Marathon Oil Company brought an action to set aside two decisions of the Secretary of the Interior, each of which precluded the counting, for royalty rate determination purposes, of water injection wells located outside the “participating areas.” The trial *983court held that the decision in the Oregon Basin case was manifestly contrary to the applicable provisions of the unit agreement, and similarly that the decision in the Elk Basin case was manifestly contrary to the plain meaning of the language contained in 30 C.F.R. § 221.49, to the end that each decision was plainly erroneous and, under the standard of review in the Administrative Procedure Act, was “arbitrary, capricious, an abuse of discretion, or otherwise not in accord with the law.” 5 U.S.C. § 706(2)(A). Accordingly, the trial court entered judgment setting aside each of the two decisions. The trial court’s memorandum opinion appears at 407 F.Supp. 1301 (D.Wyo.1975). The Secretary now appeals. We affirm.
For a detailed statement of the background facts the reader is referred to the memorandum opinion of the trial court, and we shall proceed here on the premise that the reader of this opinion is thoroughly conversant with the trial court’s memorandum opinion. For our purposes we would only note that, as relates to both the Oregon Basin and the Elk Basin, the royalty owed the United States is tied into the average daily production per well. Under this formula, assuming a given volume of production from a given participating area, it is apparent that the greater the number of wells which may be counted, the lower the average daily production per well. In turn, then, the royalty rate decreases, as specified in the royalty schedule, and the total royalty due the United States is accordingly less.
As concerns the Oregon Basin, twenty-nine water injection wells were drilled for the purpose of increasing the oil production from the oil wells situate within the participating areas. The selection of the specific site for each of these wells was made on the basis of maximizing the oil production from the producing wells in the participating areas. Thirteen of these water injection wells were located outside the outer boundaries of the participating areas.
As concerns the Elk Basin, eight water injection wells were drilled in order to increase oil production from the wells within the participating area, the site in each instance being determined by where the water injection well would do the most good in increasing oil production. Seven of these were located outside the participating area.
The question as to both the Oregon and Elk basins is whether the water injection wells located outside the participating areas are to be counted as wells in determining the average daily production per well. If such are to be included, then Marathon owes a lesser royalty to the United States. If these wells are not to be included, then Marathon owes the United States a much greater royalty. Resolution of the Oregon Basin case turns on the interpretation to be given section 13 of the unit agreement. Resolution of the Elk Basin case turns on the interpretation to be given 30 C.F.R. § 221.49, which was incorporated by reference into the Elk Basin unit agreement. The critical language in section 13 of the. Oregon Basin unit agreement is in some respects similar to, though not identical with, the critical language in 30 C.F.R. § 221.49.
Section 13 of the Oregon Basin Unit Agreement reads as follows:
13. ROYALTIES: Royalties shall be paid at the rates specified in the respective leases upon that portion of the unitized substances produced and sold from any participating area which is allocated to each tract; provided that' royalty due the United States on account of unitized Federal land shall be computed as provided in the operating regulations and paid in value or delivered in kind as to all unitized substances on the basis of the amounts thereof allocated to such land as provided herein at the rates specified in the respective Federal leases, or at such lower rate or rates as may be authorized by law or regulation; provided that, for leases in which the royalty rate on oil depends on the average daily oil production per well, the royalty rate in each participating area shall be determined for each such lease by the average daily pro*984duction of all oil wells subject to this agreement producing from that participating area. Subject to approval of the Supervisor, in accordance with the operating regulations, all oil wells shut in for conservation purposes in each participating area, including productive oil wells with excess gas-oil ratios and any and all wells of any character actually used for repressuring or recycling, shall be counted as producing oil wells; and for leases in which the royalty rate on gas depends on the average daily gas production per well, the royalty rate in each participating area shall be determined for each such lease by the average daily production of gas per well subject to this agreement producing from that participating area. (Emphasis added.)
As indicated, 30 C.F.R. § 221.49 is incorporated by reference into the Elk Basin unit agreement, and that regulation provides, in pertinent part, as follows:
§ 221.49. Royalty rates on oil; sliding- and step-scale leases (public land only).
