S)(Q)] to the power of (.6258). Where x = radius of exposure in feet; Q = maximum volume determined to be available for escape in cubic feet per day; H 2 S = mole fraction of hydrogen sulfide in the gaseous mixture available for escape.
(3) The volume used as the escape rate in determining the radius of exposure shall be that specified in subparagraph (A) - (E) of this paragraph, as applicable.
(A) The maximum daily volume rate of gas containing hydrogen sulfide handled by that system element for which the radius of exposure is calculated.
(B) For existing gas wells, the current adjusted open-flow rate, or the operator's estimate of the well's capacity to flow against zero back-pressure at the wellhead shall be used.
(C) For new wells drilled in developed areas, the escape rate shall be determined by using the current adjusted open-flow rate of offset wells, or the field average current adjusted open-flow rate, whichever is larger.
(D) The escape rate used in determining the radius of exposure shall be corrected to standard conditions of 14.65 pounds per square inch (psia) and 60 degrees Fahrenheit.
(E) For intentional releases from pipelines and pressurized vessels, the operator's estimate of the volume and release rate based on the gas contained in the system elements to be de-pressured.
(4) For the drilling of a well in an area where insufficient data exists to calculate a radius of exposure, but where hydrogen sulfide may be expected, then a 100 ppm radius of exposure equal to 3,000 feet shall be assumed. A lesser-assumed radius may be considered upon written request setting out the justification for same.
(5) Storage tank provision: storage tanks which are utilized as a part of a production operation, and which are operated at or near atmospheric pressure, and where the vapor accumulation has a hydrogen sulfide concentration in excess of 500 ppm, shall be subject to the following.
(A) No determination of a radius of exposure shall be made for storage tanks as herein described.
(B) A warning sign shall be posted on or within 50 feet of the facility to alert the general public of the potential danger.
(C) Fencing as a security measure is required when storage tanks are located inside the limits of a townsite or city, or where conditions cause the storage tanks to be exposed to the public.
(D) The warning and marker provision, paragraph (6)(A)(i), (ii), and (iv) of this subsection.
(E) The certificate of compliance provision, subsection (d)(1) of this section. (6) All operators whose operations are subject to this section, and where the 100 ppm radius of exposure is in excess of 50 feet, shall be subject to the following.
(A) Warning and marker provision.
(i) For above-ground and fixed surface facilities, the operator shall post, where permitted by law, clearly visible warning signs on access roads or public streets, or roads which provide direct access to facilities located within the area of exposure.
(ii) In populated areas such as cases of townsites and cities where the use of signs is not considered to be acceptable, then an alternative warning plan may be approved upon written request to the commission.
(iii) For buried lines subject to this section, the operator shall comply with the following.
(I) A marker sign shall be installed at public road crossings.
(II) Marker signs shall be installed along the line, when it is located within a public area or along a public road, at intervals frequent enough in the judgment of the operator so as to provide warning to avoid the accidental rupturing of line by excavation.
(III) The marker sign shall contain sufficient information to establish the ownership and existence of the line and shall indicate by the use of the words "Poison Gas" that a potential danger exists. Markers installed in compliance with the regulations of the federal Department of Transportation shall satisfy the requirements of this provision. Marker signs installed prior to the effective date of this section shall be acceptable provided they indicate the existence of a potential hazard.
(iv) In satisfying the sign requirement of clause (i) of this subparagraph, the following will be acceptable.
(I) Sign of sufficient size to be readable at a reasonable distance from the facility.
(II) New signs constructed to satisfy this section shall use the language of "Caution" and "Poison Gas" with a black and yellow color contrast. Colors shall satisfy Table I of American National Standard Institute Standard 253.1-1967. Signs installed to satisfy this section are to be compatible with the regulations of the federal Occupational Safety and Health Administration.
(III) Existing signs installed prior to the effective date of this section will be acceptable if they indicate the existence of a potential hazard.
(B) Security provision. (i) Unattended fixed surface facilities shall be protected from public access when located within 1/4 mile of a dwelling, place of business, hospital, school, church, government building, school bus stop, public park, town, city, village, or similarly populated area. This protection shall be provided by fencing and locking, or removal of pressure gauges and plugging of valve opening, or other similar means. For the purpose of this provision, surface pipeline shall not be considered as a fixed surface facility.
(ii) For well sites, fencing as a security measure is required when a well is located inside the limits of a townsite or city, or where conditions cause the well to be exposed to the public.
(iii) The fencing provision will be considered satisfied where the fencing structure is a deterrent to public access.
(C) Materials and equipment provision.
(i) For new construction or modification of facilities (including materials and equipment to be used in drilling and workover operations) completed or contemplated subsequent to the effective date of this section, the metal components shall be those metals which have been selected and manufactured so as to be resistant to hydrogen sulfide stress cracking under the operating conditions for which their use is intended, provided that they satisfy the requirements described in the latest editions of NACE Standard MR-01-75 and API RP-14E, sections 1.7(c), 2.1(c), 4.7. The handling and installation of materials and equipment used in hydrogen sulfide service are to be performed in such a manner so as not to induce susceptibility to sulfide stress cracking. Other materials which are nonsusceptible to sulfide stress cracking, such as fiberglass and plastics, may be used in hydrogen sulfide service provided such materials have been manufactured and inspected in a manner which will satisfy the latest published, applicable industry standard, specifications, or recommended practices.
Cont'd...
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HOME TEXAS REGISTER TEXAS ADMINISTRATIVE CODE OPEN MEETINGS <
(a) Distance requirements.
(1) No well for oil, gas, or geothermal resource shall hereafter be drilled nearer than 1,200 feet to any well completed in or drilling to the same horizon on the same tract or farm, and no well shall be drilled nearer than 467 feet to any property line, lease line, or subdivision line; provided the commission, in order to prevent waste or to prevent the confiscation of property, may grant exceptions to permit drilling within shorter distances than prescribed in this paragraph when the commission shall determine that such exceptions are necessary either to prevent waste or to prevent the confiscation of property.
(2) When an exception to this section is desired, application shall be made by filing the proper fee as provided in §3.78 of this title (relating to Fees and Financial Security Requirements) and the appropriate form according to the instructions on the form, accompanied by a plat as described in subsection (c) of this section. A person acquainted with the facts pertinent to the application shall certify that all facts stated in it are true and within the knowledge of that person.
(A) When an exception to only the minimum lease-line spacing requirement is desired, the applicant shall file a list of the mailing addresses of all affected persons, who, for tracts closer to the well than the greater of one-half of the prescribed minimum between-well spacing distance or the minimum lease-line spacing distance, include:
(i) the designated operator;
(ii) all lessees of record for tracts that have no designated operator; and
(iii) all owners of record of unleased mineral interests.
(B) When an exception to the minimum between-well spacing requirement of this section is desired, the applicant is required to file the mailing addresses of those persons identified in subparagraph (A)(i)-(iii) of this paragraph for each adjacent tract and each tract nearer to the well than the greater of one-half the prescribed minimum between-well spacing distance or the minimum lease-line spacing. (3) An exception may be granted pursuant to subsection (h)(2) of this section, or after a public hearing held after at least 10 days notice to all persons described in paragraph (2) of this subsection. At any such hearing, the burden shall be on the applicant to establish that an exception to this section is necessary either to prevent waste or to prevent the confiscation of property. For purposes of giving notice of an application for an exception, the commission will presume that every person described in paragraph (2) of this subsection will be affected by the application, unless the Oil and Gas Division director or the director's delegate determines they are unaffected. Such determination will be made only upon written request and a showing by the applicant that:
(A) competent, conclusive geological or engineering data indicate that no drainage of hydrocarbons from the particular tract(s) subject to the request will occur due to production from the applicant's proposed well; and
(B) notice to the particular operator(s), lessee(s) of record, or owner(s) of record of unleased mineral interest would be unduly burdensome or expensive.
(b) The distances mentioned in subsection (a) of this section are minimum distances to provide standard development on a pattern of one well to each 40 acres in areas where proration units have not been established.
(c) In filing an application for an exception to the distance requirements of this section, in addition to the plat requirements in §3.5 of this title (relating to Application to Drill, Deepen, Reenter, or Plug Back) (Statewide Rule 5), the applicant shall attach to each copy of the form a plat that:
(1) shows to scale the property on which the exception is sought; all other applied for, permitted, and completed oil, gas, or oil and gas wells in the same field and reservoir on said property; and all adjoining surrounding properties and completed wells in the same field and reservoir within the prescribed minimum between-well spacing distance of the applicant's well;
(2) shows the entire lease, pooled unit, or unitized tract indicating the names and offsetting properties of all affected offset operators;
(3) corresponds to the listing required under subsection (a)(2) of this section;
(4) is certified by a person acquainted with the facts pertinent to the application that the plat is accurately drawn to scale and correctly reflects all pertinent and required data.