Sliding- and step-scale royalties are based on the average daily production per well. The supervisor shall specify which wells on a leasehold are commercially productive, including in that category all wells, whether produced or not, for which the annual value of permissible production would be greater than the estimated reasonable annual lifting cost, but only wells, which yield a commercial volume of production during at least part of the month shall be considered in ascertaining the average daily production per well. The average daily production per well for a lease is computed on the basis of a 28-, 29-, 30-, or 31-day month (as the case may be), the number of wells on the leasehold counted as producing and the gross production from the leasehold. (Tables for computing royalty on the sliding-scale and on the step-scale basis may be obtained upon application to the supervisor.) The supervisor will determine which commercially productive wells shall be considered each month as producing wells for the purpose of computing royalty in accordance with the following rules, and in his discretion may count as producing any commercially productive well shut-in for conservation purposes:
(b) Wells approved by the supervisor as input wells shall be counted as producing wells for the entire month if so used 15 days or more during the month and shall be disregarded if so used less than 15 days during the month. (Emphasis added.)
Both section 13 and the regulation authorize approved water injection wells used for repressuring to be counted as if they were producing wells for the purpose of determining the average daily production per well. It is agreed that all the water injection wells with which we are here concerned in both the Oregon and Elk basins, whether located within or without the participating areas, were approved by the Supervisor of the United States Geological Survey, and that all of these water injection wells have in fact contributed to an appreciable increase in production from the oil producing wells located within the respective participating areas. The narrow issue is whether under the unit agreement, and whether under the regulation, water injection wells located off the participating area may be counted in determining the average daily production per well. Marathon argues that under the agreement and the regulation such wells may be counted, and the Secretary says they may not. Therein lies the area of dispute.
In our view the critical language in section 13 of the Oregon Basin unit agreement is: “[A]ll wells of any character actually used for repressuring or recycling, shall be counted as producing oil wells.” It is at once apparent that the quoted language does not contain within itself any requirement that in order to be counted as a producing oil well the water injection well must be located within the participating area. The only stated requirement is that the well be actually used for repressuring.
*985[L2] The Secretary points out that preceding the language quoted in the paragraph immediately above, there is a provision that oil wells shut in for conservation purposes “in each participating area” shall be counted as oil producing wells. From this the Secretary argues that because of the absence of a comma, the same limitation, i. e., “in each participating area,” should carry over to the subsequent language concerning the counting of water injection wells. With this line of reasoning we do not agree. As has been noted, punctuation is “a most fallible standard by which to interpret a writing.” Lessee of Ewing v. Burnet, 11 Pet. 41, 36 U.S. 39, 54, 9 L.Ed. 624 (1837); Holmes v. Phenix Insur. Go., 98 F. 240 (8th Cir. 1899); and Hol-Gar Mfg. Corp. v. United States, 351 F.2d 972, 169 Ct.Cl. 384 (1965). This Court has said that it will not “resort to grammatical niceties or the technicalities of punctuation” unless they make clear what is otherwise obscure; “[w]e are primarily interested in giving effect to the intention of the parties, and not to the technical verbiage used to express it.” Hughes v. Samedan Oil Corp., 166 F.2d 871, 873 (10th Cir. 1948). The Secretary’s reading of the provision would put repressuring wells in the same category as “oil wells shut in for conservation purposes.” We agree with the trial court that this is illogical.
In sum, the Oregon Basin unit agreement provides that: “[A]ll wells of any character actually used for repressuring or recycling, shall be counted as producing wells.” Such language is clear and unequivocal. It means that wells actually used for repressuring shall be counted as oil producing wells. It is not a function of the courts to add a further limitation that such wells, in addition to being actually used for repressuring, must also be within the participating area. It is enough if the well is actually used for repressuring, and it is agreed that such is true in the instant case.