(d) In the interest of protecting life and for the purpose of preventing waste and preventing the confiscation of property, the commission reserves the right in particular oil, gas, and geothermal resource fields to enter special orders increasing or decreasing the minimum distances provided by this section. (e) No well drilled in violation of this section without special permit obtained, issued, or granted in the manner prescribed in said section, and no well drilled under such special permit or on the commission's own order which does not conform in all respects to the terms of such permit shall be permitted to produce either oil, gas, or geothermal resources and any such well so drilled in violation of said section or on the commission's own order shall be plugged.
(f) No operator shall commence the drilling of a well, either on a regular location or on a Rule 37 exception location, until first having been notified by the commission that the regular location has been approved, or that the Rule 37 exception location has been approved. Failure of an operator to comply with this subsection will cause such well to be closed in and the holding up of the allowable of such well.
(g) Subdivision of property.
(1) In applying Rule 37 (Statewide Spacing Rule) of statewide application and in applying every special rule with relation to spacing in every field in this state, no subdivision of property made subsequent to the adoption of the original spacing rule will be considered in determining whether or not any property is being confiscated within the terms of such spacing rule, and no subdivision of property will be regarded in applying such spacing rule or in determining the matter of confiscation if such subdivision took place subsequent to the promulgation and adoption of the original spacing rule.
(2) Any subdivision of property creating a tract of such size and shape that it is necessary to obtain an exception to the spacing rule before a well can be drilled thereon is a voluntary subdivision and not entitled to a permit to prevent confiscation of property if it were either:
(A) segregated from a larger tract in contemplation of oil, gas, or geothermal resource development; or
(B) segregated by fee title conveyance from a larger tract after the spacing rule became effective and the voluntary subdivision rule attached.
(3) The date of attachment of the voluntary subdivision rule is the date of discovery of oil, gas, or geothermal resource production in a certain continuous reservoir, regardless of the subsequent lateral extensions of such reservoir, provided that such rule does not attach in the case of a segregation of a small tract by fee title conveyance which is not located in an oil, gas, or geothermal resource field having a discovery date prior to the date of such segregation.
(4) The date of attachment of the voluntary subdivision rule for multiple reservoir fields located in the same structural feature and separated vertically but not laterally (i.e., the multiple reservoirs overlap geographically at least in part), shall be the same date as that assigned to the earliest discovery well for such multiple reservoir structure. (5) If a newly discovered reservoir is located outside the then productive limits of any previously discovered reservoirs and is classified by the commission as a newly discovered field, then the date of discovery of such newly found reservoir remains the date of attachment for the voluntary subdivision rule, even though subsequent development may result in the extension of such newly discovered reservoir until it overlies or underlies older reservoirs with prior discovery dates.
(6) The date of attachment of the voluntary subdivision rule for a reservoir that has been developed through expansion of separately recognized fields into a recognized single reservoir and is merged by commission order is the earliest discovery date of production from such merged reservoir, and that date will be used subsequent to the date of merger of the fields into a single field.
(7) The date of attachment of the voluntary subdivision rule for a reservoir under any special circumstance which the commission deems sufficient to provide for an exception may be established other than as prescribed in this section, so that innocent parties may have their rights protected.
(h) Exceptions to Rule 37.
(1) An order granting exception to Rule 37 wherein protest is had shall carry as its last paragraph the following language: It is further ordered by the commission that this order shall not be final until 20 days after it is actually mailed to the parties by the commission; provided that if a motion for rehearing of the application is filed by any party at interest within such 20-day period, this order shall not become final until such motion is overruled, or if such motion is granted, this order shall be subject to further action by the commission. Permits issued pursuant to paragraph (2) of this subsection shall be issued without the 20-day waiting period.
(2) The director of the Oil and Gas Division or a delegate of the director may issue an exception permit for drilling, deepening, or additional completion, recompletion, or reentry in an existing well bore if:
(A) a notice of at least 10 days has been given, and no protest has been made to the application; or
(B) written waivers of objection are received from all persons to whom notice would be given pursuant to subsection (a)(2) of this section.
(3) Applications filed for drilling, deepening, or additional completion, recompletion, or reentry will be processed and permit issued in accordance with this regulation, subject to the commission's discretion to set any application for hearing. If the director or a delegate of the director declines to grant an application, the operator may request a hearing.
(i) Rule 37 permits. (1) Unless otherwise specified in a permit or in a final order granting an exception to this section, permits issued by the commission for completions requiring an exception to this section shall expire two years from the effective date of the permit unless drilling operations are commenced in good faith within the two-year permit period. The permit period will not be extended.
(2) So long as a Rule 37 exception is in litigation, the two-year permit period will not commence. On final adjudication and decree from the last court of appeal the two-year permit period will commence, beginning on the date of final decree.
(j) Once an application for a spacing exception has been denied, no new application shall be entertained except on changed conditions. Changed conditions in the commission's administration of its Spacing Rule 37 and amendments thereto applicable to the various special fields and reservoirs of Texas and in passing upon applications for permits under said rule and amendments shall include, among other things, the following.
(1) Any material changes in the physical conditions of the producing reservoir under the tract under consideration or under the area surrounding said tract which would materially affect the recovery of oil, gas, or geothermal resource from the given tract.
(2) Any material changes in the distribution or allocation of allowable production in the area surrounding the tract under consideration which would materially affect or tend to affect the recovery of oil, gas, or geothermal resource from the given tract.
(3) Any additional permits granted by the commission for wells drilled in the area surrounding or on offset tracts to the tract under consideration which would materially affect or tend to affect the recovery of oil, gas, or geothermal resource from the given tract.
(4) Any additional facts or evidence thereof materially affecting or tending to affect the recovery of oil, gas, or geothermal resource from the applicant's tract, or the property rights of applicant, which were not known of and considered by the commission at any previous hearing or application thereon.
(k) Exceptions to Statewide Rule 37 apply to the total depth for which the permit is granted or if special field rules are applicable, an exception to the spacing rule shall be granted only for the reservoir or reservoirs or applicable depth to which the well is projected. Subsequent recompletion of the well to reservoirs other than that covered by the permit issued would be granted only after the filing and processing of a new application.
(1) Salt dome oil or gas fields.
(1) The provisions of this section shall not apply to certain approved salt dome oil or gas fields. An application for classification as a salt dome oil or gas field shall include the following: (A) geological evidence proving that an oil or gas field is a piercement-type salt dome, that faulting has caused the producing formation to be at a 45 angle or greater, and that each well is likely to be completed in a separate reservoir;
(B) establishment, by plat or otherwise, of the probable productive limits of the salt dome area;
Cont'd...
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HOME TEXAS REGISTER TEXAS ADMINISTRATIVE CODE OPEN MEETINGS < (a) Permit required. Any person who engages in fluid injection operations in reservoirs productive of oil, gas, or geothermal resources must obtain a permit from the commission. Permits may be issued when the injection will not endanger oil, gas, or geothermal resources or cause the pollution of freshwater strata unproductive of oil, gas, or geothermal resources. Permits from the commission issued before the effective date of this section shall continue in effect until revoked, modified, or suspended by the commission. (b) Filing of application. (1) Application. (A) An application to conduct fluid injection operations in a reservoir productive of oil, gas, or geothermal resources shall be filed in Austin on the form prescribed by the commission accompanied by the prescribed fee. On the same date, one copy shall be filed with the appropriate district office. The form shall be executed by a party having knowledge of the facts entered on the form. (B) The applicant shall file the freshwater injection data form if fresh water is to be injected. (C) The applicant for a disposal well permit under this section shall include with the permit application a printed copy or screenshot showing the results of a survey of information from the United States Geological Survey (USGS) regarding the locations of any historical seismic events within a circular area of 100 square miles (a circle with a radius of 9.08 kilometers) centered around the proposed disposal well location. (D) The commission may require an applicant for a disposal well permit under this section to provide the commission with additional information such as logs, geologic cross-sections, pressure front boundary calculations, and/or structure maps, to demonstrate that fluids will be confined if the well is to be located in an area where conditions exist that may increase the risk that fluids will not be confined to the