Our reading of the regulation involved in the Elk Basin case parallels our reading of the unit agreement in the Oregon Basin case. 30 C.F.R. § 221.49(b) provides that water injection wells approved by the supervisor as input wells shall be counted as producing wells for the entire month if so used for 15 days or more during the month and shall be disregarded if so used less than 15 days during the month. This section of the regulation, then, authorizes water injection wells, if approved by the supervisor and if used the requisite number of days, to be counted as oil producing wells. Such authorization contains no limitation or requirement that the water injection wells be located within the participating area, and it is not for us to add such limiting language.
The Secretary points out that there is language in the introductory paragraph which refers to “wells on the leasehold” (which is the equivalent of wells on the participating area), and suggests that such language should be carried over into subsection (b). We do not agree. It is significant to us that the restrictive language “on the leasehold” appearing in the introductory paragraph does not appear in subsection (b). In other words, the omission is itself noteworthy. “[Wjhere a term is carefully employed in one place and excluded in another, it should not be implied where excluded.” Diamond Roofing Co. v. Occupational Safety & Health Review Comm’n, 528 F.2d 645, 648 (5th Cir. 1976). The use of the term “on the leasehold” in the introductory paragraph and its absence in subparagraph (b) have a logical explanation. The introductory paragraph deals with producing wells, which necessarily are within the participating area. Subparagraph (b) deals with a different kind of well entirely. Giving subsection (b) its plain meaning, water injection wells approved by the supervisor as input wells shall be counted if so used 15 or more days during the month, and we decline to hold that there is a further and unexpressed limitation that such wells be located within the participating area.
We recognize that the interpretation given by the Secretary to one of his own regulations is entitled to judicial deference. Udall v. Tallman, 380 U.S. 1, 85 S.Ct. 792, 13 L.Ed.2d 616 (1965); United States v. Southwest Potash Corp., 352 F.2d 113 (10th *986Cir. 1965), cert. denied, 383 U.S. 911, 86 S.Ct. 896, 15 L.Ed.2d 666 (1966). But a court need not defer to an administrative construction where there are compelling indications that it is wrong. R. V. McGinnis Theatres & Pay T. V., Inc. v. Video Independent Theatres, Inc., 386 F.2d 592, 594 (10th Cir. 1967), cert. denied, 390 U.S. 1014, 88 S.Ct. 1265, 20 L.Ed.2d 163 (1968). Courts need not “stand aside and rubber-stamp their affirmance of administrative decisions that they deem inconsistent with a statutory mandate or that frustrate the congressional policy underlying a statute.” Volkswagenwerk Aktiengesellschaft v. Federal Maritime Comm’n, 390 U.S. 261, 88 S.Ct. 929,19 L.Ed.2d 1090 (1968). Thus, when an agency interpretation is at odds with the clear and understandable language of a regulation, the latter must control and be given effect.
As indicated at the outset, we agree with the result reached by the trial judge in this matter, and generally subscribe to his reasoning. The interpretation given the unit agreement and the regulation by the trial court is consistent with the purpose of the repressuring concept. The Secretary’s construction is not. The use of water injection wells is a conservation measure designed to get maximum production from the oil producing wells in a given participating area. Both parties agree that water injection wells are permitted to be counted as oil producing wells, in determining the average daily production per well, in order to encourage lessees to drill as many injection wells as will efficiently contribute to increased production. Both also agree that the injection wells in these basins are located at points which result in the maximum and most efficient recovery. There is no logical reason for encouraging input wells at certain locations, but not encouraging them at other locations which would result in the most efficient production. In other words, it seems illogical to count a water injection well located a few feet within the boundary of a participating area, but not to count another water injection well located a few feet outside the boundary of the particular participating area, when both wells admittedly serve the same purpose, namely, to increase production from the oil producing wells located in the participating area. And our reading of both the regulation and the unit agreement does not require such incongruous result.
Additionally, we would note that the interpretation given the Oregon Basin unit agreement by the trial court squares with the conduct of the parties from 1961 to 1969. Similarly, the interpretation given to the regulation involved in the Elk Basin case by the trial court squares with the conduct of the parties from 1967 to 1970.
Judgment affirmed.