injection interval. Such conditions may include, but are not limited to, complex geology, proximity of the basement rock to the injection interval, transmissive faults, and/or a history of seismic events in the area as demonstrated by information available from the USGS. (2) Commercial disposal well. An applicant for a permit to dispose of oil and gas waste in a commercial disposal well shall clearly indicate on the application and in the notice of application that the application is for a commercial disposal well permit. For the purposes of this rule, "commercial disposal well" means a well whose owner or operator receives compensation from others for the disposal of oil field fluids or oil and gas wastes that are wholly or partially trucked or hauled to the well, and the primary business purpose for the well is to provide these services for compensation. (c) Notice and opportunity for hearing. (1) The applicant shall give notice by mailing or delivering a copy of the application to affected persons who include the owner of record of the surface tract on which the well is located; each commission-designated operator of any well located within one half mile of the proposed injection well; the county clerk of the county in which the well is located; and the city clerk or other appropriate city official of any city where the well is located within the corporate limits of the city, on or before the date the application is mailed to or filed with the commission. For the purposes of this section, the term "of record" means recorded in the real property or probate records of the county in which the property is located. (2) In addition to the requirements of subsection (c)(1), a commercial disposal well permit applicant shall give notice to owners of record of each surface tract that adjoins the proposed injection tract by mailing or delivering a copy of the application to each such surface owner. (3) If, in connection with a particular application, the commission or its delegate determines that another class of persons should receive notice of the application, the commission or its delegate may require the applicant to mail or deliver a copy of the application to members of that class. Such classes of persons could include adjacent surface owners or underground water conservation districts. (4) In order to give notice to other local governments, interested, or affected persons, notice of the application shall be published once by the applicant in a newspaper of general circulation for the county where the well will be located in a form approved by the commission or its delegate. The applicant shall file with the commission in Austin proof of publication prior to the hearing or administrative approval. (5) Protested applications: (A) If a protest from an affected person or local government is made to the commission within 15 days of receipt of the application or of publication, whichever is later, or if the commission or its delegate determines that a hearing is in the public interest, then a hearing will be held on the application after the commission provides notice of hearing to all affected persons, local governments, or other persons, who express an interest, in writing, in the application. (B) For purposes of this section, "affected person" means a person who has suffered or will suffer actual injury or economic damage other than as a member of the general public or as a competitor, and includes surface owners of property on which the well is located and commission- designated operators of wells located within one-half mile of the proposed disposal well. (6) If no protest from an affected person is received by the commission, the commission's delegate may administratively approve the application. If the commission's delegate denies administrative approval, the applicant shall have a right to a hearing upon request. After hearing, the examiner shall recommend a final action by the commission. (d) Subsequent commission action. (1) An injection well permit may be modified, suspended, or terminated by the commission for just cause after notice and opportunity for hearing, if: (A) a material change of conditions occurs in the operation or completion of the injection well, or there are material changes in the information originally furnished; (B) fresh water is likely to be polluted as a result of continued operation of the well; (C) there are substantial violations of the terms and provisions of the permit or of commission rules; (D) the applicant has misrepresented any material facts during the permit issuance process; (E) injected fluids are escaping from the permitted injection zone; (F) for a disposal well permit under this section, injection is likely to be or determined to be contributing to seismic activity; or (G) waste of oil, gas, or geothermal resources is occurring or is likely to occur as a result of the permitted operations. (2) An injection well permit may be transferred from one operator to another operator provided that the commission's delegate does not notify the present permit holder of an objection to the transfer prior to the date the lease is transferred on commission records. (3) Voluntary permit suspension. (A) An operator may apply to temporarily suspend its injection authority by filing a written request for permit suspension with the commission in Austin, and attaching to the written request the results of an MIT test performed during the previous three-month period in accordance with the provisions of subsection (j)(4) of this section. The provisions of this paragraph shall not apply to any well that is permitted as a commercial injection well. (B) The commission or its delegate may grant the permit suspension upon determining that the results of the MIT test submitted under subparagraph (A) of this paragraph indicate that the well meets the performance standards of subsection (j)(4) of this section. (C) During the period of permit suspension, the operator shall not use the well for injection or disposal purposes. (D) During the period of permit suspension, the operator shall comply with all applicable well testing requirements of §3.14 of this title (relating to plugging, and commonly referred to as Statewide Rule 14) but need not perform the MIT test that would otherwise be required under the provisions of subsection (j)(4) of this section or the permit. Further, during the period of permit suspension, the provisions of subsection (i)(1) - (3) of this section shall not apply. (E) The operator may reinstate injection authority under a suspended permit by filing a written notification with the commission in Austin. The written notification shall be accompanied by an MIT test performed during the three-month period prior to the date notice of reinstatement is filed. The MIT test shall have been performed in accordance with the provisions and standards of subsection (j)(4) of this section. (e) Area of Review. (1) Except as otherwise provided in this subsection, the applicant shall review the data of public record for wells that penetrate the proposed disposal zone within a 1/4 mile radius of the proposed disposal well to determine if all abandoned wells have been plugged in a manner that will prevent the movement of fluids from the disposal zone into freshwater strata. The applicant shall identify in the application any wells which appear from such review of public records to be unplugged or improperly plugged and any other unplugged or improperly plugged wells of which the applicant has actual knowledge. (2) The commission or its delegate may grant a variance from the area-of-review requirements of paragraph (1) of this subsection upon proof that the variance will not result in a material increase in the risk of fluid movement into freshwater strata or to the surface. Such a variance may be granted for an area defined both vertically and laterally (such as a field) or for an individual well. An application for an areal variance need not be filed in conjunction with an individual permit application or application for permit amendment. Factors that may be considered by the commission or its delegate in granting a variance include: (A) the area affected by pressure increases resulting from injection operations; (B) the presence of local geological conditions that preclude movement of fluid that could endanger freshwater strata or the surface; or (C) other compelling evidence that the variance will not result in a material increase in the risk of fluid movement into freshwater strata or to the surface. (3) Persons applying for a variance from the area-of-review requirements of paragraph (1) of this subsection on the basis of factors set out in paragraph (2)(B) or (C) of this subsection for an individual well shall provide notice of the application to those persons given notice under the provisions of subsection (c)(1) of this section. The provisions of subsection (c) of this section shall apply in the case of an application for a variance from the area-of-review requirements for an individual well. (4) Notice of an application for an areal variance from the area-of-review requirements under paragraph (1) of this subsection shall be given on or before the date the application is filed with the commission: (A) by publication once in a newspaper having general circulation in each county, or portion thereof, where the variance would apply. Such notice shall be in a form approved by the commission or its delegate prior to publication and must be at least three inches by five inches in size. The notice shall state that protests to the application may be filed with the commission during the 15-day period following the date of publication. The notice shall appear in a section of the newspaper containing state or local news items; (B) by mailing or delivering a copy of the application, along with a statement that any protest to the application should be filed with the commission within 15 days of the date the application is filed with the commission, to the following: (i) the manager of each underground water conservation district in which the variance would apply, if any; (ii) the city clerk or other appropriate official of each incorporated city in which the variance would apply, if any; (iii) the county clerk of each county in which the variance would apply; and (iv) any other person or persons that the commission or its delegate determines should receive notice of the application. (5) If a protest to an application for an areal variance is made to the commission by an affected person, local government, underground water conservation district, or other state agency within 15 days of receipt of the application or of publication, whichever is later, or if the commission's delegate determines that a hearing on the application is in the public interest, then a hearing will be held on the application after the commission provides notice of the hearing to all local governments, underground water conservation districts, state agencies, or other persons, who express an interest, in writing, in the application. If no protest from an affected person is received by the commission, the commission's delegate may administratively approve the application. If the application is denied administratively, the person(s) filing the application shall have a right to hearing upon request. After hearing, the examiner shall recommend a final action by the commission. Cont'd... 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Shirley Adams, Charlene Burgess, Willie Mae Herbst Jasik, William Albert Herbst, Helen Herbst and R. May Oil & Gas Company, Ltd. v. Murphy Exploration & Production Co.-USA, a Delaware Corporation (Shirley Adams, Charlene Burgess, Willie Mae Herbst Jasik, William Albert Herbst, Helen Herbst and R. May Oil & Gas Company, Ltd. v. Murphy Exploration & Production Co.-USA, a Delaware Corporation) — published by Counsel Stack Legal Research, free access to 12M+ legal documents.